Identification of Patches of Bitumen in a Carbonate Reservoir: A Case Study

Carbonate reservoir X has varying levels of maturity in terms of development. The South/West is highly matured; development activities have recently kicked-off in the Crestal part while the areas towards the Far North is not fully developed and posed the largest uncertainty in terms of reservoir quality, fluid contacts, oil saturation, well injectivity/ productivity, area potential and reserves due to poor well control. In reservoir X with segmented development areas, patches of bitumen have been found in the Far North. The extent of this Bitumen was unknown. In order to expand the CO2 development concept to achieve production target from the Far Northern flank, an understanding and mitigation of the area uncertainties is crucial. Reservoir bitumen is a highly viscous, asphaltene rich hydrocarbon that affects reservoir performance. Distinguishing between producible oil and reservoir bitumen is critical for recoverable hydrocarbon volume calculations and production planning, yet the lack of resistivity and density contrast between the reservoir bitumen and light oil makes it difficult, if not impossible, to make such differentiation using only conventional logs such as neutron, density, and resistivity. This paper highlights the utilization and integration of advanced logging tools such as nuclear magnetic resonance and dielectric, in conjunction with routine logs, pressure points, RCI samples, vertical interference test and core data to differentiate between reservoir bitumen and other hydrocarbon types in the pore space. The major findings from the studies shows bitumen doesn't form as a single layer but occurs in different subzones as patches which is a challenge for static modelling. When high molecular weight hydrocarbons are distributed in the pore space and coexist with light and producible hydrocarbons, reservoir bitumen is likely to block pore throats. The Bitumen present in this reservoir have a log response similar to conventional pore fluids. The outcome of this study has helped in refining the bitumen boundary, optimize well placement, resolved the uncertainties associated with deeper fluid contacts and provided realistic estimate of STOIIP.

The Use of Nuclear Magnetic Resonance (NMR) Measurements and Conventional Logs to Predict Permeability for a Complex Carbonate Formation

Permeability is one of the most important property for reservoir characterization, and its prediction has been one of the fundamental challenges specially for a complex formation such as carbonate, due to this complexity, log analysis cannot be accurate enough if it’s not supported by core data, which is critically important for formation evaluation. In this paper, permeability is estimated by making both core and log analysis for five exploration wells of Yammama formation, Nasiriyah oil field. The available well logging recorders were interpreted using Interactive Petrophysics software (IP) which used to determine lithology, and the petrophysical properties. Nuclear Magnetic Resonance (NMR) Measurements is used for laboratory tests, which provide an accurate, porosity and permeability measurements. The results show that the main lithology in the reservoir is limestone, in which average permeability of the potential reservoir units’ values tend to range from 0.064275 in zone YA to 20.74 in zone YB3, and averaged porosity values tend to range from 0.059 in zone YA to 0.155 in zoneYB3. Zone YB3 is found to be the best zone in the Yammama formation according to its good petrophysical properties. The correlation of core-log for permeability and porosity produce an acceptable R^2 equal to 0.618, 0.585 respectively

Pipe Conveyed NMR Logging Secures Successful Reservoir Characterization in a Low Resistivity Pay

The Middle Burgan formation in North Kuwait is very challenging: its limited vertical thickness and overall low resistivity require complex and special operations for drilling, formation evaluation and completion to ensure optimum production. The objective of this case study is to demonstrate the value of Nuclear Magnetic Resonance (NMR) log data to provide rock quality and fluid typing in this challenging environment, where conventional logs are not enough for reservoir understanding along a horizontal well. A horizontal 6 1/8" section was drilled through the Middle Burgan formation with oil-based mud and Gamma Ray, Resistivity, Density data were acquired while drilling, and data from the latest generation of multifrequency, focused NMR wireline tool (FMR), conveyed on pipe (PCL). Water saturation computation in low resistivity pay often exceeds the real value when computed using conventional logs. In this environment, NMR logging proved to be essential for the proper reservoir characterization and to support critical decisions on well completion design. Fundamental rock quality and permeability profiles were supplied by NMR. Oil saturation was identified by applying the 2D-NMR methods, Diffusion vs. T2, or DT2 maps. Despite the presence of washouts, high quality NMR data was obtained at different depths of investigation in the horizontal well section. Integrating the NMR data with conventional well logs helped advanced reservoir characterization, in reducing the uncertainty in formation evaluation by clearly identifying pay and shale zones, and furthermore, in providing necessary information to support management decisions regarding fracking design to maximize oil production. The formation evaluation and well objectives were met with the aid of the high-quality NMR log data. The multifrequency capability of the tool allows data acquisition at different depths of investigation which helped to overcome the negative effects of washouts in the data interpretation. A remarkable well performance and high productivity from the low resistivity, thin reservoir layers, is expected based on decisions made from the by very reliable well log data interpretation.