An exploration deep well crossing two reservoirs with different quality and properties, having an objective of: Fluid identification and sampling in extremely tight section (∼0.02mD/cP mobility) as well as in another section that is suspected to be depleted with very high overbalance exceeding legacy tools, knowing the hydrostatic pressure being ∼9500psia. Wireline formation tester was run using single probe, leading to 65% of tight stations, the rest were valid but with very low mobility. This exposes the tool to an increasing pressure differential exceeding its physical limit and leading to damaging it. This makes any further analysis impossible. The toolstring was upgraded with latest technology of WFT, that is a merge between probe based and dual packer modules. This new technology was designed with extreme environments in mind, that allows sampling in all mobility range from extreme tight to very high with its capability of holding up to 8000psia differential pressure. In the job described here, some of the tested reservoir sections were differentially depleted, something unknown to customer as this was an exploration environment. Since this information were not know even after the completion of the first and second run, a third run was carried out with the objective of re-investigating the same depths performed by the single probe, but this time 3D Radial Probe was used instead. This gave the advantage of taking the pressure down to almost 0 psia. The potential hydrocarbon zone which was bypassed (seen dry with single probe) was then tested with 3D radial probe giving a reservoir pressure of 2864psia with a mobility of ∼300mD/cP where gas condensate was identified and captured. Now for the extreme tight reservoir section, in combination with high hydrostatic, the mechanical limitation of traditional tools remains the same making sampling and/or fluid ID impossible. An attempt was made using the 3D radial probe, and despite the extreme low mobility ∼0.02mD/cP, an identification of the reservoir fluid (water) was successfully completed without any issue. The use of 3D Radial Probe technology gave a completely different picture from what was expected, enabled the completion of all objectives and made the impossible (with conventional technology) possibly and easily achievable. This resulted in changing the well strategies accordingly and complete the well successfully. The new technology made the testing of unconventional reservoirs a reality.

In producing fields, re-mapping reservoir fluid content and new contacts are one of the most important objectives in pursuit of optimized well productivity. Wireline logs and formation testing (FT) data is widely used for this purpose. Continuous fluid data from Advanced Mud Gas (AMG) analysis with downhole logs can be used to generate a comprehensive dataset for reservoir evaluation. Each method has its limitations and advantages. Combining and interpreting the output from the fundamentally different datasets require an experienced petro-technical expert with a specific skill set. To calculate hydrocarbon volume, estimate and forecast reserves, formation fluid evaluation has primarily relied on traditional methods that depends heavily on formation pressure measurements. This was achieved through the analysis of gradients and local fluid contacts. This approach can be misleading for brownfields, where a sizable amount of producible hydrocarbon is left in the reservoir. For characterizing formation fluid, a novel approach utilizing complimentary technologies was adopted. For early hydrocarbon detection and FT program optimization, AMG data was first gathered while drilling. Post drilling open Hole logs, formation pressure and fluid data were acquired not only to verify the AMG findings but also to fill in the gaps regarding water-swept zones, reservoir pressure and depletion, exact fluid contacts, and fluid characteristics to reduce uncertainties. During the job execution, AMG data was effectively used to provide early formation fluid identification and contacts. This information was used to optimize the wireline advanced fluid analysis stations. AMG analysis identified multiple fluids (wet gas, gas condensate, oil, and water) and revealed a much greater complexity of the reservoir than initially expected, which could not have been achieved with standard formation evaluation or other fluid contact identification techniques based on regional gradient analysis. The fluid types and contacts identified by AMG were then confirmed by the wireline downhole fluid analysis. Using this workflow, a high potential recoverable hydrocarbon oil was identified over a reservoir that was classified as a water zone based on initial evaluation and knowledge. In this field, an innovative method was adopted for reservoir fluid characterization. This approach based on digital integration and a unified workflow was used successfully for fluid contact identification, targeted fluid sampling, and identifying and recovering more hydrocarbon from the swept zones.