The common limitation with a casing string is its inability to maintain hole inside diameter (ID) when run through an existing casing string already installed within the wellbore. This instigated development of expandable metal tubulars to maximize the open interval below existing casing, ensuring conventional wellbore designs can be maintained as well as managing unexpected drilling hazards. With the introduction of expandable tubulars, existing wells could now be completed through the ability to include an additional casing without increasing top-hole design or compromising on the planned completion size. Today’s industry demands further development in technology, with an ability to set a casing and run another casing string without the additional hole-size reduction experienced with conventional casing or standard expandables. A monobore solution is key to allowing operators increased control of the wellbore by isolating intervals, ensuring an efficient fluid-management system, and continuing with the existing tool assemblies. This requirement has led to the development of monobore expandable systems for intervals of the wellbore with common hole sizes of 12-1/4 in., 8-1/2 in., and 6-1/8 in. Whether in their liner or clad form, isolating the respective interval without a loss in hole diameter provides new economies to operators when accessing deep and more complex reservoirs. Wellbores can now be engineered with contingency solutions without compromising on well objectives. Their ability to isolate intervals while not compromising on post-expansion hole size is providing operators the ability to mitigate drilling hazards, slim tophole casing designs, or increase completion diameters with minimal operational impact on their existing well plans. To date, operators have actively incorporated monobore expandable solutions to mitigate drilling hazards in Norway, Oman, Turkey, Australia, Saudi Arabia, and Azerbaijan, allowing for hazards to be overcome and well objectives achieved. This paper details design and implementation of such monobore expandable systems while providing real results on a global scale of their implementation, advantages, and operational efficiencies.
Well cementing is a crucial component of deepwater well construction, and a key to cementing success is the performance of the cementing plug. Plug performance is primarily based on the mechanical wiping efficiency and wear resistance of the plug. However, limited understanding of the performance has hindered the establishment of standards. While API RP10F provides recommended testing practices to evaluate the performance of cementing float equipment, it does not include cementing plugs. This paper is the first published review of efforts to better understand cement plug performance and to establish industry standards. Through laboratory studies, it examines material loss in actual deepwater applications and evaluates the effect on wiping performance of cementing plugs. These studies provide the basis of a selection process for wear-resistant materials. The paper also examines methods of measuring wiping efficiency and overall plug performance. Based on these methods, a proposal is presented for establishing industry performance standards for setting cementing plugs. Cementing wiper plugs provide a physical barrier to cement contamination by separating displacement fluid and wiping residual mud film and other materials from the inside surface of the pipe. Separation and wiping efficiency are directly related to plug wear resistance and to the process of balancing design to achieve optimal stiffness and pressure containment. This design balance is achieved through rigorous material testing and design refinement. Analysis of wiper cuttings samples has provided a clear understanding of the plug's ability to provide a physical barrier to separate fluids and how that affects the function of downhole tools. This cuttings evaluation has provided information on material loss and positive fin interference. Results of the evaluation are corroborated by field performance achieved in cementing lengths of casing greater than 16,000 ft. Plug wear is of particular concern in long, high-volume, deepwater casing strings where it can lead to displacement errors and reliability problems for downhole pressure-actuated tools. These displacement errors are examined in field applications that precisely locate the plug at multiple points during the cementing process.
This paper provides insight on planning and equipment-selection processes to successfully ream and drill in 9 5/8-in. casing through a water-sensitive shale formation, followed by a two-stage cement job to isolate lost-circulation zones. Proper placement of cement all the way to surface would be essential for providing an additional annular barrier to prevent casing-to-casing annular gas migration. Selection of the equipment is dictated by the operation to be performed (i.e., drilling new hole versus reaming a tight section), the type of reamer or drill shoe used, selection of specialized drilling tools and centralizers, along with stage cementing tools with integral packing elements, among many other requirements. Current drilling with casing (DwC) applications allow for plastering cuttings to the wellbore wall, creating a barrier that minimizes fluid losses. It also reduces the annular clearance between the casing and the wellbore wall, thus improving velocity and hole cleaning compared to conventional drilling practice. And, by introducing a stage cementing tool with an integrated packer, the annular barrier can be set inside the previous casing string to facilitate two-stage cementing, thus enabling full circulation, with cement to surface. Currently, 23 wells have been completed using this approach. A few of these jobs stand out. In one case, the casing string was reamed 501-ft (153-m) for 7.75 hours at speeds between 20 and 25 rpm using an eccentric nose shoe with carbide cutting structure on the exterior. Following the first stage of cementing (with zero returns received at surface), the team inflated the packer element of the stage cementing tool and initiated the second stage of cementing. During a second bottoms-up circulation, returns at the surface indicated successful setting and a successful second-stage cementing job in a reamed hole. In another case, the string was reamed 316 ft over 3.75 hours with 20 RPM rotation, until the bottom of the conventionally drilled hole was reached. Using a specialized drilling shoe, the string was then drilled 301 ft over 14.75 hours with 20 to 50 RPM rotation to the desired depth. Based on the broad success of this technique, the service provider built a detailed database of field jobs. This database provides a better understanding of the parameters and recommendations for this application. These insights include how to improve standoff and minimize damage to the element while rotating by using rigid centralizers, implementation of shouldered connections to allow torque transmission without compromising thread integrity, recommended RPMs and torque based on internal and external components of the tool, among others. This well construction technique has saved hundreds of hours of rig time by enabling operators to drill with the two-stage cementer (with integral packer in the string) instead of having to continue drilling a problematic open hole with a conventional assembly and run casing afterwards. By performing successful two-stage cement jobs, the need to perform top cement jobs due to total losses is eliminated. And finally, the technique eliminates the need for conditioning the hole to allow casing placement at TD, an operation that would require an additional trip with a dedicated bottom hole assembly (BHA).
From the early beginnings, the idea of expanding solid tubulars as a means to reduce nonproductive drilling time by covering unstable formations and pressure events while minimizing the telescoping effect of standard casing programs was thought to be the panacea over conventional well-construction techniques. However, the development and commercialization of this technology has been driven by increased production opportunities realized by improved well architecture and completion size optimization. Solid expandable systems are now commonly used in development, planning, drilling, and completion, and during production decline.
Float equipment comes in a variety of configurations incorporating such devices as poppet float valves and flapper valves to prevent cement from re-entering the casing at the end of displacement. Autofill functionality can be achieved by using various methods of flow and ball de-activation to either increase trip speed or reduce surge pressure on the formation. Float equipment performance is now loosely defined by the recommended practices in API RP10F. With the pending introduction of newly proposed API 10F standards, the industry recognizes the need to better define the performance properties for flow endurance, temperature, and back pressure. However, this much needed and improved specification does not address drillability and plug bump ratings. This seemingly simple technology has highly engineered nuances that may not be readily apparent. The careful balance of flow endurance, high pressure resistance, and debris tolerance while maintaining quick drill-out properties has been achieved through many years of refinement and testing. Even the concrete used in the manufacture of float equipment is highly engineered to provide ultrahigh compressive strengths and shear bonding, which not only create a drillable product but also produce a seal between the steel hull and the valve. If these nuances are not clearly understood, the selection of high-performance, cost-effective float equipment can be compromised, which can lead to poor cement placement, remedial intervention, added drill-out costs, and reduced well integrity. Failure modes are often attributed to design flaws or manufacturing errors. In some cases this is accurate, but a detailed understanding of performance properties and accurate compressibility calculations can mean the difference between allowing sufficient flow back and recording a float failure. Pipe management and standardized cementing practices are also important to success. This paper will explore the design practices and manufacturing methods for various types of float equipment and the need to dovetail the newly proposed API 10F standards and future iterations into the selection criteria for cost effective, reliable float equipment. This discussion will also review reasons for float failures and the causes behind these incidents.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.