bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fracture System in the Carbonate Reservoirs of Abu Dhabi: Implications for Field Development
Authors: Sirat Manhal , Sembiring Edison , Al-Hammadi Mohamed I. , Baguenane Boussad , Elbekshi Amer 
Published: September 2013

Abstract
Characterization of fractured carbonate reservoirs aims at delineate and constraint various data entries to help providing realistic model, which ultimately can be used to predict reservoir dynamic behavior in the near- and far future, hence helps field development planning. In the structurally complicated and highly faulted SE Abu Dhabi region, two hydrocarbon Fields (A and B) are currently under development. We aim at characterizing the fracture system in this region by integrating both direct and indirect data sets to avoid possible early water cut by the existing seismic faults and to help increasing the productivity by the existing relatively short fractures associated with these faults.
In this paper we extensively used seismic attributes analyses including curvature, discontinuity and semblance to characterize the seismic fault system in SE Abu Dhabi. We also incorporated the available well data including FMI, CMI and geomechanical data such as elastic and mechanical properties and stress profiles to characterize these seismic faults with their associated sub-seismic fractures. Further, we used basic structural assumption of the regional paleo- and current stresses together with the in-situ stresses to help estimating the potential openness of these fractures over geologic time.
Results reveal that the SE Abu Dhabi has two regions with different structural settings; an eastern region wherein the two Fields exist, and a central region to the west. The eastern region close to the border with Oman is characterized by relatively high deformation, which has resulted in more intense folding in a highly elevated terrain, and faulted with two prominent conjugate-like fault sets; N75W and N45W. The central region is characterized by low elevated terrain comprising gentle folds and the existence of a prevailing N75W fault and less dominant N45W faults. In both regions these seismic faults are segmented laterally and vertically with the existence of several relay-ramps and small scale flower structures with limited fault throws forming numerous undulations.
The significance of these results is that the development planning has been mainly governed by the existing fault patterns in both regions, where seismic faults with their associated fractures control placement, length and direction of the new planned horizontal wells. It is recommended to place the horizontal wells in the NE direction for well stability and production improvement. The horizontal wells in this direction should be placed relatively away from aquifers both vertically and laterally to avoid early water-cut. The presence of the flower structures, which can be valuable exploration targets, may need different well design for development.
Integration of Permeability Derived From Well Pressure Transient Analysis To Improve Prediction Model Permeability In High Heterogeneous Carbonates Reservoir - Case Study-offshore Abu Dhabi, UAE.
Authors: Khemissa S. RG-Hocine , Lesage P. E-Alexander , Ahmed Akram P. E-Fazeel , Draoui T. L-Elyes , Nakamura T. L-Shinichi , Al-Alyak Abass , Walia Samir , Das Surya 
Published: September 2013

Abstract
The main objective of this study is to enhance a Predicted Permeability (K_Pred) by integrating Permeability resulted from the interpretation of more than 100 P.T.A. Initially the predicted permeability was generated using neural network method (Combining core and log data) over all 254 wells penetrating the reservoir.
To achieve this task a number of workflows have been discussed and tested and finally two methods were implemented which resulted in two permeability models.
The first model, consist of generating enhanced permeability maps for each porous zone using Permeability Predicted (K_pred), core and well test data. These maps were used as multiplier in Upscaled model to generate the total permeability then exported to reservoir engineer for simulation.
The second model, consist of generating the enhanced permeability by integrating Permeability Predicted (K_pred), core and well test (KH) under each well (Log scale) in order to capture the dynamic changes of the property. This enhanced permeability was populated in geological model using stochastic methods conditioned to Rock Type and porosity.
A System of Key Performance Indicators in Intelligent Fields
Authors: Temizel Cenk , Dursun Serkan , Purwar Suryansh , Hancioglu Baris 
Published: September 2013

Abstract
The vast amount of historical and real-time data in intelligent/smart fields can be used to make efficient decisions for improving field production. However, large volumes of data may not necessarily result in high-quality decisions, especially when uncertainty exists in the field development. In this paper, a decision-making approach that can be applied to the problems related to key performance indicators in intelligent/smart fields is presented. The proposed system involves two novel indices, well present performance index (WPPI) and well future potential index (WFPI), which integrate the present and future performance, value, and contribution of each well (production and injection) in the intelligent field. WPPI is an indicator of how the well is performing currently, and WFPI determines the future value of the well to help make workover or shut-in decisions. WPPI and WFPI offer more global solutions, while known key performance indicators focus on field-, pattern-, or well-level analysis. The proposed system can rank the wells in the field using a digital oilfield workflow which automates the decision-making process and helps reservoir management. The main issue in using multiple attributes or performance indicators is the dependency of the attributes on each other and the low-degree representation of the significance of each attribute. As parameters are not ‘mutually-exclusive’, it becomes difficult to avoid using correlated attributes. The exclusiveness and significance of each attribute or indicator together with varying engineering judgment make the automation more difficult. It is challenging to standardize engineering judgment, but automation might be more clear and applicable with a method that tries to simplify a multivariate ranking problem.
Using 4D Seismic to Validate the Geomodel for the South Arne Chalk Field
Authors: Lüthje M. , Stokkendal J. , Lindelow-Marsden C. C. , Johansen K. , Jensen L. J. 
Published: September 2013

Abstract
The South Arne chalk field is located in the Danish sector of the North Sea. It is a double-dipping anticline extending 12½ km by 3½ km. Production started in the summer of 1999 using horizontal wells and water flooding with a cumulative production to date of 141 MMbbl from the two oil bearing intervals: Maastrichtian (Late Cretaceous) Tor Fm and Danian (Paleocene) Ekofisk Fm.
3D seismic was shot in 1995 (pre-production), in 2005 and in 2011. The matrix permeability of the field is low but greatly enhanced due to natural fractures. Based on the 2005 seismic interpretations a geomodel was built with emphasis on capturing the permeability enhancement due to the occurrence of fractures. The modelling was done using discrete fracture network (DFN) modelling. Fracture density was calculated based on various attributes and the outcome calibrated to well test data. Calibration was performed using full field adjustments on fracture properties enhancing predictability in less data dense areas. The model has been history matched to production data with a good overall result. The seismic shot in 2011 was compared to pre-production seismic data giving valuable information about unswept areas and water cutting as well as differences between the two reservoir intervals. The 4D data also shows that the faults have significant influence on fluid flow as modelled in the geomodel. Using fluid substitution modelling, the strongest signal is expected to come from changes in Sw. Comparing the observed changes from 4D seismic to the history-matched modelled changes in Sw, from pre-production to 2011, a very good match is found, thus validating the geomodel.
Quantifying Gas Saturation with Pulsed Neutron Logging—An Innovative Approach
Authors: Al-Nasser Mamdouh N. , Ma S. Mark , Al-Mushrafi Nedhal M. , Al-Muthana Ahmed S. , Riley Steve , Geevarghese Abel I. 
Published: September 2013

Abstract
In reservoir surveillance, gas saturation is routinely monitored both in gas reservoirs for reservoir performance and in saturated oil reservoirs to prevent gas coning or to optimize infill drilling well placement. This paper presents a new pulsed neutron technology and method that enable the quantitative monitoring of the gas saturation variations to address these reservoir management issues. One of the key features of the newly designed pulsed neutron tool is the new type of Lanthanum Bromide (LaBr3) detectors. The extra-long spacing of the far detectors provides a larger volume of investigation that is more representative of the actual reservoir condition. The quantitative aspect of the measurement is achieved by using the ratios of the detector counts, so that the rock matrix effects are diminished, as opposed to the traditional sigma measurement, which can be influenced significantly by the rock matrix properties. This new tool and data interpretation methodology have been tested in both clastic and carbonate reservoirs with encouraging results. This paper presents an overview of the technology and some field application examples.
The use of Geophysical Data in MPS Facies Simulation in a Seismically Tuned Reservoir - a new approach Based on the Direct Sampling Algorithm
Authors: Kombrink H.. , Lallier F.. , Vignau S.. 
Published: September 2013

Abstract
A relatively new Multiple Point Statistics algorithm, Direct Sampling (DS), has been tested using a turbidite lobe succession as an example. A seismically derived probability cube was used as auxiliary data. The results show that the combination of low resolution auxiliary data (reservoir is seismically tuned) and a high resolution training image produces geologically realistic reservoir facies geometries. It is shown that it is convenient to use the reservoir grid as a training image, which is an efficient way in order to achieve a reliable correlation between facies in the training image and auxiliary data. Since the training image is highly non-stationary, only the realisations obtained when applying a high weight (&gt;0.4) of the auxiliary variable can be appropriately used. Simulations produced by the IMPALA algorithm are less convincing, which leads to the conclusion that it is recommendable to use DS in similar cases.
Use of Well Test Interpretations to Constrain the Small Scale Petrophysical Anisotropy (kv/kh)
Authors: Wigniolle Eric , Massonnat Gerard 
Published: September 2013

Abstract
A recurrent issue when performing an up-scaling workflow is to assign representative values for the small scale petrophysical anisotropy ratio kV/kH. Most of the time the data provided by the plugs is not appropriate due to the absence of vertical sampling or to problems of representativeness. Where plug data is available kV/kH ratios are often found to be close to one, a value too high to be realistic when considering geological heterogeneity at small scale.
A methodology is proposed in order to give more appropriate ranges of values for the small scale permeability anisotropy ratio (kV/kH) as an input during the up-scaling workflow. When a well test with partial penetration interpretation is available, it is possible to use the large scale anisotropy ratio Kv/Kh obtained from spherical flow equations and thus constrain the small scale anisotropy ratio kV/kH.
The approach consists in: 1) building a fine scale grid whose size is consistent with the well test investigation radius, 2) populating the grid with facies and petrophysical characteristics observed at the well, and 3) up-scaling the fine scale grid so as to compare the upscaled anisotropy ratio Kv/Kh with the one derived from the well test interpretation.
The method was successfully tested on different field cases in turbidite and carbonate environments. Reference values of kV/kH ratios associated to facies have been determined and can be used, as an initial starting point during the up-scaling process. Guide lines for matching the parameters are also provided.
Thin Beds And Cut-Offs: A Probabilistic Approach For An Improved Assessment And Modelling Of The Net Porous Volume
Authors: Clavel J. , Ruelland P. 
Published: September 2013

Abstract
The objective of the work was to improve the knowledge and understanding of sedimentary facies which consist of thin beds, the impact of the cut-offs, and to improve the coherency and quality of 3D models.
Applying a cut-off consists in defining a threshold value on one or more logs to separate the reservoir intervals in which hydrocarbons are mobile from the gross rock thickness. In a thin beds context, this deterministic approach is insufficient because of the resolution of the logs and a limited number of data. The probabilistic approach considers that the relationship between the cut-off value on the selected log and hydrocarbon mobility in the sandy laminae is a statistical function.
The method is adapted to alternating sand-shale thin beds that have not undergone extensive burial, and has been applied to reservoirs in a turbidite depositional context. In such environment, the cut-off on the VClay log is the most discriminating.
The process of upscaling petrophysical properties is performed for each facies using two cellular mini-models. One is built at log resolution; the second at the scale of the cells in the reservoir model. The cut-off is applied in the log-scale mini-model using a probability function on VClay. The upscaling process provides distributions and correlation transforms for PHIE, NTG and PHIEnet which can be then used to populate the reservoir model. Transforms and Mean values differ from those obtained using a deterministic cut-off as the latter tends to underestimate the reservoir volume in shale-dominated thin bed facies and overestimate reservoir volume in sand-dominated thin bed facies.
Geostatistical Modeling with Seismic Characterization of Wara/Burgan sands, Minagish Field, West Kuwait
Authors: Al-Anezi K. , Kumar S. , Ebaid A. , Bonnel A. , Lucet N. , Lecante G. , Ortet S. 
Published: September 2013

Abstract
The Minagish field covers an area of 90 km2, located in south-western part of Kuwait in onshore position. The studied Cretaceous Wara and Upper Burgan reservoirs, deposited in fluvio deltaic environment (clastic rocks), consist of vertically stacked sands with extensive lateral facies variation. Lower Burgan sands are more significant and blocky in nature with little variations in their properties. Reservoirs geometry, their heterogeneities and structural setting are the key issues for the development of the reservoirs.
The geostatistical methodology used to simulate a high-resolution geological model representative of the reservoir heterogeneity will be described in this paper. The paper will particularly discuss the techniques used for the integration of seismic attributes to constrain the facies modeling, as well as a nested simulation workflow for a realistic representation of heterogeneities.
The three dimensional structural grid was classically based on the seismic interpretation (faults and horizons) and the well correlations. Facies simulation was performed using PluriGaussian functions approach in a non-stationary frame based on vertical proportion curves (VPC) matrix. The distribution has been done separately in three zones: Wara, Upper Burgan and Lower Burgan. For Wara and Upper Burgan zones, nested simulations were used. The lithology (sand or shale) was simulated in a first step, under the constraint of proportion facies maps extracted from seismic data. In a second step, the depositional environment facies were simulated in the sand lithology. These simulations were based on two Gaussian functions to better integrate the various orientations of the different deposits, and their complex spatial relationship. For the Lower Burgan zone, because of the very low variability of the sand proportion, a stationary facies simulation was run, using a truncated Gaussian algorithm.
Eventually, the paper underlines the capacity of the PluriGaussian Simulation approach to realistically mimic sedimentary bodies, and to easily incorporate seismic derived information.
Combining Unstructured Grids, Discrete Fracture Representation and Dual-Porosity Models for Improved Simulation of Naturally Fractured Reservoirs
Authors: Maier Christine , Geiger Sebastian 
Published: September 2013

Abstract
Commonly, dual-porosity and dual-permeability models are employed to simulate naturally fractured reservoirs (NFR). Recently, dual-porosity models have been extended to include more than one transfer function per simulation grid block. These so-called multi-rate dual-porosity models (MRDP) hence allow for more than one set of rock and fluid parameters to be present within one grid cell, which captures the natural variability in fracture, matrix, and fluid properties more accurately. Discrete fracture and matrix (DFM) based simulators have recently emerged as an alternative in NFR simulation. They use unstructured meshes to model large-scale fractures, fracture corridors, and faults explicitly but cannot represent small-scale fractures because field-simulations would become intractable, even with parallelisation.
In this paper we demonstrate a combined MRDP-DFM approach for the first time. We demonstrate how the MRDP-DFM approach can be discretised using unstructured (tetrahedral) meshes. This facilitates the partition of the geological model into regions where (1) large-scale heterogeneities such are fracture corridors are modelled by the DFM method with appropriately upscaled single-porosity properties and (2) the flow through small-scale fractures is modelled using MRDP method with a distribution of transfer function and effective fracture permeability tensors coming from classical Discrete Fracture Network models.
We use a suite of proof-of-concept simulations to demonstrate that our MRDP-DFM approach yields more realistic forecasts of oil recovery due to gravity drainage and imbibition in fractured reservoirs because it allows us to represent the multi-scale heterogeneities inherent to NFRs more realistically. It hence predicts recovery processes more accurately compared to standard dual-porosity models and more efficiently compared to standard DFM models.
Multi-Objectives Constrained Waterflood Optimization in Tight Carbonates
Authors: Khan H. , Saputelli L. , Carvajal G. A. , Ranjan P. , Wang F. , Knabe S. 
Published: September 2013

Abstract
Production from low permeability carbonate reservoirs is commonly supported by the waterflood (WF) process. Despite decades of research and field experience, oil recovery expectations in carbonates typically remain low due to factors such as high permeability streaks, poor microscopic sweep efficiency, and low mobility ratios, all of which can dramatically impair oil recoveries. Vast amounts of remaining oil-in-place have led operators to analyze opportunities to improve WF management and production.
This paper presents an approach to increase recovery and improve performance indicators in a low permeability carbonate reservoir. The main objective of this effort is to maximize short-term oil rates and long-term recovery while honoring target constraints on voidage-replacement ratio (VRR), reservoir pressure, sweep efficiencies, and production and injection rates. In essence, our approach seeks optimum WF solutions by coupling a full-field reservoir simulator with an adaptive, simulated annealing optimization engine.
Predefined scenarios impose hard constraints on production and injection rates, field conditions, and well operating constraints. Voidage replacement ratios (VRR) and nominal pressure (Pn), volumetric sweep efficiency (Evol) and displacement efficiency (Ed) are soft constraints used to calculate design feasibility. Reservoir recovery and displacement efficiency performance indicators are pursued at different levels in the optimization loop. The outcome is that the following month's operational decisions are suggested by the optimizer. This paper describes how this optimization methodology provides improvements in short-term production rates of about 10–20% while enhancing oil recovery between 1–8%. This paper also discusses additional strategies to further improve oil recovery expectations using this automated workflow as the foundation.
Optimized Modeling Workflows for Designing Passive Flow Control Devices in Horizontal Wells
Authors: Gurses Sule , Vasper Adam 
Published: September 2013

Abstract
The benefits of horizontal wells from both a production and reservoir characterization perspective are well known1,2,3. With the benefits however come several challenges, usually concerning uneven production or injection profiles. Interval Control Device (ICD) completions have become popular as a method of addressing these problems controlling fluid flow between the reservoir and wellbore or vice versa in horizontal wells4,5,6. Most ICD devices are passive or fixed once installed downhole, making the design process of these completions very important.
This paper describes the elements of the design for ICD completions and workflows that integrate them within an easy to use software environment. The objectives of the completion are discussed and how to deal with potentially contradictory requirements. The advantages of using 3-D reservoir simulation versus static modeling are listed and workflows making 3-D dynamic methods faster and more accessible explained. The most common ICD design strategies are associated with the reservoir challenges they can address and the quality of the data required. Workflows are introduced for building fit-for-purpose simulation models depending on the data and time availability, and the reservoir challenges being faced. Finally, optimizers are discussed as an aid to ICD completion design.