Variation in hydrocarbon fluid properties, composition and spectrum is one of the major uncertainties that oil and gas industry faced for decades. The issue is further amplified through changes in pressure and temperature condition from downhole up to surface operating boundaries, which often resulted in unnecessary liquid drop-out or unfavourable change in the fluid phase envelope. This will deem all the fluid identification and PVT analyses conducted during real time operation monitoring to be invalid. Recently, with new technology breakthrough, the current status quo of downhole fluid identification via wireline conveyed had been challenged through the application of the in-situ sampling while drilling tool. This paper will highlight what are the pain points in conventional wireline conveyed fluid identification, few case studies on the new technology application, generating reservoir management insights based on the results and the impact to the field development plan.

Application of downhole in-situ fluid analyzer had seen an interesting evolution over the decades. Driven by massive variation in hydrocarbon fluid properties across the different continents, fluid characterization methodologies and algorithms have also become more sophisticated. Similar to any real time operation, pre-job planning is the key to achieve the well objectives. Gathering fluid properties from nearby wells based on previous downhole fluid analyzer operation and predicting the real time fluid contamination level to determine hydrocarbon fluid type present are two key components that complement this new technology which drive value creation in terms of pumping time optimization and also quality assurance of the fluid Results from the case studies presented show successful hydrocarbon fluid type determination which distinguish oil from water and oil from gas presence. Comparison of real time hydrocarbon composition from the new technology deployed with the lab-based composition from the nearby wells indicate a close agreement given the two different operating conditions. In addition, presence of reservoir contaminants such as CO2 and H2S could be predicted based on the correlation developed using the real time monitoring channels. Feasibility of predicting the amount of contamination level for QC purpose and prioritizing fluid samples for PVT analysis are also demonstrated.

In a nutshell, the new in-situ while drilling fluid analyzer has successfully delivered promising well results amidst the challenges and operational constraints. New development of other reservoir parameter sensors such as CO2, H2S, gas composition up to C36 components, density, viscosity, bubble point and fluorescence index are getting more demand and will shape the future fluid characterization technique.

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