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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
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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Far and Near Wellbore Fracture Characterization Using High Resolution Borehole Images and Acoustic Imaging
Authors A. Alhammadi, A. AlMershed, H. Al-Khateeb, D. Tiwary, N. Kerrouche and R. BouchouSummaryFar and near wellbore natural fracture systems characterization is key element for the successful exploitation of tight reservoirs, where one of the dominant aspects is permeability. Carbonate reservoirs fracture evaluation is a challenge in terms of type, density, aperture and extension. Borehole image logs, Stoneley permeability analysis, acoustic fracture ID and azimuthal shear-wave anisotropy evaluation from cross-dipole are key technologies in this context. They allow identification of individual fractures and provide information on fracture type, orientation, distribution (fracture density), aperture, permeability and extension. However, the meaning of features observed on image logs is a matter of interpretation at the borehole wall only. This introduces a degree of uncertainty, which may be greatly reduced by integrating other acquired measurements such as acoustic logs, which map the near borehole environment for fractures as well as their extension nature far away from the borehole. Therefore, integration of the two sources of information significantly enhances the benefits of both. While this principle is not new, technological advances in tool design and analysis software capabilities continuously expands the amount of detail that can be obtained.
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Geological Description for Unlocking Potential of Najmah-Sargelu Reservoir in Greater Burgan Field
By B. Al-EneziSummaryThe Najmah-Sargelu are regionally extensive formations extending across Kuwait. The Najmah formation lying above Sargelu limestone is a prolific source rock that has been attributed as one of the key hydrocarbon sources for most of the overlying reservoirs in South-Eastern Kuwait along with the Makhul and Kazdhumi. The Najmah formation in Burgan Field consists of limestones and mudrocks with a set of particularly rich shales at its center, which are potential targets for an unconventional shale play. Within neighboring fields to the west of Greater Burgan, permeable and pervasive fracture networks are present within the Najmah and Sargelu. The presence of these fracture networks connecting the prolific source rock source rock with competent carbonate beds, and with a thick Gotnia evaporite cap rock, form an effective hydrocarbon system that has been developed successfully in the nearby Kuwait fields. The Najhmah shale benefits from having very high TOC and reservoir pressure but has low overall net thickness and porosity that will directly affect the resource density. This play has the most potential along the northeastern part of the Burgan field where intense deformation is most likely to create a permeable and pervasive fracture network capable of delivering significant quantities of oil. This paper involves the subsurface description of two play-types (Najmha Shale and Najmah-Sargelu Fractured Limestone) and their spatial development across the Greater Burgan Field, critical review and comparison of Burgan and analogue data to establish a view of unlocking potential resources in Greater Burgan and develop analogue based views of possible recovery and productivity in the Najmah-Sargelu formation in Greater Burgan. This paper also emphasizes the possibility of exploiting the fractured Najmah-Sargelu play within Burgan and predicts where the play is most likely to be successful.
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Pore-Scale Mechanisms Associated with Permeability Impairment in Porous Media: a Micromodel Study
Authors S. Nishad and R. Al-RaoushSummaryRecently, researchers are attracted towards the gas production from hydrate bearing sediments considering its abundance in marine continental margins and persisting demand for alternate energy. Dissociation of hydrate into gas and water is the preliminary technique for gas production in hydrate bearing sediments. Expanded fluid volume and gas pressure upon dissociation detach the fines from the grain surface and result in pore throat entrapment. Migration of fines associated with gas flow greatly influence the alteration of permeability of the sediment by clogging pore throats in the flow path. A pore-scale visualization study was implemented to provide a clear insight into the actual mechanisms associated with mobilization and clogging of fines during two-phase flow through a microfluidic chip. Carboxylate modified polystyrene latex particles deposited in the porous media were migrated during drainage with CO2 gas. The detachment of fine particles from the grain surfaces was observed and were retained on the new interface; gas-water interface. The images and videos captured during the experiment was helpful in observing additional pore scale mechanisms responsible for permeability impairment in the porous media. Interface pinning, deformation and resistance to coalescence was found to be other mechanisms in addition to pore clogging.
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A Parametric Investigation on the Effect of Rock and Fluid Properties in Upscaling of Spontaneous Imbibition
Authors A.S. Abd and N. AlyafieSummaryScaling spontaneous imbibition (SI) data is essential in understating the behavior of naturally fractured water-driven reservoirs. The efforts of developing scaling groups has been the focus of many studies since 1950’s. In this paper we highlight the outcome of a detailed investigation on the influence of different rock and fluid properties on the quality of the scaling group proposed by Schmid and Geiger. These rock and fluid parameters can have either a direct effect on the scaling law, or an indirect effect through the semi-analytical solution of SI. This analysis will allow us to identify how imbibition assisted recovery curves change with varying physical conditions, and whether the scaling group will hold regardless of the varying range of parameters. Based on our analysis, we notice that the variations in different parameters including initial water and wettability of the studied core did not affect the quality of the scaling group, and the results matched the semi-analytical solution. The results of the work done in this study can be used to produce more experiments with varying operating conditions and compare the outcome against similar numerical models.
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Validation of Steam Injection Mobility Models
By B. SamsonSummaryAn overview of existing models for the steam injection mobility (SIM) in simulating thermal oil recovery processes is presented. On the basis of the analysis of their accuracy, we give recommendations on the application of these models for accurate reservoir numerical modelling. We have established that SIM models with more restricted steam injection from wellbore to reservoir may lead to underestimation of the oil recovery figures.
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A Comprehensive Experimental Investigation of Low Salinity Waterflooding Potential in Qatar’s Carbonate Reservoirs
Authors P. Sagbana, A. Abushaika and O GharbiSummaryQatar’s onshore and offshore hydrocarbon reservoirs are found in carbonate oil fields. The complexity, heterogeneity and wettability of carbonate fields constitute a challenge in oil recovery, leading to low recovery factor. Several improved oil processes have been suggested for carbonates reservoirs but low salinity waterflooding (LSWF) has been at the forefront of recent research due to the success in laboratory and field applications. This work will involve experimental investigation on the potential of LSWF in Qatar’s carbonate reservoirs. An in-depth analysis of the mechanisms, the effect and changes on petrophysical and geomechanical properties in LSWF. Coreflooding experiments will be executed using injection water with modified salinities and potential determining ions. Capillary pressure, interfacial tension and wettability changes will be measured to examine the effect on oil recovery during LSWF. Core samples will be photographed with a micro CT scanner, SEM and XRD analysis will be conducted to monitor changes in petrophysical and geomechanical properties of the rock. The results obtained from this work will provide information on factors influencing an increase in oil recovery in LSWF, a deep understanding of the mechanisms involved in oil recovery and effect on the rock properties. Finally, a design of optimal injection water.
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Overview of Polymers for Improved Oil Recovery Treatments
Authors M. Shamlooh, A. Hamza, I. Hussein, M. Nasser and S. SalehiSummaryHigh water production in oil and gas wells reduces significantly the recovery factor. Mechanical as well as chemical methods are applied to shut-off water productive zones. Crosslinked polymers showed high efficiency to seal off water zones in high permeability sandstone and fractured carbonate reservoirs. Moreover, emulsified polymeric formulations have been introduced for deep profile modification by changing the wettability of the rock and hence allowing selective plugging of water.
The objective of this paper is to overview types of organic and inorganic crosslinked polymers suitable for water-shut off operations for low and high temperatures applications. Furthermore, it highlights the use of reinforcement materials for the developed gel such as nanosilica. Moreover, recent advancement in relative permeability modification using emulsified gels and micro-gels are presented. Finally, factors that affect the performance of the crosslinked polymers are discussed.
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Integrated Approach in Employing Low Salinity Waterflooding in One of the Middle East Carbonate Reservoir
By A. MoazamiSummaryThe feasibility of low salinity waterflooding in carbonate reservoirs are first evaluated through coreflooding tests and relative permeability curves are obtained. Next, the performance of low salinity waterflooding in one of the middle-east carbonate reservoirs is investigated. Finally, the results are compared in terms of economic profits by implementing the concept of net present value. The two-phase relative permeabilities from unsteady state coreflooding data are usually computed using JBN method. In this method, capillary pressures are neglecting. But in this research, a modified method used to calculate oil-water relative permeabilities which included capillary pressures. The economic evaluation of any IOR development strategy is a crucial factor for the success of the development strategy. Having the technical ability to increase the oil recovery by an IOR method is not enough to implement it. The economic feasibility of that method has to be studied before implementation. Beside using capillary pressure data in modified JBN method to obtain the relative permeability curves and a new method for averaging the relative permeability curves in an experimental and numerical calculation, using reservoir management techniques which includes economic evaluation and technical determination implemented in this study.
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A Theoretical Study of Gas Adsorption on Calcite for CO2 Enhanced Natural Gas Recovery
Authors G. Carchini, I. Hussein, M.J. Al-Marri, R. Shawabkeh and S. AparicioSummaryThe adsorption of gas molecules (CO2, CH4, H2O, H2S and N2) on calcite (104) has been studied by means of Density Functional Theory, in order to investigate the molecular characterization of Enhanced Gas Recovery (EGR) processes by CO2 injection.
Results show that the geometries of both the surface and gas were not affected by the adsorption, highlighting the physisorption nature of the process. Water and hydrogen sulphide adsorb the strongest due to hydrogen bonding, while carbon dioxide follows next. Regarding the other gases, nitrogen adsorption is stronger in average when compared to methane, with a certain degree of complexity. In general, all the configurations’ energies can be found in a range of less than 0.4 eV for each adsorbate. Nevertheless, the larger affinity of CO2 in comparison with methane confirms the suitability of CO2 injection for methane release in EGR operations.
The stronger water adsorption compared to carbon dioxide (-0.91 eV versus -0.38 eV) gives a quantitative estimate of the impact of water as impurity. Further investigations need to address this issue, since this aspect could dramatically hinder the application of the whole technique. Coverage studies on methane and carbon dioxide further highlights the affinity of the latter to the carbonate surface.
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Formation Damage by Produced Water Injection in Carbonate Reservoir
By A. RahmanSummaryProduced water treatment is expressive and technically a challenging task. Thus, it is better to reinject produced water into the formation. We have conducted a novel experimental study where we have observed the effects of salinity and temperature on formation damage in carbonate core samples. In future, we will conduct more parametric experiments (suspended solid particle, emulsion and so on) and a mitigation approach will also be proposed.
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Grouping Minimum REV of Porosity and Tortuosity Based on Descriptors of Sand Grains
Authors R. Al-Raoush, J. Hannun, Z. Jarrar, K. Alshibli and J. JungSummaryIn sandy reservoirs, selecting a representative elementary volume (REV) for the pore scale, is essential for predictive upscaling toward the reservoir scale. The porosity and tortuosity of a sand media are used for REV selection. The profile and size of sand grains, forms the voids morphology; as a result, hypothetically the grains size distribution can provide an indication to whether a volume size is representative of the media. Linking voids based characteristics such as tortuosity and porosity, to their solids counterparts like grains distribution; can help in standardizing REVs for rocks and sands. The aim of the study is to use grains size, uniformity coefficient and conformity coefficient; for categorizing the REV of porosity and tortuosity. Synchrotron X-ray micro-computed tomography of 15 unconsolidated sand system was studied. In order to determine the minimum REV of porosity and tortuosity, 20 sub-volumes for each system was generated. Micro tomography was shown to be an effective tool in measuring sand grains and voids space characteristics. REV analysis showed that a bigger size for porosity was always required compared to that of tortuosity. Categorizing sand systems based on the uniformity and conformity indices, was shown to be ineffective for the purpose of REV selection.
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Reactivating Horizontal Wells in Carbonate Reservoir through Integration of Pressure Bore Hole Image Success Case of Greater Burgan Field
By F. AhmadSummaryMauddud Reservoir is characterized as low permeability with moderate to good porosity and variable fracture density. The reservoir can be subdivided into 2 units, lower unit been very tight and lack any oil stains, and upper unit which ranges from 5 to 10 feet of good oil column based on diagenesis process. Ideally horizontal wells were best option to exploit this thin reservoir, but production in Mauddud wells results varied a lot due to tight rock and low-pressure support. This decline is associated with high GOR, wells that shut in for some time reveal later to flow back to production. A study been carried out to review opportunities in over 20 horizontal wells to revive these wells thru integration of dynamic data with static data and utilizing latest new technologies in the industry. A thorough geological study integrating all the available data was carried out initially. Wells were screened for stimulation by using various proven new technologies. Acid Frac, multi Stage Frac, near wellbore acid-jet and Matrix Acid techniques have been applied with varying results. Advanced placement technique like distributed temperature profiling was used in some of the jobs.
This paper presents the details of the application of the above mentioned technologies, to the candidate wells and discusses the results. The success of some of these technologies opened up new opportunities for a new beginning to revive the closed wells completed in Mauddud Formation.
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Comparative Analysis of ML Classifiers in an Imbalanced Facies Distributed Data from a Libyan Carbonate Reservoir
Authors T. Sager and W. Ben SalehSummaryIn petrophysics, machine learning has been used extensively as an alternative approach to conventional methods to classify rock facies based on available well data. This is generally because conventional methods involving visual examination of cores and assigning facies manually is a tedious and a time-consuming process. Nevertheless, most ML classification algorithms accuracy is reduced when the classes to be classified are not represented equally in the dataset i.e. the problem of imbalance.
In this paper, we compare the performance of five machine learning classification algorithms using an imbalanced data set where two facies types dominate the dataset model selection is carried out first then algorithms are compared using cross-validation concept and finally best performing models are investigated further and compared in terms of prediction accuracy using the same data set.
It is concluded that in an imbalanced dataset, all the four classifiers perform slightly similar at their default setting and without parameter optimizations. However random forest classifier achieved a higher accuracy and precision than the other tree algorithms and it is more efficient in prediction facies classes in our case.
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4D Seismic Integration with Reservoir Mapping While Drilling (RMWD) for Reservoir Heterogeneities Characterization (Al Shaheen Field)
Authors G. Berthereau, S. Finlay and M. ViandanteSummaryReservoir Mapping While Drilling was run into an Al Shaheen water injector suffering from poor sweep efficiency in order to evaluate saturations changes at and away from the borehole and assess the planned recompletion strategy. The data interpretation suggested high degree of heterogeneities along the well borehole with alternating zones of interpreted sweep and limited/no sweep. The zones with interpreted sweep present different signal distribution: transitional / stripy.
4D seismic hardening (interpreted as Sw increase) is relatively well aligned with RMWD interpretation suggesting asymmetrical injection along well bore and the impact of neighbouring water injector. Integration of the RMWD data with 4D seismic data improves the interpretation of both data sets. If 4D data alone is interpreted, the effect of variable injectivity can be well observed, however the vertical resolution of the data is not high enough to diagnose the causes of the variable injection. If the RMWD data alone is interpreted the pattern can be imaged at high resolution, but could be misleading without the reservoir scale information. The integration with geological information in terms of facies, diagenesis and fault and fractures is critical for all interpretations.
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Effect of SiO2 Nanoparticle Addition on the Filtrate Characteristics of Drilling Fluids Used in Carbonate Reservoirs
Authors A. Kanjirakat, M. Amani, A. Carvero and R. SadrSummaryOne of the ideal characteristics for a drilling fluid suitable for drilling in carbonate reservoirs would minimize the amount of the filtrates entering into the reservoir formation. Incorporating nanoparticles into the drilling mud is expected to improve this functionality. The effect of nanoparticle addition the filtrate characteristics of a water based muds that are typically used for drilling in carbonate reservoirs are studied in the present work. The filtrate volume, dry and wet weights and thickness of the filter cakes are measured to evaluate the filtrate characteristics. A water based mud with a mud weight of 12ppg is used as the base mud for comparing the results. SiO2 nanoparticles are added to the base mud, and standard fluid loss studies at 250oC and differential pressure of 1200 psi is conducted. The addition of SiO2 nanoparticles is observed to be beneficial in reducing the fluid loss mainly when used with a 10μm pore disk. An increase in nanoparticle concentration is observed to increase the filter cake thickness and to have reduced the porosity of the filter cake.
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New Insights from 10-Years-Stored Plugs Improve Log Water Saturation Estimation in a Tight Carbonates in Libya
Authors W. Ben Saleh, T. Sager and M. AltownsiSummaryThe Garian reservoir is a low porosity, low permeability, locally fractured carbonate reservoir consisting mainly from limestones and dolomites. Log water saturation throughout the reservoir is highly uncertain and does not compare well with core water saturation. It is thought that the resistivity measurements conducted on few plugs cut from the first well drilled and used for evaluation are not adequate, and that the derived Archie parameters are somehow biased.
It is necessary, therefore, that new resistivity measurements are acquired from a different well to calibrate and improve log water saturation. However, all fresh plugs cut from the newly drilled wells have been damaged and only plugs from a well drilled in 2008 are available.
The main objective of this work is to check whether the plugs stored from the well drilled in 2008 are still fit for resistivity measurements (by comparing 2008 CCA data with the newly acquired ones), and if so, perform resistivity measurements at reservoir conditions, derive new Archie parameters and use it to see if log water saturation can be calibrated and/or improved.
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