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.

Tar mat and asphaltene are present in many reservoirs around the world. The mechanism of origin of these deposits can vary from one reservoir to another. The processes involved in asphaltene enrichment is governed by many factors. For example, gravitational segregation and light hydrocarbon or gas charge into an oil reservoir or oil biodegradation-residue, e.g. at paleo oil-water contact (OWC). Heavy residual oil in many reservoirs can act as a permeability barrier and is a challenge for petrophysical evaluation using conventional logging tools. Asphaltene can be residual, immobile, or it can be mobile and deposited in the reservoir or production lines. Comprehending the distribution of tar and asphaltene in a reservoir is an important component in production optimization, and which often requires using a combination of technologies. Measurements from a combination of surface logging and downhole tools were adapted to understand the presence and distribution of tar and asphaltene in a field on the Norwegian continental shelf. The main driver for this approach was the presence of asphaltene in the field and to mitigate associated risks including compartmentalization, impact on reservoir properties, and reserve estimate. On one hand, Surface measurements are referred to as ‘surface toolbox’, which mainly consisted of compositional analysis of light hydrocarbons detected using advanced mud gas analysis and Total Organic Carbon (TOC) measurements on cuttings. They provide a direct assessment of the organic matter nature expected in such an environment, from light hydrocarbons to viscous liquid mixture and solid carbon deposit. On the other hand, the ‘downhole toolbox’ consisted of a fluid-mapping-while drilling tool (FMWD) based on optical spectrometry. Laboratory calibrated C5 asphaltene concentrations (wt%) were estimated during real-time drilling operations using logging-while-drilling downhole fluid analysis (LWD-DFA) to assess the similarity between fluids in the well being drilled and those in offset wells. The differentiation of mobile hydrocarbon from immobile zones is a complex task. We have enhanced the asphaltene detection while drilling using surface measurements including pyrograms from an isothermal combustion process, and fluid properties from mud gas analysis. This continuous fluid information was used for selecting downhole fluid sampling or scanning stations to confirm the observations from surface measurements. The identification and quantification of asphaltene and its properties was used in optimizing the completions of the producer wells.