Uncertainty analysis using experimental design and response surface techniques has been extensively used in the field of reservoir simulation. This study outlines an innovative workflow to generate multiple realizations of forward stratigraphic modelling of three Lower Cretaceous reservoirs from onshore Abu Dhabi. Forward stratigraphic modelling is a deterministic technique that simulates basin infill providing a better understanding of vertical and lateral facies distribution and connectivity in sedimentary basins. During the course of forward modelling a variety of environmental and stratigraphic parameters are used. Due to the uncertainties of these parameters it is critical to assess their impact on the development of the basin fill. The experimental design and response surface techniques have been innovatively applied at reservoir scale to enhance the understanding of major controlling parameters on carbonate production and to produce alternative facies distribution scenarios in the study reservoirs. The methodology used in this study was based on running multiple simulations, through varying key input parameters. The best stratigraphic models were then selected based on calibration quality and geological consistency. Calibration quality was assessed by two user defined quantitative functions called Thickness Calibration Indicator and Rock Texture Calibration Indicator. The initial step in the workflow identified uncertain environmental parameters (e.g. eustasy, carbonate production versus depth, carbonate production versus time, wave parameters, gravity and wave transport and erosion rates) from a manually calibrated reference case and ranges of values for each parameter defined based on the knowledge of geology over the area. Latin Hypercube experimental design was then used to define a set of simulations to allow an efficient and uniform sampling of the entire uncertain domain. Sensitivity analysis was then performed on simulation responses (texture and thickness calibration indicators) using the technique of nonparametric Response Surface Modelling (RSM). The influence (quantitative and qualitative) of the impacting parameters on responses was studied to identify the most influential parameters as well as the ranges yielding good calibration indicator values. A further set of simulations was then launched that considered the most influential parameters and their precise ranges. Non critical parameters were assigned with the constant values from the reference case model. These simulations generated a series of well calibrated models. A filtering of simulations with high calibration indicator values and good geological consistency was then performed to choose acceptable multi-realizations. Finally, thickness and texture confidence properties were mapped based on the selected multi-realizations and the reference case. Sensitivity study on three Lower Cretaceous reservoirs from onshore Abu Dhabi successfully addressed the uncertainty associated with forward stratigraphic model input parameters. Sensitivity analysis was performed using Experimental Design and RSM. This was applied to enhance the understanding of the major controlling environmental parameters on carbonate production for individual sequence with each of the study reservoirs.

For a new sour field development, the scheme for crude oil stabilization is designed using condensate as stripping agent in the crude oil stabilizer in place of conventional scheme using sweet fuel gas. The article discusses the scheme and its advantages compared to other industry practice of 'Reboiled Stripper' for Crude Oil Stabilization.The design is based on splitting of gas condensate produced during gas compression in to heavy cut and lights in a condensate splitter operating as a distillation column. The lights are recycled back in to the gas compression for gas injection while heavy condensate is vaporized and used as stripping agent in crude oil stabilizer.The benefits are higher oil volumes with some improvement in oil API achieved through ability to mix higher fraction of the condensate produced in to oil, while maintaining Reid Vapor Pressure (RVP) and Hydrogen Sulphide (H2S) Specifications for oil export.The scheme eliminates light condensates drying and pumping for injection in to reservoir as it mixes it with gas for injection and a common gas drying and compression system can be used for injection in to reservoirs. Also instead of boiling crude at higher temperatures in the reboiler of crude oil stabilizer which is the case for the 'Reboiled Stripper Scheme', clean condensate vapors are used for stripping H2S and light hydrocarbons in crude stabilizer with operations at near 100°C.This will reduce the system fouling while providing higher plant availability by eliminating reboiler from the Crude oil Stabilizer. The estimated Capital Cost is lower in comparison to other schemes.Thus the design gives a simplified scheme for simultaneous processing of condensate with crude oil stabilization, producing oil in quantity and specification similar to the 'Reboiler Option' while providing additional bebefit of lower CAPEX with higher plant availability.

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Natural fractures can have a significant impact on fluid flow by creating permeability anisotropy in hydrocarbon reservoirs. They can also play an undesirable role on reservoir subsidence and compaction during depletion, with important consequences for production strategy and well and surface facility equipment. The investigation of these possible fracture effects motivated a comprehensive integrated fracture study of three reservoirs from a giant gas-condensate field in Abu Dhabi. The main objective of the study was to build representative 3D fracture models and compute fracture properties of each reservoir, to be used in future accurate dynamic simulations. The results of the fracture study were also used to define the risk associated with the geomechanical integrity of the reservoirs. The integrated workflow included several approaches, all contributing towards the global understanding of the fracture distribution and flow impact in the reservoirs. The static fracture characterization involved detailed seismic inversion and fracture characterization, core and borehole image analysis. It focused on the identification of the fracture components occurring in the reservoirs and their geometrical properties and spatial distribution. This was complemented by a study of the well dynamic data (e.g. fluid injection/production data, well tests, flowmeters, static pressure data), carried out to evaluate the dynamic impact of the fractures by identifying wells showing anomalous dynamic behaviors. The integration of static and dynamic data allowed the identification and quantification of which fracture components played a role on fluid flow in the reservoirs. The results of the static and dynamic data analysis were integrated to develop a 3D Discrete Fracture Network (DFN) model of each reservoir, reflecting the fracture organization identified during the characterization stage. The hydraulic properties of fractures (aperture and conductivity) were determined using flowmeter and well test data. The calibrated fracture models were then upscaled as to compute equivalent fracture properties (fracture porosity, permeability tensor and equivalent matrix block sizes or shape factors) to be used in further full-field reservoir simulation models. The results of the study concluded that the reservoirs are dominated by the presence of large scale fracture corridors that were modelled deterministically in the DFNs based on the integration of well and seismic data. There is also a negligible, unconnected small scale diffuse fracturing in the reservoirs, with no flow impact. The fluid production is mainly controlled by matrix support with very limited contribution from fracture corridors. Finally, the very limited fracturing detected suggests no major risk in terms of reservoir integrity. The integrated study carried out allowed the development of accurate, consistent fracture models for the three studied reservoirs. The uncertainty associated with the fractures and their impact was properly addressed, allowing building better field development plans and defining risk-free reservoir depletion strategies.