Drilling High-Angle Casing Directionally Drilled Wells With Fit-for-Purpose String Sizes
Abstract: TX 75083-3836, U.S.A., fax 1.972.952.9435. AbstractThis paper discusses the design and testing of 10 ¾-in. and 7 5/8-in. casing directional drilling equipment and procedures that ConocoPhillips plans to use on a mature North Sea asset. ConocoPhillips has worked with Tesco Corp. and Schlumberger in building the tools necessary to complete this task. These include: downhole casing drilling tools, underreamers, positive displacement motors, MWD tools, rotary steerable systems (RSS), and high capacity winches for … Show more
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Remote Arctic onshore exploration can be very costly, frequently exceeding the cost of a deepwater Gulf of Mexico well. This paper reviews the reasons for these high costs and a possible combination of new proven technologies and rig designs to significantly reduce these costs Logistics, mobilization, demobilization and a limited drilling season are factors that combine to cause high costs. Operation time requirements and the short drilling season normally results in a rig drilling one well per season. A significant reduction in exploration final hole size is the primary driver in reducing costs as this leads to a major reduction in rig size. Downsizing does not limit well evaluation due to recent developments in downsizing evaluation equipment. The majority of the required information can be obtained with this finder well or "scratch and sniff" approach. This downsizing allows the use of an innovative rig design; hybrid coil tubing drilling unit; that has significantly reduced mobilization and demobilization times. The reduction in drilling and mobilization/demobilization time can result in one rig drilling multiple wells in the drilling season. Combining new technologies, such as casing drilling and coil tubing drilling, reduces drilling time and allows the hybrid coil tubing rig to drill deeper. Casing drilling and coil tubing drilling are areas where ConocoPhillips is an industry leader. A significant reduction in exploration cost is predicted, estimated at 50%. Introduction ConocoPhillips (COP) has significant Arctic onshore exploration acreage in Alaska, Canada, and Russia (through a (jJoint vVenture with OOOLUKoil Naryanmarneftegaz with Lukoil). The majority of the exploration prospects are far from existing infrastructure, 50 to 200 miles. Most remote exploration, greater than 570 miles from infrastructure, has been done using snow roads. Building ice roads for longer distances is not cost or time effective. The rigs are transported using low ground pressure vehicles, such as sleds, bull dozersRolligons, RolligonsTM (a), QuadTracsTM (a)Quadtracs, sleds, etc. In some cases conventional transportation equipment can be used but this requires highly packed snow roads. This delays mobilization until the packed snow essentially turns to ice and can accept a higher bearing pressure. The well pads are typically ice, built using water from local lakes. When drilling is completed and the pad melts there is no damage to the tundra. In Russia, sand or gravel pads, are built even for exploration wells. The rigs used are typically rated to more than 20,000 feet with 5-inch drill pipe. The rig components can be broken down to 8 ½ feet wide by 8 ½ feet tall and 50 feet long, maximum weight less than 50,000 lbm. This results in approximately 100 loads for the rig and 50 loads of associated equipment. Rigs in the Russian Arctic have large component pieces and are moved by skidding them on sleds1. Erection of the rigsequipment requires using cranes. This workErection is subject to weather related delays, blowing snow and low temperatures that shutdown crane operation. Thirty 30 days is a reasonable estimate of the time required to mobilize this type of rig. Stacking rigs close to the exploration well site has been done previously to reduce mobilization time. This however has not been very successfully in decreasing mobilization and rig up time. Rig moves in the Russian Arctic can take over three (3) months. Although rig components are large all the primary and auxiliary piping, ducting, insulation, etc. are fabricated onsite. Arctic conditions at initial mobilization are typically no daylight and low temperatures. During the Alaska 2006 season the time period, late January to early February 2006, had a minimum temperaturee of -55°F and a maximum temperaturee of -15°F. The average temperature during this time period was -35°F. At temperatures below -35°F all crane operations are essentially shutdown as booms may experience brittle fracture.
Remote Arctic onshore exploration can be very costly, frequently exceeding the cost of a deepwater Gulf of Mexico well. This paper reviews the reasons for these high costs and a possible combination of new proven technologies and rig designs to significantly reduce these costs Logistics, mobilization, demobilization and a limited drilling season are factors that combine to cause high costs. Operation time requirements and the short drilling season normally results in a rig drilling one well per season. A significant reduction in exploration final hole size is the primary driver in reducing costs as this leads to a major reduction in rig size. Downsizing does not limit well evaluation due to recent developments in downsizing evaluation equipment. The majority of the required information can be obtained with this finder well or "scratch and sniff" approach. This downsizing allows the use of an innovative rig design; hybrid coil tubing drilling unit; that has significantly reduced mobilization and demobilization times. The reduction in drilling and mobilization/demobilization time can result in one rig drilling multiple wells in the drilling season. Combining new technologies, such as casing drilling and coil tubing drilling, reduces drilling time and allows the hybrid coil tubing rig to drill deeper. Casing drilling and coil tubing drilling are areas where ConocoPhillips is an industry leader. A significant reduction in exploration cost is predicted, estimated at 50%. Introduction ConocoPhillips (COP) has significant Arctic onshore exploration acreage in Alaska, Canada, and Russia (through a (jJoint vVenture with OOOLUKoil Naryanmarneftegaz with Lukoil). The majority of the exploration prospects are far from existing infrastructure, 50 to 200 miles. Most remote exploration, greater than 570 miles from infrastructure, has been done using snow roads. Building ice roads for longer distances is not cost or time effective. The rigs are transported using low ground pressure vehicles, such as sleds, bull dozersRolligons, RolligonsTM (a), QuadTracsTM (a)Quadtracs, sleds, etc. In some cases conventional transportation equipment can be used but this requires highly packed snow roads. This delays mobilization until the packed snow essentially turns to ice and can accept a higher bearing pressure. The well pads are typically ice, built using water from local lakes. When drilling is completed and the pad melts there is no damage to the tundra. In Russia, sand or gravel pads, are built even for exploration wells. The rigs used are typically rated to more than 20,000 feet with 5-inch drill pipe. The rig components can be broken down to 8 ½ feet wide by 8 ½ feet tall and 50 feet long, maximum weight less than 50,000 lbm. This results in approximately 100 loads for the rig and 50 loads of associated equipment. Rigs in the Russian Arctic have large component pieces and are moved by skidding them on sleds1. Erection of the rigsequipment requires using cranes. This workErection is subject to weather related delays, blowing snow and low temperatures that shutdown crane operation. Thirty 30 days is a reasonable estimate of the time required to mobilize this type of rig. Stacking rigs close to the exploration well site has been done previously to reduce mobilization time. This however has not been very successfully in decreasing mobilization and rig up time. Rig moves in the Russian Arctic can take over three (3) months. Although rig components are large all the primary and auxiliary piping, ducting, insulation, etc. are fabricated onsite. Arctic conditions at initial mobilization are typically no daylight and low temperatures. During the Alaska 2006 season the time period, late January to early February 2006, had a minimum temperaturee of -55°F and a maximum temperaturee of -15°F. The average temperature during this time period was -35°F. At temperatures below -35°F all crane operations are essentially shutdown as booms may experience brittle fracture.
Concurrent rotary-steerable directional drilling and hole enlargement utilizing concentric underreamers is becoming more commonplace. Significant cost savings can be obtained enlarging the hole while drilling with a rotary-steerable system (RSS) as opposed to using a designated hole-opener run after the pilot has been drilled. However, RSS underreamer assemblies are often challenged with BHA instability, excessive vibration and stick-slip problems when the two different cutting structures (bit and underreamer) interact with significantly different formations. This paper describes case histories of directional wells that have been drilled with both point-the-bit and push-the-bit RSS underreamer assemblies in the North Sea, Mediterranean Sea and Nile Delta (Egypt). In particular, RSS underreamer assemblies opening from 13" to as large as 17 ½", using 12 ¼" pilot holes will be discussed. A unique sensor system, integrated into this specific RSS provides measurements of near-bit borehole caliper, stick-slip and vibration. While drilling, borehole quality and downhole vibrations were monitored in real-time at the rig site and from a remote operating center. The real-time data was used to optimize drilling parameters and provide enhanced performance from the RSS underreamer assembly. The RSS solution to simultaneous wellbore enlargement has been analyzed in terms of vibration, efficiency, performance, directional objectives and cost. The physical components, operational aspects and limitations of RSS underreamer technology will be discussed. The combination of a specific RSS and underreamer with a balanced cutting structure has resulted in excellent ROP and directional control, while reducing reaming-related vibration and potential failures. Further, an automated directional drilling feature and real-time drilling process monitor have enabled optimum directional drilling performance. Introduction Hole enlargement while drilling using RSS and underreamers is becoming widely accepted on directional projects worldwide. Conventionally, steerable motors with bi-center bits were the only practical option for directional hole enlargement where casing pass-through was a restriction. Today, BHAs utilizing a combination of RSS and underreamers are commonly used on wells that require directional hole enlargement. Slim well casing programs, casing whipstocks or re-drilling around a fish all commonly use RSS underreamer technology. Common problems associated with bi-center bits are: poor directional control, inconsistent directional results in soft formations, low ROP, excessive vibration, and irregular and/or spiraled holes1–3. All these problems lead to the need for an alternative method of hole enlargement, with the ability to enlarge the hole beyond the size of existing casing. The RSS underreamer BHA has become the obvious solution to this problem.
First Retrievable Directional Casing While Drilling (DCwD) Application in Peruvian Fields Generates Time Reduction and Improves Drilling Performance Preventing Potential Non-Planned Downtime
Drilling Operations in Peruvian Jungle requires a complex logistical preparation similar to an offshore project. This high logistic cost that is necessary to drill in this area means a big investment and strongly impacts the daily drilling cost. To minimize potential non productive time (NPT), potential problems that were identified in offset wells (borehole instability, gumbo shales, stuck pipe, etc.), and to improve the drilling performance, Perenco Peru Limited decided to use Directional Casing while Drilling (DCwD) technology in their Block 67 campaign wells. Two wells (Piraña-4D and Dorado-2D) were drilled with this technology obtaining success and achieving the operator's targets. The objectives for the Casing Drilling operations on the Block 67 wells were: Prove feasibility of both vertical and directional casing drilling technologies Save time upon the whole section by simultaneously Drilling and casing-off problematic formations Demonstrate efficiency of the technology to reduce risks associated with conventional drilling that could easily result in losing the well and further unplanned sidetracks Prove adaptability of the technology to different well conditions (mainly variance on well trajectory) Evaluate the economical viability of the technique (cost & time savings) This paper describes these experiences in terms of planning, preparation, execution and evaluation of results including the lessons learnt generated during the process.
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