In the budgeting of all major development projects, there is always a desire to capture the financial and operational opportunities of all new and existing technologies; however, this can be difficult if not proven to be viable in advance of the development campaign commencing. This leads to great difficulty in fully capturing potential savings in future financial planning. In a cost-sensitive market, a leading East Africa exploration and production operator recognized an opportunity to trial new technologies in the exploration and appraisal campaign phase in order to reduce well cost and risk, which could be directly translated to the development campaign feasibility model. A flat-time analysis was performed on historical data to benchmark the connection performance against relevant proxies. From this analysis, it was determined that there was room for improvement from both technology and existing practices. To improve the connection time on a technology basis, offset field resistivity data were modelled to determine the feasibility of the formations drilled to efficiently propagate a bi-directional electromagnetic signal. Once the modelled feasibility was deemed acceptable to deploy from a risk perspective, a systematic field-trial plan was developed to deliver proof of concept, which was followed by the second element, running the system to reduce connection time. After two successful proof-of-concept runs, the electromagnetic system facilitated a material reduction in connection time, which could then be applied to the development project economics. Whilst primarily focusing on technology-oriented connection improvements, there was also a systematic performance improvement from the human element on the rig floor owing to the performance initiative. The secondary benefit of successfully implementing the electromagnetic telemetry system was the increased data rate and the ability to transmit annular pressure data while the pumps were off, which provides valuable data to understand wellbore hydraulic behavior during pumps-off events. With conventional mud-pulse telemetry systems, the critical path is impeded to obtain these measurements, where annular pressure data is streamed to surface after the surface event (e.g., LOT / FIT, connection ballooning check, etc.). During these field trials, the downhole equipment complexity run in conjunction with the electromagnetic telemetry transitioned from basic gamma ray and pressure measurements to a quad-combo LWD string run in conjunction with a rotary steerable system.

Increases in high pressure, high temperature (HPHT) drilling campaigns on the continental shelf of Norway and the UK have increased demands for next-generation technology that can deliver borehole measurements, enabling the wells to be drilled and reducing the operator's risk and operational expense. These deep gas development and exploration wells require a dramatic departure from conventional operating envelopes, including pressure, temperature, hydraulics, and formation evaluation capability. This paper discusses unique borehole integrity and formation evaluation challenges in two North Sea HPHT wells. It demonstrates how innovative new technology, coupled with fast-track component design modifications to meet specific operational challenges, enabled the safe, cost-effective drilling of these wells. The development of telemetry, gamma ray, pressure-while-drilling (PWD), vibration, and induction resistivity technology that is rated to operate at 200°C / 25,000 psi followed a stringent life cycle process. In this process, the field trial phase of the technology development included a rapid phase of trial runs, followed by engineering improvements. This iterative process helped to ensure that the technology was fit-for-purpose when it reached the commercialization phase. The step change in the thermal tolerance of the downhole electronics was accomplished through significant changes in design simplification, thermal screening, ceramic encapsulation, and thermal dissipation modeling relative to existing high-temperature electronics rated to 175 °C.

In a cost-sensitive market driven by depressed commodity prices, significant capital challenges exist for operators interested in pursuing exploration activities in remote environments to define their producible reserves. This paper explores the organizational and operational model developed by a service company over several remote area mobilizations; this model resulted in an optimized low-cost service delivery model characterized by top quartile operational key performance indicators (KPIs). The model centralizes critical functions of an operational organization into discrete service units that are located near the operational location or that provide remote assistance with communication and reporting lines in place to function effectively. Top quartile operational performance and tool availability is a result of placing a remote repair and maintenance facility that includes containerized specialty modules near the operational area. The upfront bottomhole assembly engineering, 24/7 monitoring, and proactive feedback of logged data, drillstring dynamics, and wellbore hydraulics are performed by a core team of subject matter experts in their respective disciplines from an established centralized operating center. The operational KPIs over the course of the six well exploration campaign provided substantial evidence to support the reliability of the model and the high level of experience used in both the remote maintenance facility and the operations center support team.

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