In today's drilling environments and economics oil companies demand focus on all aspects of services delivered by the oil field service companies. Safety and efficiency are paramount with cost considerations following closely behind. Reductions of non-productive time are continuously monitored to evaluate service delivery excellence. All economics are impacted by dead or non productive time associated with failed or damaged equipment, logistical complexities, unplanned events (i.e., weather storms), complex reservoirs and drilling trajectories.A costly yet extremely critical service for the oil companies is the capture of representative fluid samples from the reservoirs they are drilling. This is done today with formation sampling wireline tools (FSWL) lowered into the wellbore days after the drilling of the formation. The timeliness of this information as well as the additional rig costs associated with the capture of this information can be several days or more in additional time for the sampling operation. In many cases, such as in high angled or horizontal wells, the drill pipe is required to convey the wireline to the formations. In these instances the tools cannot be gravity conveyed, which adds cost and additional risk. Because formation sampling while drilling (FSWD) technology has recently been introduced, significant cost savings are possible because the testing and sampling can be performed during the drilling process. It is the objective of this paper to demonstrate an economic model using field examples to evaluate the cost benefit between using FSWL and FSWD fluid sampling operations acquired in deep water fields. Factors considered are the operating costs for FSWL and FSWD, the probability for fishing, reduction in pumping times associated with lower invasion for FSWD and reducing the operational time in high angel wells and the ability to make changes in well construction.

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.

GeoTap®, a new formation testing while drilling (FTWD) service, was introduced to the Valhall Flank Drilling campaign in May 2003. Introduction of this service was anticipated to be the most cost effective solution for gathering pressure data on these long horizontal wells. After the first well, the equipment was modified; and the rate of success increased from 20% to 90 %. As of November 2004, the service has been run in seven wells. In this paper, we review the value the service has added to the drilling campaign and also review the experience gained with the service during its first year.The drilling environment is dynamic with hydrostatic pressure constantly changing. The new tool offers the capability to perform pressure tests in this environment with the mud pumps on or off. As an essential part of FTWD job planning, estimates are made concerning the impact of hydrostatic pressure changes and supercharging prior to logging a well. In most cases, these estimates show that pressure data gathered with this service compare favorably to other pressure measurements, such as those gathered during perforating and stimulating.The field examples presented demonstrate the field procedures used to gather pressure measurements and the added value from acquiring this data during the drill phase. Knowledge of the reservoir pressure distribution in these wells was crucial to understanding flow dynamics across the field and optimizing well decisions. These data have also impacted perforation and stimulation procedures that would not have been foreseen using conventional wireline tests. The data have been used to optimize the drilling process by providing key information for the TD decision.Finally, conclusions are drawn regarding FTWD technology today and regarding its future direction for the Valhall Flank drilling campaign in particular. Fig. 2-GeoTap Tool Collar showing the packer/probe and equalization valve. The packer/probe is protected in a recessed portion of the collar. A stabilizer is attached to the collar to centralize the tool.

Fluid samples were acquired in an exploration well and subsequent pilot hole for an operator in deep water on the Norwegian continental shelf to identify the reservoir fluids and to check for potential connectivity between two reservoir targets. Several limiting factors meant that pipe-conveyed logging after drilling was not a viable option. Consequently, a logging while drilling (LWD) formation fluid sampling tool was run as a part of a LWD evaluation program to collect fluid samples while drilling and when pulling out of the hole after reaching TD (total depth) of the section. A team of global and local experts was established to plan the job. The team performed a risk analysis to identify risks and plan mitigating actions. Several challenges were identified, including the potential damage to equipment from vibration when drilling out the shoe track or from hitting stringers while drilling the formation. Other challenges identified involved potential tool movement from rig heave during sampling and required sampling time as a function of the duration of formation exposure to drilling mud before sampling. The team assessed the risks and established a plan to mitigate them, and the job was performed according to plan in February and March of 2014. A total of nine fluid samples were collected in two well sections, completing each section in one drilling run. This paper discusses the results of the third-party laboratory sample analysis. The formation evaluation logs were inconclusive as to whether or not the reservoir contained oil, condensate, or gas at some depths because of the laminated structure of the formation. The LWD fluid sampling technology confirmed that the reservoir contained gas. This paper also discusses the job planning, mitigating actions that were introduced, implementation and results of the job, and the benefits of fluid sampling while drilling.

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