Hole enlargement while drilling (HEWD) is an important technique in both deepwater and onshore drilling. Drilling interbedded formations is a difficult HEWD application. Two extreme cases can occur. One case is when the reamer drills in soft formation while the bit is in a harder formation. The other more difficult situation is when the reamer is in a hard formation while the bit drills ahead in soft formation. The latter creates an enormous challenge for the reamer to drill the harder formation without inducing large lateral and torsional vibrations which is detrimental to the reamer and other BHA components. An overall HEWD operating parameter management approach can greatly reduce probabilities of tool damage and unnecessary tripping while dramatically reducing drilling costs. A state-of-the-art BHA dynamic analysis program that allows modeling the reamer and bit in different formations plays a vital role in the overall HEWD management process. Before any planned HEWD operation, various possible operating scenarios can be virtually simulated through the BHA dynamic analysis program to evaluate the effect on BHA components of lateral and torsional vibrations. An optimized BHA configuration can be specified through these analyses and a set of optimal operating parameters for the chosen BHA can be developed. This paper presents an excellent case study of HEWD through severely depleted interbedded formations in the Gulf of Mexico. Previous offset wells had required multiple runs to HEWD this section due to reamer cutting structure damage. Models were constructed to compare performance with a range of BHA, WOB/WOR and RPM combinations. A set of optimal operating parameters and a road map were established for managing these parameters on the rig. Most importantly, the analyses recommended operating conditions that were substantially different from the accepted HEWD operation of increasing weight on bit (WOB) in harder formations. The analyses indicate that overall BHA performance was dramatically affected by weight on reamer (WOR). With a small sacrifice of ROP in the harder, more abrasive formations the HEWD system can effectively drill through the entire section without tripping due to component failure. This approach achieved excellent overall cost effective performance saving the operator $1.89 million on an offset well. Introduction The operator announced its field discovery in the Gulf of Mexico's Mars Basin in September, 2002. It is in 3,000ft of water, and is located approximately 88 miles southeast of Port Fourchon, Louisiana (Figure 1). During recent field development, the operator experienced problems with a BHA component. Specifically, the reamer 1,2 was suffering cutting structure damage driving up field development costs and slowing time to production. This paper will present the application challenges and resulting tool issues in addition to the problem analysis and engineering design changes to the reamer and operating parameters intended to solve the problem(s). Finally, the authors will present the results of applying the new technologies and operating parameters on the WELL #3 and how they saved the operator $1.89 million compared to costs incurred drilling the offset WELL #2.
fax 01-972-952-9435. AbstractThe success of deepwater exploration and development operations is greatly dependent on utilizing larger OD casing to reach the ever-increasing depths of today's prospects. Recently in the Mississippi Canyon region of the U.S. Gulf of Mexico's deepwater arena, a leading exploration company utilized new hole enlargement technology to simultaneously drill and enlarge a wellbore to facilitate the installation of a multiple string casing program.A case study is detailed to illustrate how proper planning and the utilization of new hole enlargement technology matched with a rotary steerable system, culminated in the successful execution of this critical well construction operation. As part of the planning process, hydraulics analyses and BHA stabilization optimizations using special computer software are discussed. The application of a new design concentric reamer in a deepwater tight clearance casing program that enlarged more than 18,000 ft of four differentsized wellbore intervals will be presented.
ConocoPhillips pre-drilled wells for the Magnolia tension leg platform (TLP) development in 2003 using a dynamically positioned semi-submersible drilling vessel1. The Magnolia field is located in 4,674 ft of water at Garden Banks (GB) block 783 in the Gulf of Mexico. During the pre-drilling phase, two wells were successfully sidetracked out of 13.625 in. casing in one trip using an extended gage, one trip whipstock system. The first whipstock operation was through cemented pipe and the second was through uncemented pipe, which had communication to a shallower, weak formation. This paper focuses on whipstock operations through uncemented pipe and describes the planning and execution of the first successful attempt at setting a whipstock, milling the window, squeeze cementing the window, and drilling out cement and rathole - all on one trip while using synthetic base mud (SBM). Due to the high spread rate cost of deepwater drilling, every effort is made to reduce critical path time while managing risk and safety. Typical whipstock operations through uncemented casing can require three or more round trips to prepare a window for drilling ahead. On the GB 783 A-4 BP1 well, window milling/cementing operations through uncemented casing were conducted in a single trip. The whipstock was oriented and set at 11,080 ft measured depth (MD) in a 54° angle hole. The window was milled, the assembly pulled above the window, and the openhole squeeze cemented. After waiting on cement to set, the cement was drilled out and a successful formation test achieved. An additional 130 ft of rathole was then drilled with the mills to place the stabilizers on the next drilling assembly below the whipstock. Operations from the start of running the whipstock until the mills were laid down took 2.6 days. A total of 1,861 lbm of metal shavings was safely recovered. This paper highlights 1) whipstock installation and window cutting operations, 2) safety and operational best practices for removing, handling, and monitoring metal cuttings that, if not removed from the hole, can be problematic for subsea blowout preventer (BOP) systems, 3) equipment modification made to mitigate risk for cementing through a milling assembly, and 4) design considerations for achieving a successful squeeze. Introduction The Magnolia TLP development wells were drilled from a dynamically positioned semi-submersible rig, which required using a subsea BOP stack and subsea wellhead equipment. The typical casing program for the wells was 36 in. × 20 in. × 13.625 in. casing strings run to the mudline. The 13.625 in. casing weighs 88.2 lbm/ft and is HCQ-125 grade pipe. A 10.75 in. drilling liner is run to obtain high enough fracture gradient to drill to total depth (TD). An 8.062 in. production liner was then run and hung off in the 10.75 in. drilling liner that also functions as production casing. Both the 10.75 in. drilling liner and the 8.062 in. production liner for the GB 783 A4 well stuck off bottom while being run. Numerous attempts to fish the 8.062 in. liner out of the hole were unsuccessful. In order to have 8.062 in. casing set across the producing zone of the original geologic targets, it was necessary to set a whipstock above the 10.75 in. liner and sidetrack the well. The 13.625 in. casing in the area above the 10.75 in. drilling liner was uncemented in order to prevent potential annular collapse issues. One of the previous wells in the pre-drill program, GB 783 A2 ST3, had sidetracked out of 13.625 in. casing by setting a whipstock. The whipstock was set across a length of casing that had cement in the casing by openhole annulus. A number of "Lessons Learned" were obtained during whipstock operations on the A2 ST3 well. These lessons learned and others from previous deepwater whipstock operations were used to help evaluate the risk and optimize the procedures on the A-4 well.
fax 01-972-952-9435. AbstractThe success of deepwater exploration and development operations is greatly dependent on utilizing larger OD casing to reach the ever-increasing depths of today's prospects. Recently in the Mississippi Canyon region of the U.S. Gulf of Mexico's deepwater arena, a leading exploration company utilized new hole enlargement technology to simultaneously drill and enlarge a wellbore to facilitate the installation of a multiple string casing program.A case study is detailed to illustrate how proper planning and the utilization of new hole enlargement technology matched with a rotary steerable system, culminated in the successful execution of this critical well construction operation. As part of the planning process, hydraulics analyses and BHA stabilization optimizations using special computer software are discussed. The application of a new design concentric reamer in a deepwater tight clearance casing program that enlarged more than 18,000 ft of four differentsized wellbore intervals will be presented.
fax 01-972-952-9435. AbstractConocoPhillips pre-drilled wells for the Magnolia tension leg platform (TLP) development in 2003 using a dynamically positioned semi-submersible drilling vessel 1 . The Magnolia field is located in 4,674 ft of water at Garden Banks (GB) block 783 in the Gulf of Mexico. During the pre-drilling phase, two wells were successfully sidetracked out of 13.625 in. casing in one trip using an extended gage, one trip whipstock system.The first whipstock operation was through cemented pipe and the second was through uncemented pipe, which had communication to a shallower, weak formation. This paper focuses on whipstock operations through uncemented pipe and describes the planning and execution of the first successful attempt at setting a whipstock, milling the window, squeeze cementing the window, and drilling out cement and ratholeall on one trip while using synthetic base mud (SBM).Due to the high spread rate cost of deepwater drilling, every effort is made to reduce critical path time while managing risk and safety. Typical whipstock operations through uncemented casing can require three or more round trips to prepare a window for drilling ahead. On the GB 783 A-4 BP1 well, window milling/cementing operations through uncemented casing were conducted in a single trip. The whipstock was oriented and set at 11,080 ft measured depth (MD) in a 54° angle hole. The window was milled, the assembly pulled above the window, and the openhole squeeze cemented. After waiting on cement to set, the cement was drilled out and a successful formation test achieved. An additional 130 ft of rathole was then drilled with the mills to place the stabilizers on the next drilling assembly below the whipstock. Operations from the start of running the whipstock until the mills were laid down took 2.6 days. A total of 1,861 lbm of metal shavings was safely recovered. This paper highlights 1) whipstock installation and window cutting operations, 2) safety and operational best practices for removing, handling, and monitoring metal cuttings that, if not removed from the hole, can be problematic for subsea blowout preventer (BOP) systems, 3) equipment modification made to mitigate risk for cementing through a milling assembly, and 4) design considerations for achieving a successful squeeze.
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