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Third EAGE WIPIC Workshop: Reservoir Management in Carbonates
- Conference date: November 18-20, 2019
- Location: Doha, Qatar
- Published: 18 November 2019
1 - 20 of 36 results
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Mimetic Finite Difference Simulation of Multiphase Flow in Carbonate Fractured Media in Presence of Capillary Pressure
Authors N. Zhang and A.S. AbushaikhaSummaryModelling fluid flows in fractured reservoirs is crucial to many recent engineering and applied science research. Various numerical methods have been applied, including finite element methods, finite volume methods. These approaches have inherent limitations in accuracy and application. Considering these limitations, in this paper, we present a novel mimetic finite difference (MFD) framework to simulate two phase flow accurately in fracture reservoirs.
A novel MFD method is proposed for simulating multiphase flow through fractured reservoirs by taking advantage of unstructured mesh. Our approach combines MFD and finite volume (FV) methods. Darcy’s equation is discreted by MFD method, while the FV method is used to approximate the saturation equation. The resulting system of equations is then imposed with suitable physical coupling conditions along the matrix/ fracture interfaces. This coupling conditions at the interfaces between matrix and fracture flow involve only the centroid pressure of fractures, which brings some simplification in analysis. The proposed approach is applicable for three dimensional systems. Moreover, it is applicable in arbitrary unstructured gridcells with full-tensor permeabilities. Some examples are implemented to show the performance of MFD method. The results showed a big potential of our method to simulate the flow problems with high accuracy and application.
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Uncertainty Quantification and History Matching for Naturally Fractured Carbonate Reservoirs
Authors S. De Hoop, D. Voskov and G. BertottiSummaryCarbonate reservoirs host a major part of the world’s hydrocarbon reserves and over the past decade(s) have shown an increase in geothermal potential all over the world. However, naturally fractured carbonate reservoirs (NFR) contain a large uncertainty in their flow response and mechanical behavior due to the poor ability to predict the spatial distribution of discontinuity networks at reservoir-scale. In this work, we present a potential workflow for performing uncertainty quantification and data assimilation in fractured carbonate reservoirs. This workflow consists of a pre-processing step in which the original fracture network is cleaned and can be represented at the desired discretization accuracy. This method can then be used to transform a high-fidelity ensemble of models to some coarser representation. This coarser representation can be subsequently used to determine ensemble representatives. Finally, a history matching routine can be performed on each ensemble representative which characterizes the main flow patterns present in the NFR.
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An Image Is Still Worth a Thousand Words: Heterogeneity Analysis Using Electrical Images, CT-Scans and a Revisited Methodology
Authors S. Finlay, A. Abu El Fotoh and C. MaesoSummaryCarbonate reservoirs commonly exhibit a variety of heterogeneities that can complicate ERD waterflood developments. One such heterogeneity that is commonly observed in carbonate reservoirs is the occurrence of diagenesis where varying degrees of cementation and dissolution can result in complex pore throat systems with varying proportions of primary and secondary porosities. The variability in pore throat systems can result in large variations in permeability and therefore have significant impact on the success of a waterflood development. Therefore characterizing the type of porosity and quantifying the types of porosity observed in the reservoir can lead to significant improvements in permeability prediction, reservoir characterisation and reservoir performance. Classical methods of porosity evaluation through traditional resistivity and neutron-density logs usually lack the vertical and azimuthal resolution to address such complexities in the internal rock fabric variability, and therefore accurate permeability predictions and reconciliation with production data remain elusive.
In this case study we present the application of a revisited methodology for the characterisation and quantification of porosity types in heterogeneous reservoirs using borehole images, and whole core CT-Scans. The strength of the study is the iterative approach across multiple cored wells with advanced data acquisition, improving the confidence of propagation to uncored wells.
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Structural Constraint with Integration of Horizontal Well Information and Advanced Seismic Imaging in Carbonate Environment
Authors L. Bovet, G. Mueller and A. VacheyroutSummaryThe integration of horizontal well information is offering a unique dataset for structural calibration in Al-Shaheen field.
New workflow to integrate seismic information using Depth Imaging technic show promising results as capturing geological heterogeneities in the overburden resulting in an improved structure.
Better structural maps are of great interest for Al-Shaheen developpement: it ensures more realistic gelological model with less uncertainties. In particular, the identification of possible local structure that could be gas bearing.
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Lithofacies Interpretation through Capillary Equilibrium Analysis in the Transition Zones
Authors D. Guérillot and J. BruyelleSummaryThe characterization of lithofacies along wells is the first step before considering generating geological models. In this paper, a method to improve the well characterization in term of lithofacies is presented. This approach based on the relationship between capillary pressure and saturation associated with each lithofacies allows characterizing the lithofacies automatically along wells in transition zones.
The saturation of fluids depends on the rock lithofacies, the fluid properties, the rock-fluid interactions, and must be calculated in order to satisfy the gravity-capillary equilibrium. From the well log data, the water saturation is assumed to be known. The aim of the method is to identify the capillary pressure curve that satisfies the calculated capillary pressure and the observed water saturation of the cells along the wells. The first step consists of calculating the pressure of each phase in the reservoir. From the pressure of each phase, the capillary pressure Pc is deduced. The lithofacies associated with the capillary pressure curve closest to the point [Sw, Pc] is assigned to the cell.
An application on the Brugge Field is presented.
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Application of DFT in Iron Sulfide Scale Removal from Oil and Gas Wells
Authors A. Onawole, I. Hussein, M. Saad, M. Ahmed and S. AparicioSummaryScale formation including those formed by iron sulfides have been a major hassle in the upstream sector of the oil and gas industry for many decades. Iron Sulfide scales including pyrite (FeS2) and troilite (FeS) often form a precipitate in the matrix formation, tubulars and other downhole equipment in the wells resulting in plant shutdown. Herein, a molecular modelling tool known as Density Functional Theory (DFT) is used to study the binding affinity of chelating agents to ferrous ion, which is the state of iron in pyrite scale. The calculated binding affinity of the chelating agents to Fe2+ increased in the order; GLDA < HEDTA < EDTA < DTPA which correlated with what has been reported experimentally. The number of nitrogen atoms in a chelating agent plays a predominant role in its binding ability. This could give insights on how novel chemicals could be designed which would be more effective and environmentally friendly in iron sulfide scale removal.
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Deciphering Dual Porosity Carbonates Using Multiphysics Modeling and Inversion
More LessSummaryVery often rock physics modeling and formation evaluation are treated as independent tasks. This is attributed to several causes: lack of communication between petrophysicists and seismic analysts (organizational silos), insistence on using simple linear or quasi-linear models in well log interpretation, and lack of core and fluid samples to provide calibrated rock matrix and fluid properties such as salinity, critical porosity, Archie’s parameters, etc.
The proposed multiphysics modeling and inversion algorithm will make use of conventional well logs (sonic, density, and resistivity) to invert for pore-type, porosity, saturation, rock matrix properties, salinity, and other model parameters. The developed multiphysics rock models will assist petrophysicists and seismic analysts to identify and distinguish carbonate’s facies characteristics from well log and pre-stack seismic data.
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Towards a Continuous Near-Real Time Reservoir Fluid Characterization by the Implementation of Advanced Mud Logging Technology
Authors V. Franzi, C. Robert, A. Shoeibi, R. Galimberti, E. Ndonwie Mahbou, B. Zupinov, B. Lambert, F. Bouasla, S. Hamdidouche and M.H. KallelSummaryThe giant Al Shaheen oil field, located within the Qatar Arch, exhibits variation in reservoir fluid properties, for example the oil API gravity ranges from 15° to 35°. The cause of the variability in oil density is believed to be due to multiple charges events ( E.Hoch et al, 2010 ), and the subtle bacterial alteration ( L.M.Wenger et al, 2002 ). Nowadays the field development is challenged to lower quality reservoirs units and in such condition a continuous information of hydrocarbon fluid quality is required.
An example of application in a horizontal well drilled in the Mauddud Formation proves that the monitoring in near real-time of a series of molecular parameters enables the observations of oil quality variations along the well bore.
In the future, the information supplied by the advanced mudlogging could evolve in a more detailed API gravity model, applicable to Al Shaheen field, provided by a sufficient number of downhole fluid samples.
In any case the methodology, also thanks to its synergy and complementarity with LWD, offers a unique data set for geological interpretation and can give a fundamental contribution to the improvement of fluid sampling program and, ultimately, to a reduction of the costs for downhole sampling.
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Quantification of Sublog Heterogeneities and Implication for Optimizing Well Injectivity - Example of a Carbonate Nodular Fabric
Authors C. Perrin, N. Sultana, E. Mahbou, M. Pal and B. MarirSummaryWe present how a comprehensive geological study helped in the understanding the distribution of the heterogeneity in the example of a nodular facies. The result of an in-house workflow based on core CT-scan information provided quantification of the heterogeneities. These results are used to show that oil can still flow, even when logs indicate high water saturation values. The results anticipated by the method were confirmed by well tests.
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Hydrate Surface Area Measurements During Dissociation Using Dynamic 3D Synchrotron Computed Tomography
Authors Z. Jarrar, R. Al-Raoush, K. Alshibli, J. Hannun and J. JungSummaryAvailability of natural hydrates and ongoing rise in demand for energy, motivated researchers to consider hydrates as a potential energy source. Prior to gas production operations from hydrate-bearing sediments, hydrate dissociation is required to release gas into sediments. To reliably predict natural hydrate reservoir gas production potential, a better understanding of hydrate dissociation kinetics is needed. Hydrate dissociation models assume the relationship between hydrate surface area and (hydrate volume)2/3 to be linear due to hydrate sphericity assumptions. This paper investigates the validity of the spherical hydrate assumption using in-situ three-dimensional (3D) imaging of Xenon (Xe) hydrate dissociation in porous media with dynamic 3D synchrotron microcomputed tomography (SMT). Xe hydrate was formed inside a high-pressure, low-temperature cell and then dissociated by depressurization. During dissociation, full 3D SMT scans were acquired continuously and reconstructed into 3D volume images. A combination of cementing, pore-filling, and surface coating pore-habits were observed in the specimen. It was shown that hydrate surface area can be estimated using a linear relationship with (hydrate volume)2/3 during hydrate dissociation in porous media based on direct observations and measurements from 3D SMT images.
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Pore Networks to Characterize Formation Damage Due to Fines at Varied Confinement and Sand Shape
Authors J. Hannun, R. Al-Raoush, Z. Jarrar, K. Alshibli and J. JungSummaryCarbon sequestration in geological formations is in demand for many applications, especially energy production from hydrates. During gas production in a sandy hydrate reservoir, two phase flow and changes in confinement takes place. Nine fully saturated sand systems were scanned three times; before, during and after CO2 gas injection. The confinement pressure was altered, by placing a vertical spring that presses against the upper port of the sediment cylinder. 3D images were analyzed by direct visualization, followed by quantification and pore network analysis. Outcomes demonstrated that shape of sand particles affects how the unconsolidated media will impact the flow, in angular sediments with high confinement pressure, there is more friction between the grains, this results in no dislocations of sand, the fines clog the throats, and more formation damage is noted. In rounded grains with lower confinement pressure, sand grains dislocated; opening large pathways for gas flow; this resulted in lower formation damage. Measures done using pore networks, showed that because of micro-fractures, permeability of the system can increase during hydrate production. This is in contrast to the other systems, where throat sizes shrunk, decreasing the permeability; because of fines migration toward the throats and the small sand grains dislocations.
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A Block Preconditioning Framework for the Efficient Solution of Flow Simulations in Hydrocarbon Reservoirs
Authors S. Nardean, A. Abushaikha and M. FerronatoSummaryThe need of a reliable solution to large numerical models poses an issue regarding the efficiency of the employed linear solver, both in terms of accuracy and computational cost. In this work, we present an analysis on the performance of two families of block preconditioners, properly designed to handle the linearized system of equations that arises from the discretization of flow problems in reservoirs by means of the Mimetic Finite Difference Method.
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Full-GPU Reservoir Simulation Delivers on its Promise for Giant Carbonate Fields
Authors A. Vidyasagar, L. Patacchini, P. Panfili, F. Caresani, A. Cominelli, R. Gandham and K. MukundakrishnanSummarySimulation of carbonate fields presents challenges due to the underlying multi-scale heterogeneities and consequent stiff nature of the flow equations. This paper highlights the principles of a full-GPU (Graphics Processing Unit) reservoir simulator, currently approaching feature parity with traditional CPU-based codes. The approach exhibits fine-grained parallelism beyond that of CPU-based and hybrid CPU-GPU solutions; consequent performance improvements enable modeling of giant carbonate fields with limited computing resources. Additionally, large black-oil models are memory-bound, and GPU bandwidth has shown significant progress with every generational release of new hardware. Performance will keep improving without changes in the code base, which has not been observed with CPU codes in almost two decades.
Computational performance of a full-GPU black-oil reservoir simulator is benchmarked against legacy and modern parallel CPU simulators, for two giant gas and oil carbonate reservoirs. Results for the gas reservoir indicate a ∼7.3x chip-to-chip speed improvement (one GPU vs. to 16 CPU cores), and ∼5.5x for the oil reservoir, both against the fastest reference simulator. These results suggest that full-GPU codes are ready to simulate complex carbonate models of commercial grade, with exceptional performance, which should encourage the industry to pursue research and development efforts geared towards this approach.
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Development of an Advancing Parallel Framework for Reservoir Simulation
Authors L. Li and A. AbushaikhaSummaryIn this work, we develop an advancing parallel framework which is flexible for structured grids, unstructured grids, two point flux approximation (TPFA), multiple point flux approximation (MPFA) and full tensor permeability.
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Modelling Full Tensor Permeability in Fractured Carbonates Using Advanced Discretization Schemes
Authors A.S. Abd, N. Zhang and A. AbushaikhaSummaryNaturally fractured reservoirs (NFR’s) present complex physical flow conditions and form the vast majority of oil and gas reserves in the world, and exhibit complex flow regimes that prove to be challenging in reservoir modelling. In this work, we present the efficiency of utilizing a Mimetic Finite Difference based simulator for discrete fractures to predict hydrocarbon recovery when full tensor permeability is used. The results shed the light on the importance of mapping and realistically representing the highly heterogeneous porous media in the reservoir simulation using full tensor permeability. The orientation of the tensor will help accurately mimic the field conditions for oil flow. Moreover, this approach is powerful and can yield accurate results for hydrocarbon recovery, yet needs to be treated with care. The choice of the rotation axis and the angle for the full tensor permeability construction will greatly affect the flow in fractures and will result in early water breakthrough times in some cases.
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Unlocking the Potential of a Giant Offshore Field through a Phased EOR Program and Pilot Implementation
Authors M. Pal, P. Saxena, M. Albertini, A. Kumar, P. Cheneviere, P. Cordelier and C. PrinetSummaryA phased approach to screening and scaling up EOR trials for a highly complex offshore carbonate field will be presented. The phased approach taken is from screening to pilot and then continuing to a possible field implementation and is unique for the offshore field and its challenges. The cost effective means of executing the trials at different stages of the project are testament to the fact that EOR projects are possible even at low oil prices and in challenging offshore environments.
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Foam Assisted Conformance Control for Offshore Al-Shaheen Field
More LessSummaryA complete laboratory plan is devised to identify the best surfactant formulation, that is, one that shows low adsorption, good aqueous stability at reservoir conditions, and strong foam stability with variations in foam quality, capillary number, water saturation, and oil saturation. We also evaluated surfactant or formulations for hybrid approach where one can create a foam to control conformance and also alter the wettability of the rock from oil-wet to water-wet to enhance foam transport by changing pore wettability to water-wet. The objective of this work is to generate a laboratory data to estimate parameters of a foam model which can then be used to simulate and predict foam performance in reservoir scale simulations. Such a predictive foam model then can be used to optimize injection strategy for implementing foam technology in the field. In this report we will present the initial phase of the experimental work used in identifying the suitable surfactant.
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Capillary Impacts on Recovery: a Core-Scale Study to Predict Residual Oil Saturation for Altered Wettability Systems
Authors M. Abdul Ghani, N. Alyafei, E. Elhafyan, O. Nawfal and H. RabbaniSummaryMultip[hase Flow in Porous Media
Special Core Analysis
Enhanced Oil Recovery
Numerical Simulation
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The Challenge of Carbonate Permeability Characterization: Off Shore Abu Dhabi Field Case Study
Authors F. Elarouci, S. S. Smith and A. Mohamed IguerSummaryAn integrated approach was performed to determine the possible causes of permeability mismatch between cores, logs, wireline formation testers and production tests in this field. Based on logs and core data, the reservoir was subdivided into different layers and further refined using permeability indices from NMR logs. Formation testers with advance measurements were used to evaluate effective vertical and horizontal permeability of a single layer. The production testing covering several layers was used to fine-tune subzone permeability and subsequent flow units.
The results from this study show that permeability given by CCA was somewhat misleading due to physical limitations from core plugging. The detailed core description and well-test data indicate that a significant portion of flow passes through high-permeability (vuggy) sections of the formation that cannot be measured by plugs. A formation tester was applied to check vertical and horizontal permeability in one productive zone.
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Characterizing Flow from Thin Carbonate Formation Integration of Oil Finger Print and Dynamic Data
By S. Al-jazzafSummaryThe complexity and heterogeneity of the thin, tight Mauddud carbonate in the Greater Burgan Field makes it challenging to characterize and develop this formation. In the study reported here, we have taken advantage of substantial advances in production data analysis and oil fingerprinting technology to conduct a more advanced reservoir analysis.
The Mauddud carbonate reservoir is sandwiched between two massive clastic reservoirs, the Wara and the Burgan. The formation is mostly composed of calcarenitic limestone with intervals of 5–10 feet of good oil reservoir. Average porosity is 18% with low permeability ranging from 1 to 10 mD, characteristics which made this reservoir a candidate for horizontal drilling. However past production results have varied significantly among wells, a fact which previously raised the concern that perhaps the well paths of some lateral wells in this carbonate may be inadvertently tagging the adjacent, more permeable, clastic reservoirs. If that were the case, then production from the adjacent clastic reservoir could be augmenting the production from some of the wells intended to be completed solely in the carbonate. Considered in total, the results from previous development strategies for this reservoir did not meet expectations.
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