Effective primary cementing in the wellbore is critical to achieve positive wellbore isolation for the life of the well. This paper discusses an expandable liner hanger (ELH) system, which provides liner rotation during the liner deployment and the cementing operation while also providing a hydraulically energized liner-top seal on setting. The wells in this case study were drilled and 7″ liners installed using an expandable liner hanger system. This paper demonstrates the cementing result of the cemented liners in 30 wells during a 2 ½-year period. The wells consisted of two types of liner installations: liner jobs in which rotation was planned and achieved and liner jobs in which rotation was not planned due to equipment limitations (cementing results prompted a change to a high torque rotating liner system). The study evaluates the quality of cement bond with the effects of liner rotation, standoff, displacement rate, openhole inclination, openhole exposure time, and dogleg severity (DLS). In hostile well environments, the cementing of liners has always presented a challenge to conventional cementing liner operations. Well designs are inherently more complex because the targets are deeper, and the downhole conditions are uncertain. Highly deviated and extended reach well configurations require much more planning when developing the drilling and completion design. An ELH system has been developed to address the challenges in the conventional cementing liner operation, which can increase the probability of achieving overall operational success. The result of this study shows that rotating the liner during the cementing operation achieved better cement quality. The case histories of the wells using the expandable liner system verify the key consideration factors presented in this paper, which helps to improve the quality of liner cementing bond.

Casing wear caused by rotating drill strings can lead to reduced well life, failed or burst casing strings, and expensive non-productive time (NPT) for remedial actions. In Alaska's Alpine Development field, where logistics are challenging, regulations are strict, and the operational window is small, drilling increasingly long laterals has vastly increased the cost and risk of casing wear, necessitating effective mitigation. After detailed analyses of Alpine field wells, one operator successfully implemented a casing wear mitigation plan combining new tools, modeling techniques and analyses. The plan required strategic placement of Non-Rotating Protectors (NRPs) based on predicted casing wear, analyzed side forces, and lateral length. Additionally, the operations group wanted to simultaneously improve computer modeling for both casing wear and torque and drag (T&D) analysis. One major challenge was predicting appropriate wear factors for casing wear modeling. Operational challenges included how to deploy the plan in managed pressure drilling (MPD) operations, where preventing premature wear on rotating control device (RCD) sealing elements had to be considered. Implementing this casing wear mitigation plan allowed the operator to successfully drill extended reach multilateral wells to planned total depth while keeping wear below maximum allowable thresholds. The paper describes the challenges and approach to predict casing wear, as well as successful mitigation strategies and lessons learned from an extensive offset database. Included are comparisons to field results from casing logs, and several wells that deployed the casing wear mitigation plan, versus an offset well that was drilled without a plan. The paper describes new techniques for predicting and modeling casing wear which, in combination with utilization of specific tools, results in a readily-applicable approach to wear mitigation in extended-reach drilling (ERD).

As hydrocarbon basins mature, reservoir pressure depletion caused by hydrocarbon production leads to severe pore pressure/fracture gradient anomalies that can reduce an otherwise sufficient mud weight window significantly. At the same time, reentries involving slim-hole sidetracks incur high annular losses that further widen the gap between equivalent static and circulating densities - ESD and ECD. In this situation, it is not possible to drill using normal overbalanced methods. The risk of formation fracturing and fluid losses, fluid influxes, and wellbore collapse would far outweigh the reward of increased production. The effective variation of static and circulating densities must be minimized. A major project in the Gulf of Mexico posed such a problem. Managed pressure drilling (MPD) was adopted as the solution to manage a tight hydraulic window and effectively drill reservoirs which would have been extremely challenging using conventional drilling methods. Traditional directional drilling with a positive displacement motor would normally create more pressure balance complications under a MPD environment due to the continuous fluctuations to the ECD when the motor is in sliding or steering mode. This paper outlines how new generation rotary steerable systems coupled with the interpretation from a downhole real time pressure while drilling sensor was engineered to maximize drilling performance for a directionally drilled well in MPD environment. This paper will also discuss the case histories and lessons learned and thoroughly review the range of opportunities these technologies have created in the maturing areas of the Gulf of Mexico. Introduction Conventional drilling using either steerable systems or rotary steerable systems utilizes drilling fluids which are overbalanced to suspend the drilled cuttings, clean the hole and maintain wellbore stability. The drilling fluid as it is circulated down the hole also cools and provides energy to the bit required to break the rock and drill ahead but most importantly applies overbalance pressures which is a combination of hydrostatic pressure and annular friction pressure to prevent formation fluid influx into the formation. This is illustrated in Figure 1.

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.