Directional/complex wells

Technologies and Practices Push ERD Safe Operating Envelope, Reap Savings Offshore

The complete paper describes an offshore artificial island project northwest of Abu Dhabi in which drilling limits were extended continually by adopting new technologies and practices in an extended-reach-drilling (ERD) campaign.


Optimizing resources and pushing drilling limits to tap into deeper reservoirs at minimal cost is a primary objective of operators worldwide. The complete paper describes an offshore artificial island project northwest of Abu Dhabi in which drilling limits were extended continually by adopting new technologies and practices in an extended-reach-drilling (ERD) campaign. The project drilled longer wells at lower cost. The approach has resulted in drilling and completion of wells comfortably within the equipment-rating envelope and is considered a benchmark for nearby fields in the region.

Field Background

The offshore field is northwest of Abu Dhabi. After successful drilling and evaluation of nine exploratory and appraisal wells using an elaborate data-gathering program, a detailed field-development plan was put forward for execution. Among cost-optimization opportunities identified and studied at the initial phase was the planned construction of two artificial islands for land operations to replace drilling with a conventional offshore rig spread. This reduced overall development cost significantly but increased the complexity of drilling and completion activities and elevated operational risks from collisions, high-departure ERD wells, downhole dysfunctions, weight transfer, equipment limitations, subsurface challenges, and landing completions in the reservoir. A comprehensive risk-mitigation plan was developed along with a strategy to address various constraints by the introduction of new technology and revamped operational practices.

The field-development plan involved drilling and completing 86 wells of various departures, ranging from low to very high, with customized completion designs based on the individual well placement within the target reservoir. The wells were designed to increase reservoir potential by maximizing reservoir contact. A total of 35 high-, 41 medium-, and 10 low-departure wells were planned. At the time of writing, 50 wells had been drilled and completed.

ERD Challenges and Tailored Solutions

The complete paper includes a list of drilling and completion considerations taken into account while planning for extended-reach wells on the artificial islands. It then discusses tailored solutions to manage the complexity and risks and optimize operations and cost. The four following optimization initiatives are discussed.

  • Changing a heavy casing design (HCD) to medium casing design (MCD), which entailed reducing casing policy. For HCD wells, the casing policy is 20-in. casing, 13⅜‑in. casing, 9⅝-in. casing, and 7-in. liner. Casing policy for MCD wells is 13⅜-in. casing, 9⅝-in. casing, and 7-in. liner. Combining two sections under one casing has helped reduce well durations in high-departure wells but has added risks. A robust mitigation and contingency matrix ensured optimization, resulting in savings of approximately $28.5 million across at least 11 wells over 5 years.
  • Eliminating separate liner top packer runs for all the wells and changing from nonintegral to integral hangers. After offsetting the conversion cost, forecasted savings were approximately $33 million over 5 years.
  • Running 9⅝-in. single-string casing instead of liner and tie back. This meant running up to 20,000 ft of 9⅝-in.×10¾‑in. casing in one run. Possible shallower casing points were offered as contingencies for limited margin of overpull available in case of stuck casing closer to total depth. This change also meant a long cement job and possible high equivalent circulating density (ECD) and losses in the weak zones behind the casing. A combination of conventional and high-strength, lightweight slurry was used for tail and lead slurries, and the ECDs were effectively managed. After drilling a few wells to understand the formation strength of weaker zones, applying this optimization initiative resulted savings of approximately $0.8 million per well and $48 million across the campaign.
  • A new completion-design strategy that called for a tubing-mounted packer with nippleless barrier plug to eliminate wireline intervention and enable packer setting at higher inclinations. This change saved 2 days per well. Additionally, all completion tubing was made up offline and racked back in the derrick, saving another 2 days per well.

Equipment Upgrades

During the initial planning stage, some of the well profiles were deemed aspirational because they were at or beyond the drilling envelope of the existing equipment. The complete paper includes a detailed discussion of a comprehensive approach encompassing equipment upgrades, technology introduction, and improvements in drilling and completion practices. A detailed road map was developed, and all proposed improvements were classified based on their potential savings and the difficulty of their application.

Well-Profile Optimization

Downhole conditions can subject the bottomhole assembly (BHA) to the harshest of drilling environments, especially in ERD. Complex 3D profiles in pad/slot drilling driven by anticollision concerns and seismic faults can significantly increase drilling difficulty (Fig. 1).

Fig. 1—3D plot of planned and drilled wells and the fault system in the field.


Several optimization runs were performed on the well profiles during the planning stage. Every iteration was aimed at reducing the difficulty in drilling these profiles. Known seismic faults were either avoided or drilled at low inclinations against competent formations. Additionally, geological targets in the reservoir were challenged for possible changes to drill incident-free wells.

Data-acquisition plans were optimized. Low-departure wells were placed strategically in the reservoir and used as pilot holes with multiple log runs. The reservoirs’ basic data-acquisition strategy included density-neutron logs that warranted running radioactive sources in the drilling BHA. Initially, the risk has been flagged as high, and a two-run approach was adopted. Later, after optimizing the well paths, both runs were combined with detailed risk assessments, mitigations, and contingencies in place.

Technologies and Implementation

The complete paper includes a listing and discussion of numerous technologies that have been implemented from the start of the island drilling campaign to reduce environmental exposure and improve safe working conditions, increase operational efficiency, and drive costs lower. The discussion includes specific challenges, how they were addressed with the technologies employed, and improvements and savings that resulted.

Real-time drilling monitoring with smart visualization, key-performance-indicator monitoring, and benchmarking substantially reduced the amount of nonproductive time and associated costs, and improved drilling efficiency and safety.

In-House-Developed Field-Specific Practices

An in-house-developed continuous improvement process included drilling the well on paper; prejob planning meetings; peer, section, and after-action reviews; and a dynamic, detailed, lessons-learned register and database accessible to both offshore and onshore stakeholders of the project. The process is iterative from planning through execution and evaluation. Every improvement is studied for health, safety, and environmental considerations and cost-effectiveness, and evaluated for its success to be graduated into the drilling program.

The complete paper lists initiatives, optimizations, opportunities, and operational improvements that have contributed either to pushing the drilling envelope or saving time and costs.


  • A combination of tailored engineered solutions, technology introduction, and implementation of field-specific best practices have pushed the ERD envelope and helped drill offshore artificial-island wells within existing constraints.
  • This field has set the example for nearby fields and ERD wells in the region.
  • Various initiatives, optimizations, and improvements have resulted in realized and forecasted combined savings of approximately $360 million for the entire campaign (Fig. 2).
Fig. 2—Distribution of contributors to total savings.


This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 197123, “Technologies and Practices to Push the Extended-Reach-Drilling Envelope Within Existing Constraints,” by Phalgun Paila, SPE, Baker Hughes; Rudra Pratap Singh, ADNOC; and Kashif Abid, SPE, Baker Hughes, prepared for the 2019 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11–14 November. The paper has not been peer reviewed.