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Jose Angulo Yznaga, Reinaldo (Halliburton) | Vican, Kresimir (Halliburton) | Jambunathan, Venkat (Halliburton) | Najm, Ehab (Halliburton) | Guergueb, Nacer (Halliburton) | Francis Eriavbe, Francis (Al Dhafra Petroleum)
Rock typing in carbonate reservoirs has always represented a difficult challenge due to rock heterogeneity. When interpreting electrical logs, the thick carbonate formation can leave an impression on the homogenous environment; however, looking at core analysis and mercury injection capillary pressure (MICP) data, reservoir heterogeneity can be determined. This complexity of the formation characterization presents challenges in reservoirs that contain tilted water/oil contact (WOC). Tilted WOC discovers hydrocarbon saturation below the free-water level, and different events during geological time can contribute to this specific fluid accumulation. Knowledge of the fluid distribution is needed to understand the mechanisms of oil entrapment, oil volumetric, and potential recovery mechanisms involved in reservoirs under this wettability and WOC conditions. This case study will describe the workflow used to characterize and model an atypical regime like non-water wet formations in reservoirs with tilted WOC.
In this study, a combination of electrical logs, core analysis (lithofacies, poro-perm, MICP), and customized workflow was used to characterize, classify, and map facies. Capillary pressure information and formation tester data were integrated and compiled for each facies. Moving forward, a new method was developed to model saturation height functions representing non-water wet formations and tilted WOC phenomena.
Fluid and saturation properties are estimated and assigned to each reservoir point and after reservoir rock types (RRT) were defined. This method has been validated by applying the new approach to actual well data. The drainage capillary pressure (Pc) lab data in the reservoir intervals with established conventional WOC complemented interpretation results derived from acquired logs; however, for the reservoirs zones with identified tilted OWC, correlation and matching Pc lab data with logs was not possible. The new method provides saturation properties in formations with complex fluid-rock interactions and phenomena.
This work introduces a novel approach to estimate saturation height functions and saturation distribution for reservoirs with complex fluid-rock interaction and distribution, such as non-water wet formations in tilted WOC conditions.
Kundu, Ashish (Abu Dhabi Co For Onshore Petroleum Operations Ltd) | Voleti, Deepak Kumar (Abu Dhabi Co For Onshore Petroleum Operations Ltd) | Rebelle, Michel (Abu Dhabi Co For Onshore Petroleum Operations Ltd) | Al Housani, Habeeba Ali (Abu Dhabi Co For Onshore Petroleum Operations Ltd)
Abstract The studied lower Cretaceous carbonate ramp deposits are heterogeneous with pervasive diagenetic processes leading to complex pore network and rock texture. Before this study, field development was based on log based water saturation modeling. This saturation modeling was dependent on the hydraulic flow units and porosity classes, which was meant to be, but was not explicitly representative of the defined geologic facies. The assignment of the relative permeability data is also very challenging in the absence of proper Rock Type model. Often in carbonate reservoirs, there is no direct or linear relationship between Reservoir Rock Types (RRT), sedimentological facies assemblages and water saturation distribution across the field. Hence, accurate integration of the sedimentological, diagenetic, depositional environment information and petrophysical properties is essential in building a robust RRT model. This RRT model can then explain the rock-fluid interaction through a reliable saturation height model. In the first part, the paper illustrates the workflow which involves integrating lithofacies, depositional packages, degree of cementation, pore-type from sedimentology and relating resultant pore-typing to core porosity–permeability data. This workflow resulted in a strong reservoir rock typing scheme, which was key in building a robust saturation height model. Precisely, this was achieved by assigning "most-of lithofacies and diagenetic indicators" to each rock type defined. In the second part, a Variable Saturation Height Function (VSHF) was developed using mercury injection capillary pressure (MICP) data. The function was made variable with depth by bringing one or both of the reservoir parameters (Phi and K) into the equation. Most importantly, VSHF explicitly scans the lower and upper Sw boundary of a particular rock type and helps in removing the skewness in the Sw difference histogram between model and log Sw. One of the important steps in the workflow was to normalize the MICP data to log derived Sw values, provided the confidence on the Sw calculation from logs is high. After stress and closure correction, the normalization of the reservoir Pc data was achieved through an independent correction factor. Both of the workflows (rock typing and saturation height modeling) were built based on data from 30 cored wells. The workflows were tested on 15 cored wells and more than 600 non-cored wells. Rock type maps were found to be more correlatable with reservoir quality maps than lithofacies maps alone. This is a result of the diagenetic processes undergone by the rock during and after deposition modifying the original depositional controlled pore architecture. With this approach the water saturation distribution was more consistent with logs and core derived Sw data. The workflows shown in this paper are reliable and can be extended to other carbonate fields’reservoir characterization.
Al-Amri, Meshal A. (King Fahd University of Petroleum & Minerals) | Mahmoud, M. N. (King Fahd University of Petroleum & Minerals) | Al-Yousef, Hasan Y. (King Fahd University of Petroleum & Minerals) | Al-Ghamdi, Tariq M. (Saudi Aramco)
Abstract Accurate estimation of permeability is essential in reservoir characterization and in determining fluid flow in porous media to optimize the production of a field. Some of the available permeability prediction techniques — e.g., Porosity-Permeability transforms and more recently artificial intelligence and neural networks — are encouraging but still show only moderate to good match to core data. This could be due to limitation to homogenous media while the knowledge about geology and heterogeneity is indirectly related or absent. The use of geological information from core descriptions, e.g., Lithofacies, which includes diagenetic information, show a link to permeability when categorized into rock types exposed to similar depositional environments. The objective of this paper is to develop a robust combined workflow integrating geology and petrophysics and wireline logs in an extremely heterogeneous carbonate reservoir to accurately predict permeability. Permeability prediction is carried out using pattern recognition algorithm called multi-resolution graph-based clustering (MRGC). We will bench mark the prediction results with hard data from core and well test analysis. As a result, we show how much better improvements are achieved in permeability prediction when geology is integrated within the analysis. Finally, we use the predicted permeability as an input parameter in J-function and correct for uncertainties in saturation calculation produced by wireline logs using the classical Archie equation. In conclusion, a high level of confidence in hydrocarbon volumes estimation is reached when robust permeability and saturation height functions are estimated, in conjunction with important geological details that are petrophysically meaningful.
Menon, Pradeep (Al Dhafra Petroleum Operation Company) | Ali, Abdulla (Al Dhafra Petroleum Operation Company) | Guergour, Mohamed N. (Al Dhafra Petroleum Operation Company) | Ebeid, Mahmoud (Al Dhafra Petroleum Operation Company) | Jeong, Jaehoon (Al Dhafra Petroleum Operation Company) | Darous, Christophe (Schlumberger)
Abstract What makes a petrophysical model robust is the understanding of the relationships between its petrophysical properties, typically porosity, permeability, and saturation. In carbonates, and particularly in limestones, the pore geometry and connectivity are often not uniform which can lead to lack of correlation between porosity, permeability, and saturation. This study explains how the combination of core analyses, Nuclear Magnetic Resonance (NMR), and borehole image logs was used to build a permeability transform that considers the pore size distribution and connectivity. The permeability model is based on a dual medium pore network concept that combines the macro pore network with the micro and meso pore network according to their relative pore volume. The saturation height functions are defined based on the rock characteristics that honor the capillary pressure (Pc) core data behavior. The comparison of the pore size partitioning from NMR logs or borehole image processing with the core description and digital core photos provided important information on how to process and interpret both log and core data. The pore size distribution was associated with depositional and diagenetic processes that were used during the 3D modeling of the macro porosity. After the porosity and the macro-porosity were modelled using geological concepts and geostatistics, the permeability in the 3D static model is directly computed using the function defined from core and logs. The saturation height functions (SHF) are defined from routine and capillary pressure (Pc) core data to be consistent with the pore size classification used to define the permeability model. The saturation height modeling is ultimately adjusted by combining the free water level (FWL) from pressure data, SHF from Pc data, and log-derived water saturation. All the properties of the model are consistent between each other and can be updated with new wells very easily since only porosity and its macro porosity volume need to be re-populated with the data from the new wells. The construction of empirical permeability models in particular in carbonates that use the pore size distribution has been established in the past generally at the core to log level. This work revisits the construction of those analytical permeability models by using a dual-media pore network concept and illustrates the advantages to use those functions directly in the 3D modeling construction and update.
Abstract The Middle East region holds substantial resources of unconventional tight gas and shale gas. The efficient extraction of these resources requires significant technology and expertise across numerous disciplines, including reservoir description and geomechanical characterization, hydraulic fracture modelling and design, advanced numerical simulation capabilities, sensor and surveillance technologies, and tightly integrated workflows. The effective application of these integrated subsurface and completion workflows leads to improved capital efficiency and well performance through increased well potential, increased ultimate recovery, and reduced costs. Key elements include dynamic rock typing to highlight potential flow units that will maximize gas deliverability, geomechanical modelling to provide a calibrated stress profile, and an integrated model that demonstrates the importance of understanding both dynamic flow properties and geomechanical response in complex tectonic environments. Dynamic rock typing focuses on using both depositional and petrophysical properties including rock type, porosity, and effective gas permeability at reservoir conditions to divide the reservoir into flow units in the context of their saturation history. The geomechanical profiling generates a tectonics-corrected minimum horizontal stress (SHmin) and the net confining stress (NCS). The rock-log-test calibration requires the evaluation and integration of subsurface fracture tests, including After-Closure Analysis (ACA), Data Fracs and Micro Fracs. All three involve different injection volumes and sampled reservoir volumes. Tight gas petrophysical studies must go “beyond volumetrics”, and should consider not only the static (storage) and dynamic (flow) properties within the context of the petroleum system and evolution of the current day pore geometry and fluid saturation distribution, but also the geomechanical stress regime and its implications for efficient completion optimization. Alternative interpretations test the range of uncertainty and are useful in designing field trials and surveillance strategies to reduce the subsurface uncertainty and to mitigate development risks.