ABSTRACT
The appraisal phase is a unique opportunity to evaluate reservoir continuity for reducing key uncertainties required for field development decisions and planning. Consequently, appraisal activities for large offshore reservoirs necessitate optimal fluid and formation data acquisition and analysis to reduce reservoir uncertainties. This is critical for assessment of vertical and lateral reservoir connectivity, flow assurance or fluid production behaviors under future EOR schemes.
Reservoir Fluid Geodynamics (RFG) studies incorporating downhole fluid analysis (DFA) measurements and analysis of reservoir fluid samples help establish origin and history of the fluids in the reservoir - from charge through to present day (4.2 km apart Mullins, 2019). This new discipline coupled with geochemical, image and core analysis allows addressing important risk factors, such as vertical and lateral reservoir connectivity. This paper shows how DFA gradient analysis and implications regarding charge, geology evolution from log data and whole core, and well test evaluation all combine to give a robust interpretation of the good news of excellent lateral connectivity.
The Upper Miocene age Zama oil discovery, located in the offshore Sureste Basin of Mexico, was initially identified as a three-way dip structure sealed against a normal fault system. It consists of individual stacked turbiditic sands as seen on borehole images and logs, overlain by a thick hemipelagic shale. During field appraisal, formation testing data and representative fluid samples were required for assessing reservoir connectivity and for input to engineering studies. The initial appraisal wells could not be sampled effectively using established sampling technologies since many reservoir intervals were poorly consolidated.
A new formation testing platform was deployed in two appraisal wells to overcome these challenges. This new system enabled focused sampling and downhole fluid analysis, with collection of pure samples while maintaining controlled low-pressure drawdowns during sample cleanup. In real-time, downhole fluid analysis measurements were used to guide the sampling process, identify additional depth intervals requiring characterization, and enable assessment of reservoir continuity between different flow units using RFG principles.
More than thirty pressure-compensated fluid samples of high-quality and purity were efficiently collected at multiple depths. Subsequent laboratory analysis of the sampled fluids confirmed the favorable case of laterally extensive connectivity of the stacked sands sequences. Petroleum geochemistry analysis also corroborated measurements of reservoir fluid gradient and asphaltene concentration gradients; which provided further insights on timing of migration and reservoir charging. Interpretation of geological image logs and subsequent full core analysis were consistent with DFA gradient analysis, and the lateral connectivity predictions were confirmed during a multi zone well test. This case study demonstrates how RFG analysis using advanced formation testing and sampling measurements integrated with borehole image and petrophysical log evaluations enables reservoir connectivity assessment and predictions for a large field offshore Mexico.
