Abstract This paper presents the results of a full field simulation study for a rich gas condensate reservoir with complex fluid behavior. Unique to this paper is a comparison between Modified Black-Oil (MBO) and compositional simulation in a full field model with water influx. Geological, petrophysical, fluid properties, rock-fluid properties, and well data were used to build two full field simulation models (14-component Equation-of-State, compositional model and 3-component MBO model). More than 14 months of daily gas, oil, and water production and tubing pressure data from 4 wells were matched using the MBO model. The model was then used to forecast production and identify new development locations. Comparison runs between the MBO and the fully compositional models were made. It was found that the two models agreed for the entire simulation above and below the dew point and with water influx from the aquifer. The MBO runs were at least 5 times faster than the most efficient compositional run.
The use of the MBO approach allowed a rapid history match of the field performance and a timely completion of the simulation study. Contrary to the common belief that a compositional simulation approach is needed for modeling near-critical reservoirs, this study shows that a MBO approach can be used instead of a fully compositional approach for modeling depletion and water influx processes in near-critical reservoirs. This approach may result in significant time saving in full field simulation.
Introduction Reservoir simulation is often used to study a variety of problems. In this paper, we used reservoir simulation to study a rich gas condensate reservoir. After producing the field for approximately 400 days, it was decided to construct a full field simulation model and history match the field performance. The objectives of the study were to evaluate gas and condensate reserves, forecast field production, and optimize field development. The following discussion summarizes the results of the simulation study.
Field Background The field is a moderate-size rich gas condensate reservoir with gas production rate of 55 MMscf/D from three wells, measured at the high-pressure separator (around 1,000 psia). The field produces from a high-temperature high-pressure offshore reservoir. Reservoir temperature is more than 310°F and initial reservoir pressure is close to 14,230 psia (pressure gradient is approximately 0.9 psi/ft). Another well was added to boost the field production to 80 MMscf/D and the field is currently producing from four wells. Gas, condensate, and water are separated on the platform where they are metered and then mixed together and shipped through a pipeline to a gas plant. The fluids are separated once again at the gas plant and the gas is processed to strip out natural gas liquids.
Geological Model. Detailed log analysis on the four wells in addition to other dry holes in the area revealed that the main sand body in the reservoir is relatively clean with high porosity and low water saturation. The structure on top of the sand was mapped using 3D seismic data. Net sand map was drawn based on the log analysis with input from the geological model. An amplitude map derived from the 3D seismic data was used to guide the net sand map between the wells. The reservoir is highly faulted with a large-throw north-south fault that separates the reservoir into two completely isolated fault blocks. Fig. 1 shows the structure map on top of the reservoir sand. The figure shows the two main fault blocks, several smaller blocks, and the location of the four producing wells.
Geological Model. Detailed log analysis on the four wells in addition to other dry holes in the area revealed that the main sand body in the reservoir is relatively clean with high porosity and low water saturation. The structure on top of the sand was mapped using 3D seismic data. Net sand map was drawn based on the log analysis with input from the geological model. An amplitude map derived from the 3D seismic data was used to guide the net sand map between the wells. The reservoir is highly faulted with a large-throw north-south fault that separates the reservoir into two completely isolated fault blocks. Fig. 1 shows the structure map on top of the reservoir sand. The figure shows the two main fault blocks, several smaller blocks, and the location of the four producing wells.