This fundamental course begins with an introduction to the DwC industry, key benefits of the technology, and the primary DwC systems employed by various operators. This is followed by selection of equipment for setting up a competent DwC system comprising of surface casing drive and handling equipment and downhole components. Various engineering calculations will also be discussed. At the end of the course students will be given an assessment test. You will gain an understanding of the well selection, economics, pre-job engineering, equipment selection, and preparation needed to ensure the successful execution of a casing while drilling project.
Casing drilling is a method by which the well is drilled and cased simultaneously. The small annulus from casing drilling can create a controllable dynamic equivalent circulating density (ECD). Casing-drilling technology enables obtaining the same ECD as with conventional drilling but with a lower (optimized) flow rate and lower rheological properties and mud weight. Frictional pressure loss during casing drilling was evaluated with computational fluid dynamics (CFD). Having accurate models for ECD, including the effects of pipe rotation and eccentricity in the annulus, is essential for success in these challenging jobs.
Before many of the new chemical and nanoparticle technologies for wellbore strengthening arrived to the marketplace, casing while drilling (CWD) was used for more than a decade to mechanically achieve the same end. Weatherford International and other service companies have developed multiple technologies for CWD, as well as the similar method of liner drilling (LD). With CWD, the casing is the drillstring, and with LD, the liner is the drillstring. CWD and LD technologies are building up a track record as operators encounter more difficult-to-drill frontier fields. Weatherford said it was contracted by a North Sea operator to use its LD technology in a field where three previous attempts resulted in two sidetracks and well suspension.
This paper will demonstrate the benefit of liner-drilling technology used to drill and cement an operator's 9⅝- and 7-in. Before the introduction of drilling-with-liner (DWL) technology, two previous wells drilled in the Carpa field encountered massive lost circulation and hole instability while drilling into the El Abra limestone, resulting in a total of 55 days of nonproductive time (NPT) for the two wells. Nine fields have been developed in the offshore Faja de Oro area of the Gulf of Mexico (Figure 1). They are the Arrecife Medio, Isla de Lobos, Tiburon, Bagre, Atun, Morsa, Escualo, Marsopa, and Carpa fields, and to date the estimated cumulative production is some 210 million BOE of light crude ranging from 30 to 40 API from the El Abra Middle Cretaceous limestone.
The secure placement of tools and accessories along well construction and completion strings is essential to executing downhole applications. In wellbore cementing, for example, job success depends on efficient mud removal and cement displacement around the tubular. Both of these objectives may be compromised if channeling occurs, where the cement does not spread evenly in all directions. Prevention of channeling depends on designing the right cementing program, which includes achieving the optimal standoff between the string being cemented and the open hole. Selecting the right centralizers and planning their location along the string are critical to achieving standoff.
For oil and gas operators today, remaining competitive means drilling longer laterals with less downtime, while creating the best possible balance of cost efficiencies. Casing flotation devices can help operators achieve these goals as they are engineered to reduce costs and increase efficiencies by ensuring casing reaches the bottom. In the Appalachian Basin, Northeast Natural Energy (NNE) was challenged to land 17,000 feet of casing in a horizontal gas well with a 9,000-foot lateral while maximizing operational and cost efficiencies. Running casing to depth in long lateral sections is complex due to excessive drag forces. While conventional casing flotation can reduce drag by creating an air chamber above the float collar that reduces sliding friction by approximately 50 percent, they shatter in large pieces.
Conventional drilling through lower intermediate intervals in the southern portion of the Alpine field on Alaska's North Slope has posed significant challenges. While unstable shale sections can be drilled without significant issues, hole collapse has caused difficulties while tripping out of hole and running casings. In 2011, a new steerable-drilling-liner system was deployed in the field. This paper provides insights into the new technology and the field-trial program. The Alpine field, which came online in 2000, lies near the environmentally sensitive shoreline of the Arctic Ocean on the North Slope of Alaska (Figure 1 above).
Centeno, Manuel (Schlumberger) | Krikor, Ara (Schlumberger) | Herrera, Delimar Cristobal (Schlumberger) | Sanderson, Martin (Schlumberger) | Carasco, Anant (Schlumberger) | Dundin, Alexander (Schlumberger) | Salaheldin, Ahmed (Schlumberger) | Jokhi, Ayomarz (Schlumberger) | Ibrahim, Sameh (Schlumberger) | Wehaidah, Talal (Kuwait Oil Company)
The complexity of drilling highly deviated wells in Kuwait drives the need for step changing in the well construction mindset, where severe to complete loss of circulation in Shuaiba formation significantly deteriorate the shale layers in Wara and Burgan formations leading to uncontrolled wellbore stability events. Casing while drilling (CWD) and two-stage cementing with a light density cement slurry were introduced as a technology system to drill the highly deviated complex wells through unstable and highly fractured formations. Fit for purpose engineering processes, advanced software solutions, a tailored bit and a bottom hole assembly dynamically simulated for drilling stability and directional tendency behavior were designed. A special light density cement slurry with high compressive strength was also designed to tackle the lost circulation issues when cementing the casing string. The paper will describe how the technologies can work as one system to solve complicated wellbore problems and address the problematic challenges of drilling unstable shales and fractured formations in the same section of the wellbore. This strategy enabled a significant time saving compared to drilling the section conventionally, removing Non-Productive Time (NPT) resulting from additional trips, cement plugs, stuck pipe, and subsequent sidetracks.
Hegab, D. (BP) | Kholy, S. El (BP) | Banger, T. (Weatherford) | Hoelterling, C. (Weatherford) | Shenoufy, O. El (Weatherford) | Boers, R. (Maersk) | Wakeel, W. El (BP) | Mobarak, H. (BP) | Courtney, B. (BP) | Muhiuldin, G. (BP)
One of the most serious red-zone hazards on a rig's drill floor is in casing running operations. Manually operated power tong hanging on a rig floor tugger required up to six people to be present in the red zone of the drill floor. In this respect, it was decided to evaluate the latest technological solutions, and work on an improved solution to casing running operations. The challenge on the Maersk Discoverer is main well center roughneck design, which has historically prevented the team from using an existing mechanized solution from the market. The Casing Running mechanization project was piloted on the Maersk Discoverer rig, in order to mechanize the casing and tubing running operations. Weatherford has specifically designed a bespoke adaptor that fits the CMR roughneck on main well center allowing for a remotely operated casing running operation. The adopted design overcome the challenge of tight space between the tong and the well center which prevented a mechanized solution before. Weatherford casing and tubing tongs are remotely operated through Weatherford's Mechanized control system. This Pilot approach has been installed and tried with multiple casing and tubing sizes. The Project brought remarkable results impacting the safety and the performance of our operations through two outcomes. Zero people in the red zone on one hand and on the other hand, improving efficiency of handling the tongs in a controlled manner avoiding excessive and uncontrolled movement of these heavy loads. Consequently, hands free casing running operations were successfully implemented.
Grymalyuk, Sergiy (Baker Hughes a GE Company) | Regener, Thorsten (Baker Hughes a GE Company) | Mensch, Robert (Baker Hughes a GE Company) | Canizares, Paul E (Baker Hughes a GE Company) | Miller, Troy (Baker Hughes a GE Company) | Hobbs, Greg (ConocoPhillips) | Marushack, Andy (ConocoPhillips) | Njoku, Johnson (ConocoPhillips) | Alvord, Chip (ConocoPhillips) | Robinson, Shon (ConocoPhillips)
This paper presents and discusses the results of the first six field deployments of a newly enhanced 7-in. steerable drilling liner system in Alaska's Greater Mooses Tooth (GMT) project. The system was operated with a managed pressure drilling service and drilled three-dimensional directional objectives while casing an 8¾-in. hole section through a highly unstable overburden section to the top of the reservoir section. The shales of the overburden section were chaotically disturbed by a prehistoric landslide that left large sections in unknown orientations from the original bedding planes. These sections have subsequently proven mechanically unstable when drilled at high angles. Exploration wells in the area determined that conventional drilling and casing methods would not allow successful completion of development wells. To succeed, the GMT project needed systems that would guarantee reservoir access and well mechanical integrity. The operator elected to deploy the newest version of the steerable drilling liner system because its design indicated a higher performance potential with more fail-safe options to manage the risks presented by this interval.
The new system uses a 4¾-in. pilot bottomhole assembly (BHA) and an expandable underreamer capable of opening the pilot hole from 6-in. to 8¾-in. for the 7-in. liner that is run in parallel with the drillpipe. The underreamer blade design was customized for the application to minimize drilling dysfunctions and optimize penetration rates. Special operating procedures were applied to deploy managed pressure drilling, surveying with a measurement while drilling (MWD) tool below a motor, and drilling with up to three cutting structures engaged at the same time. A new liner cementing concept was developed and proven to enhance reliability and provide flexibility for various contingency options.
The high-risk overburden sections were simultaneously directionally drilled and evaluated with logging while drilling (LWD) measurements while they were secured with the liner to the top of the pay section below. In the first two wells, the planned 18-day deployment was completed in nine days. The duration for the drilling part of the operation planned for 10 days was completed, on average, within 2.5 days without any tool failures or high dynamic dysfunctions while averaging a rate of penetration (ROP) of 35 to 45 ft/hr. Acceptable cementation of the liners was achieved on both wells with bond results comparable to conventional cementing in the section.
This paper summarizes and describes the results and system features in detail, and demonstrates how they can help operators reducing operational risks and saving cost.