Analysis of Lateral Fluid Gradients From DFA Measurements and Simulation of Reservoir Fluid Mixing Processes Over Geologic Time
Authors:   Schlumberger, Chen Qing , Kristensen Morten ,   Schlumberger, Johansen Yngve Bolstad ,   Aker BP, Achourov Vladislav ,   Schlumberger, Betancourt Soraya S. ,   Schlumberger, Mullins Oliver ,   Schlumberger
Published: January 2021

Downhole fluid analysis (DFA) is one pillar of reservoir fluid geodynamics (RFG). DFA measurements provide both vertical and lateral fluid gradient data. These gradients, especially the asphaltene gradient derived from accurate optical density (OD) measurements, are critical in thermodynamic analysis to assess equilibration level and identify RFG processes. Recently, an RFG study was conducted using DFA and laboratory data from an oil field in the Norwegian North Sea. Fluid OD gradients show equilibrated asphaltenes in most of the reservoir, with a lateral variation of 20%. This indicates connectivity, which is confirmed by three years of production data. Two outliers are off the asphaltene equilibrium curve implying isolated sections, one each on the extreme east and west flank. Their asphaltene fraction varies by a factor of six. Such a difference reveals that different charge fluids entered the reservoir, and the equilibrated asphaltenes are the result of an after-charge mixing process. Meanwhile, different gas-oil contacts (GOCs) exist in the reservoir, indicating a lateral solution-gas gradient. Geochemistry analysis shows the same level of mild biodegradation in all the fluid samples, including those from two isolated sections. This means that biodegraded oil spills into the whole reservoir with little or no in-reservoir biodegradation. Furthermore, lateral asphaltene gradients at different times after charge have been preserved; it was a factor of six in asphaltenes content initially and is now 20% in the present day. This unique data set provides a valuable constraint to simulate reservoir fluid after-charge mixing processes to present day, aiming to investigate the factors impacting the evolution of lateral composition gradients in geologic time in a connected reservoir. Numerical simulations were performed over geologic time in reservoirs filled by oil with a lateral density gradient, which imitates the lateral compositional gradients in the gas-oil ratio (GOR) and asphaltenes measured in the above oil field. Simulations show that this lateral gradient creates lateral differential pressures and causes a countercurrent fluid flow forming a convection cell. In reservoirs with realistic vertical-to-horizontal aspect ratios, such fluid flows are not rapid, and lateral gradients can be partially retained in moderate geologic times. Additionally, diffusion was included in the simulation. The reservoir model was initialized with two GOCs producing subtle lateral GOR and density gradients. The simulated mixing process transports gas from higher GOR regions to lower GOR regions and reduces the GOC difference. However, the flux of solution gas transport is small. Consequently, we conclude that lateral GOR and asphaltene gradients can persist for moderate geologic time, which is consistent with observation from the field.