No abstract

This paper displays an example of the power of data integration. Multiple sub-surface datasets viz., Bore Hole Images (BHI), triple-combo logs, core data, production logs and geomodels were tied together to throw light on suspicious injection profile patterns observed in a horizontal well drilled in the Thamama Group. This well was drilled in an onshore green field. The production log provided information on injection profile patterns and quantity of fluid intake per zone along the drilled well path. Bore Hole Images (BHI) were processed and analysed for structural features including fractures and faults. Advanced analysis was performed on BHI to gather information on diagenesis along well path. Emphasis was put on extraction of moldic (vuggy) porosity content. Allied LWD resistivity, density, gamma ray and porosity logs were used to calibrate and back-up BHI-based findings. Core descriptions, core photographs, and petrographic analysIs results from offset vertical wells were looked-into in detail to understand diagenesis better, in the adjoining area of candidate well. Structural events identified at well scale were calibrated to field-scale using up-to-date geomodels. The integrated approach helped in comprehending flow profile patterns in candidate well. Prior to this study, it was assumed that the observed flow profile behavior was related to factors like tool malfunction, well trajectory and even large open fractures. However, post-study findings revealed clear diagenetic control on injection profile (and zonal intake). The role of fractures were observed to be minimal to negligible in this case.

A Reservoir Rock Typing (RRT) and Saturation modelling integrated study of the Lower Cretaceous Group reservoirs in Field X was conducted as part of required inputs into an ongoing FDP update. The results of this study allowed for a robust 3D modelling workflow that included saturation height modelling of the observed tilted oil water contact in the acquifer underlying three (3) of the major hydrocarbon bearing zones. The study intervals covered intervals that for the purpose of this paper will be called XH-4, XH-1, KX-2, XK-3 and XK-2 zones. Rock types were defined using core data integrated with geological descriptions and 3D distributed taking into consideration the depositional environments. Porosity, permeability and saturation property distribution was guided by the RT distribution. In total 44 wells in the field plus 4 nearby wells were incorporated in this study. This paper analyses the petrophysical, geological and static modelling workflows utilized. The RRT definition was based on the prediction of Self Organising Map (SOM) electrofacies which were classified using the petrophysical grouping obtained from lithofacies and depositional environment, permeability and MICP data. As a further step, the predicted RRT was optimised where the Archie saturation indicated that a different rock type was more likely. The analysis of virgin formation pressure data to understand the tilted OWC/FWL concept reveals that different wells have different absolute pressures. When the differences are mapped no regional trends were observed which makes a hydrodynamic origin of the tilted OWC/FWL less likely. Free water level (FWL) has been interpreted on well by well basis and mapped across the field for a better understanding of the variation. The pressure data are consistent with the scenario that the XH-4, XH-1 and KX-2 zones all share the same free water level for modelling purposes. The OWC is more or less flat in the central field area and is about 35 ft deeper in the eastern part of the structure. Although the difference in OWC could be abrupt (compartmentalisation), a gradual tilt seems to fit the data better. Furthermore, the ‘deepest oil observations’, which relate to paleo conditions, are deeper than present-day FWL in the east. All these observations would be consistent with a structural tilt towards the east. Similar trends were also observed from the FWL interpreted across key wells having formation pressure data. In terms of reservoir quality, the interval XK-3 has highest porosity and highest permeability. Also XH-1 and KX-2 contain good reservoir quality rocks. XH-4 is located above XH-1 and KX-2 and has relatively low quality matrix properties. It does contain low porosity (and hence brittle rocks) that can be expected to contain oil when fractured. The deeper XK-3 is probably disconnected from the underlying XK-2 which can be explained by the argillaceous interval between XK-3 and −2. XK-2 consists of thin reservoir intervals so that both Archie saturation estimates and the rock typing work carry significant uncertainty. The derived saturation height (SH) models utilise both a present-day and a paleo free water level per well. Each reservoir interval has its own SH-model based on SH-functions for each RRT. Implementation of all defined RRTs with associated SHFs was done to allow for highest resolution population of the geomodel, though a significant number of algorithms is required for this process. The RRT population of the static models was designed to be obtained from the combination of 3 distributed parameters: porosity, depositional environment, and reservoir quality by using the algorithms provided. Reservoir Quality is the driver most closely linked to diagenesis and local permeability variations.