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The classic method for initializing reservoir simulation models in the presence of a transition zone, based on primary drainage capillary-gravity equilibrium, is extended to account for partial reimbibition post oil migration. This tackles situations where structural events, such as trap tilting or caprock leakage, caused the current free-water level (FWL) to rise above deeper paleo-contacts. A preliminary primary drainage initialization is performed with zero capillary pressure at the paleo (or deepest historical) FWL, to obtain a minimum historical water saturation distribution. From a capillary pressure hysteresis model, it is then possible to determine the appropriate imbibition scanning curve for each gridblock, which are used to perform a second initialization with zero capillary pressure at the current FWL. With the proposed method, log-derived saturation profiles can be honored using a physically meaningful capillary pressure model. Furthermore, when relative permeability hysteresis is active, it is possible as a byproduct of the initialization to assign the correct scanning curves at time zero to each gridblock, which ensures that initial phase mobilities (hence reservoir productivity) and residual oil saturation (hence recoverable oil to waterflood) are modeled correctly. This is demonstrated with a synthetic vertical 1D model. The method was implemented in a commercial reservoir simulator to support modeling work for a giant undeveloped carbonate reservoir, where available data suggest that more than 3/4 of the initial oil in place could be located between the current FWL and a dome-shaped paleo-FWL. This work is used as a case study to illustrate the elegance of the proposed method in the presence of multiple (or tilted) paleo-FWLs, as only one set of capillary pressure curves per dynamic rock-type is required to honor the complex log-derived saturation distribution.
The classic method for initializing reservoir simulation models in the presence of a transition zone, based on primary drainage capillary-gravity equilibrium, is extended to account for partial reimbibition post oil migration. This tackles situations where structural events, such as trap tilting or caprock leakage, caused the current free-water level (FWL) to rise above deeper paleo-contacts. A preliminary primary drainage initialization is performed with zero capillary pressure at the paleo (or deepest historical) FWL, to obtain a minimum historical water saturation distribution. From a capillary pressure hysteresis model, it is then possible to determine the appropriate imbibition scanning curve for each gridblock, which are used to perform a second initialization with zero capillary pressure at the current FWL. With the proposed method, log-derived saturation profiles can be honored using a physically meaningful capillary pressure model. Furthermore, when relative permeability hysteresis is active, it is possible as a byproduct of the initialization to assign the correct scanning curves at time zero to each gridblock, which ensures that initial phase mobilities (hence reservoir productivity) and residual oil saturation (hence recoverable oil to waterflood) are modeled correctly. This is demonstrated with a synthetic vertical 1D model. The method was implemented in a commercial reservoir simulator to support modeling work for a giant undeveloped carbonate reservoir, where available data suggest that more than 3/4 of the initial oil in place could be located between the current FWL and a dome-shaped paleo-FWL. This work is used as a case study to illustrate the elegance of the proposed method in the presence of multiple (or tilted) paleo-FWLs, as only one set of capillary pressure curves per dynamic rock-type is required to honor the complex log-derived saturation distribution.
Reservoir Rock Typing and saturation modeling need a two-sided methodology. One side is the geological side of the rock types to populate properties within geological concepts. The other side is addressing reservoir flow and dynamic initialization with capillary pressure. The difficulty is to comply with both aspects especially in carbonates reservoirs with complex diagenesis and migration history. The objective of this paper is to describe the methodology and the results obtained in a complex carbonate reservoir. The approach is initiated from the sedimentological description from cores and complemented with microfacies from thin sections. The core-based rock types use the dominant rock fabrics, as well as the cementation and dissolution diagenetic processes. The groups are limited to similar pore throat size distribution and porosity-permeability relationships to stay compatible with property modeling at a later stage. At log-scale, the rock typing has a focus on the estimation of permeability using the most appropriate logs available in all wells. Those logs are porosity, mineral volumes, normalized saturation in invaded zone (Sxo), macro-porosity from borehole image or Nuclear Magnetic Resonance (NMR), NMR T2 log mean relaxation, and rigidity from sonic logs. A specific calculation to identify the presence of tar is also included to assess the permeability better and further interpret the saturation history. The MICP data defined the saturation height functions, according to the modality of the pore throat size. The log derived saturation, and the SHFs are used to identify Free Water Level (FWL) positions and interpret the migration history. The rock typing classification is well connected with the geological aspects of the reservoirs since it originates from the sedimentological description and the diagenetic processes. We identified a total of 21 rock types across all the formations of interest. We associated rock types with depositional environments ranging from supra-tidal to open marine that controls both the original rock fabrics and the diagenetic processes. The rock typing classification is also appropriate to model permeability and saturation since core petrophysical measurements were in use during the classification. The permeability estimation from logs uses multivariate regressions that have proven to be sensitive to permeability after a Principal Component Analysis per zones and per lithologies. The difference between the core permeability and the permeability derived from logs stays within one-fold of standard deviation as compared to the initial 3-fold range of porosity-permeability. We assigned the rock types with three Saturation Height Function (SHF) classes; (unimodal-dolomite, unimodal- limestone & Multimodal-Limestone). The log derived water saturation (Sw) from logs and SHF shows acceptable agreement. The reservoir rock typing and saturation modeling methodology described in this paper are considerate of honoring geological features and petrophysical properties to solve for complex diagenesis and post-migration fluid alteration and movement processes.
This study attempts to describe and model the process leading to the genesis of the tilted oil-water contact (OWC) observed in the lower part of the Thamama Group in an offshore Abu Dhabi field. Post-oil-migration deformation is thought to be the mechanism that produced a tilted OWC dipping towards the Northeast. Deciphering the tectonic evolution from Jurassic to Paleocene times confirms a long and complex structural history combining burial, halokinesis, uplift and tilting. Diapiric activity was probably established in the eastern accumulation by pre-Jurassic times, followed by localized salt-related doming in both parts of the field. During the mid-Eocene occurred a late tilting of the northeastern part of the field, enhancing the curvature of the area. This late tilting caused oil saturation redistribution. In uplifted areas of the field, water saturationdecreased along the drainage curve whereas in areas brought structurally closer to the Free Water Level (FWL), water saturation increased along a scanned imbibition curve. The objective of this study is to retrace the saturation history of the field using lab-measured bounding capillary pressures. This workflow ensures the correct initialization of the dynamic reservoir model and reproduces the observed field behavior. Drainage and imbibition capillary pressures are available for different rock types (RT), measured under various experimental set-ups (mercury injection, porous plate, centrifuge). This study reconciles lab measurements with wireline logs and Dean-Stark data to produce a representative capillary pressure curve for each RT. Next, the structural deformation history is representedas a series of elementary geometric transformations (localized subsidence and global translation) to restore the reservoir in its pre-deformation state. Wireline log saturationsare matched to capillary-based water saturations by adjusting the present day free water level (FWL) and the change of FWL due to seepage. The dynamic model is then initialized by enumeration with the original water saturation and let to equilibrate for 40,000 years. The fluid redistribution and pressures are then monitored to confirm that equilibrium has been attained. This equilibration step ensures that the fluids are at their correctstate of relative permeability and capillary pressure at the start of simulation, something that is not garanteed in the case of direct enumeration of the final saturations. The implications of such procedure on the dynamic behaviorare explored by simulating 50 years of production history and compa. This study greatly improved the saturation modelling by moving from synthetic porosity-bin functions to physics and texture based capillary pressures. The proposed workflow enhanced the history-match quality and reproduced observed field behaviors such as the high water-cut development in the Northeast. A tilted OWC might increase the in-place however extracting those resources might prove more challenging in the face of the low oil mobility. The oil below OWC might not be recovered under conventional waterflood methods and would warrant an EOR implementation. In the future, an appraisal well is planned in the Northeast to assess the volume and mobility of the oil below OWC. It is the first time an integrated workflow, combining SCAL and structural geology, is proposed to correctly initialize the dynamic model for reservoirs that experienced a post-migration deformation, hence making the present study unique.
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