bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of a Variable Shape Distribution (VSD) Model to Populate Reservoir Properties in Tight Fractured Reservoirs for Numerical 3D Modeling
Authors: Aguilera R.. , Vargas J. Ramirez 
Published: October 2013

Abstract
The importance of unconventional resources is increasing every day. In Canada, unconventional gas accounts for an estimated 34% of the total gas production. In the United States the estimate is 54%. And we anticipate that the contribution of unconventional resources throughout the world will become significant in decades to come.
Most unconventional reservoirs are naturally fractured and also need to be hydraulically fractured to attain commercial production. Different authors have concluded that both, natural and hydraulically induced fractures make these reservoirs stress-sensitive causing various problems for modeling, such as poor history match and inaccurate forecasting. The solution to this problem is coupling the reservoir model with a geomechanical model, to take into account the changes in porosity and permeability due to changes in stresses during the life of the reservoir.
But inputting natural fracture data accurately in the simulator at different scales is challenging. Thus the objective of this study is the use of a variable shape distribution (VSD) model, which has never been utilized in the past in reservoir simulation, to build a more rigorous static model with a view to improve history matching, production forecasting, and modeling of tight fractured reservoirs. While other statistical models are not capable of fitting the whole scale spectrum of fracture properties without truncating the data, the VSD fits the complete set of non-truncated fracture data with a coefficient of determination (R2) of at least 0.97. This improves reservoir characterization and geostatistical modeling. Although application of the method concentrates only on a tight gas formation of the Western Canada Sedimentary Basin (WCSB) the workflow is presented in detail so that it can be reproduced in other tight naturally fractured reservoirs around the world.
It is concluded that the proposed methodology represents an improvement over previous approaches as the complete distribution of matrix and fracture properties, from very small to very large scales, is taken into account without any truncations. Results lead to proposals for drilling horizontal wells in areas of more intense natural fracturing.
Complexity Reduction of Multi-Phase Flows in Heterogeneous Porous Media
Authors: Ghommem Mehdi , Calo Victor M. , Efendiev Yalchin , Gildin Eduardo 
Published: October 2013

Abstract
In this paper, we apply mode decomposition and interpolatory projection methods to speed up simulations of two-phase flows in highly heterogeneous porous media. We propose intrusive and non-intrusive model reduction approaches that enable a significant reduction in the dimension of the flow problem size while capturing the behavior of the fully-resolved solutions. In one approach, we employ the dynamic mode decomposition (DMD) and the discrete empirical interpolation method (DEIM). This approach does not require any modification of the reservoir simulation code but rather postprocesses a set of global snapshots to identify the dynamically-relevant structures associated with the flow behavior. In a second approach, we project the governing equations of the velocity and the pressure fields on the subspace spanned by their proper orthogonal decomposition (POD) modes. Furthermore, we use DEIM to approximate the mobility related term in the global system assembly and then reduce the online computational cost and make it independent of the fine grid. To show the effectiveness and usefulness of the aforementioned approaches, we consider the SPE 10 benchmark permeability field and present a variety of numerical examples of two-phase flow and transport. The proposed model reduction methods can be efficiently used when performing uncertainty quantification or optimization studies and history matching.
Reliable Fracture Characterisation and Value Addition through Special Core Reorientation: Kuwait Case Study
Authors: Alenezi A. M. , Narhari S. R. , Alajmi N. H. , Pattnaik C.. , Rao J. D. , Al-ateeqi K. A. , Saffelbach C.. , Anis Abdel-Hamid , Chakravorty S.. 
Published: October 2013

Abstract
Reliable fracture characterization is essential for efficient field development of tight carbonate reservoirs. A comprehensive campaign of core based fracture analysis was carried out on more than 7,000ft of deep tight carbonate (over 14500ft TVD and 3pu avg. porosity and 0.1 mD avg. perm) cores of Kuwait, spread over a number of wells covering a large area of over 1000sq km.
The aim of the study was to provide inputs for a detailed structural analysis of the area, with the help of reorientation of cores focusing on the geometrical and structural characteristics of each well. The reorientation procedure used a special core Goniometry process, which permits a totally hands-free 3D digitization of all planar and linear features. Reorientation of the cores is established using either the deviation data from the wells or through comparison with image log data.
In addition to the detailed integrated description of type, size, aperture and filling of fractures, a porosity/permeability model was generated after calculation of fracture frequency. By calculating the orientation and value of the permeability vectors, an indication of optimum direction of drilling was established for each well/area.
The natural fracture network obtained with open, partially-open and cemented fractures, together with induced stress-release fractures analysis, contributed to a better understanding of tectonic history and present-day stress in the studied area. A field synthesis map highlighted the main direction of all types of fractures and an actual stress map was worked out by compiling all directions of the maximum horizontal stress observed in the wells and oriented by the petal and centreline induced fractures.
The integration of the results with analyses of image log data, well log correlation data and seismic data provided critical information about the reservoir properties.
Realistic Fracture Conductivity Calculation Using Well Performance Data in Saudi Arabian Deep Gas Reservoirs
Authors: Rahim Zillur , Al-Anazi Hamoud , Al-Kanaan Adnan , Makmun Areiyando , Kayumov Rifat 
Published: October 2013

Abstract
The actual fracture conductivity contributing to gas flow after a proppant treatment is usually much lower than what is reported in the laboratory tests. This is because the ideal conductivity values can be impaired by numerous factors in the reservoir conditions – from high unconfined compressive strength to condensate yield – that cannot be fully captured in the laboratory measurements. Although there are many publications in the literature discussing this issue and software in the industry that predict certain percentage decreases in conductivity due to various reasons, these results are usually specific to certain reservoirs, formations, and laboratory tests and cannot be extrapolated or used for all reservoirs. To understand and compute actual conductivity values in Saudi Arabian gas reservoirs stimulated by proppant fracturing, a new workflow is proposed. The workflow involves using all available data to first calculate the actual fracture geometry using a mass balance and pressure matching. Subsequently, fracture conductivity is computed from another standard method, such as the Cinco-Ley correlation; and using industry software to estimate realistic conductivity values at static and dynamic conditions using closure pressure, actual well performance, and bottomhole flow pressure measurements. A range of fracture conductivity is computed during initial and later periods by matching the well performance data. The calculations show the fracture conductivity achieved after a fracture treatment at reservoir conditions and also how the values change during the production period of a well. Later, correlations relating to productivity increases with reservoir rock and pumping properties can be used to optimize fracture treatments such that a high rate can be maintained after a fracture treatment.
A Horizontal Drilling Breakthrough to Develop the New Resources: A Case Study in Developing the Unexploited Complex Reservoirs from Tarim Basin, West China
Authors: Shi Xiang Hong , Bai Xiang Deng , Qiu Bin , Zhu Yi , Xia Feng Guo , Tan Ping Jun , Li Fei , Chen Lin Jiang , Halomoan Parlindungan Monris , Xu Chong Hui , Wang Yong , Wang Da Hai , Bin Nie Xiang , Fei Wang , Xin Lin 
Published: October 2013

Abstract
Hadexun oil field, located onshore west China, has been in production for over 13 years. Most of the primary oil was produced from relatively thick oil reservoirs. The development plan has now shifted toward the new resources in previously unexploited reservoirs: the ultrathin reservoir with only 0.4 to 0.8 m thickness and the 1- to 2-m low resistivity pay reservoir with an incoherent bottomwater level throughout the field.
A successful drilling strategy was developed that used double-step long horizontal drilling to cover dual thin layers from a single lateral for the ultrathin reservoir and a medium single lateral for the thin low resistivity pay reservoir. An integrated while-drilling application included directional electromagnetic and wellbore imaging technologies for rigorous geological well placement and spectroscopy and sigma for lithology and fluid identification for advance formation evaluation. This integrated application has enabled us to eliminate the need for pilot-hole wells, cover dual layers by single lateral, and avoid side tracks, thus improving efficiency and significantly saving the AFE budget; accurately place the well and significantly reduce the probability of erroneous lateral placement along the thin target layers and avoid drilling into water zone, thus optimizing reserve recovery; optimize the outline of future horizontal drain locations; and economically develop the new resources in previously unexploited reservoirs.
Pore Typing and Use of Capillary Bundles for Porefacies Constrained Saturation Model: A Case Study from Minagish Oolite Reservoir, Umm Gudair Field, Kuwait
Authors: Dutta Dipankar , Banerjee Tapan K. , Al Khalifa Nasser 
Published: October 2013

Abstract
Seventy nine HPMI (high pressure mercury injection) derived saturation height function curves are used to create nine different capillary bundles for Minagish Oolite carbonate reservoir. Each capillary bundle is tied up with its sedimentological and petrophysical attributes to create a discrete pore type/porefacies. The best pore type (Type 0) has well connected pore throat with lesser tortuosity as represented by very low entry point, low irreducible water saturation (Swirr) and wide plateau of the function curve. The worst one (Type 8) is very fine pore throats with high restriction of flow due to high entry point and very high irreducible water saturation. Good porefacies (Type 0, 1 and 2) represent mostly intergranular pore dominated samples, not much affected by subsequent cementation and dissolution. Intermediate pore types (Type 3,4 and 5) are found to have both primary intergranular and secondary solution rich pore spaces. The bad porefacies (Type 6,7 and 8) are either mud dominated or highly cemented rocks with restricted pore spaces. HPMI based poro-perm clusters are also used to create porefacies in the uncored wells and subsequently populated in 3D grid using variogram. Saturation height function of each representative capillary bundle is then used to tie the saturation value of individual porefacies along the well path in more than 250 wells. The newly constructed saturation grid is well tied with specific pore type of each facies and thus suitable to explain the fluid flow behavior within the reservoir. Well wise production behaviour and certain issues of anomalous production rate as well as water cut are satisfactorily explained through this workflow.
A Novel Workflow for Fracture Characterization and Well Placement Using BHI Data in WBM and OBM in Deep Unconventional Reservoirs of North Kuwait
Authors: Acharya Mihira N. , Al-Ajmi Saad A. , Al-Azmi Mejbel S. , Joshi Girija K. , Dashti Qasem , Al-Anzi Ealian H. , Chakravorty Sandeep , Darous Christophe 
Published: October 2013

AbstractThe tight deep carbonate reservoirs of Oxfordian age in North Kuwait consist of tight limestone interbedded with organic rich shale layers. The overall matrix porosity is generally very low and the production is mainly from fractures in the crestal part of main structures. Borehole images are routinely acquired in vertical to moderately deviated wells drilled with oil-base mud for fracture characterization.For detailed fracture property evaluation, a highly deviated pilot hole was drilled with water-base potassium formate mud for the first time across the reservoir section and drill-pipe conveyed high-resolution electrical borehole image data was acquired. The upper half of the interpreted interval showed potential open fractures sets, NE-SW striking fracture set was most abundant. An advanced fracture segment extraction workflow was used to determine porosity and aperture of different fracture sets.The first horizontal well was then drilled as a lateral in the target reservoir with oil-base mud restricting direct computation of fracture properties. The electrical and acoustic images in OBM indicated fracture concentrations at quite a few places along the horizontal well trajectory, the most conspicuous occurring at the zones where heavy mud losses were encountered while drilling. A 2D litho-structural model was constructed along the well trajectories using the dip data and open-hole logs to correlate finer carbonate and organic shale layers and fracture distribution across the layers. This workflow permitted extending fracture properties along horizontal well as well.Finally, a high-resolution 3D structural model was constructed using outputs from previous workflows and data from two nearby vertical / less deviated wells. The final model showed a folded structure, which was absent in the existing model of the field. Thus the innovative workflow provides a means to generate an accurate structural and fracture model for the reservoir, integrating the fracture characteristics of the individual sub-layers with the main fracture corridors.
Application of Seismic Attributes in Estimating Gas Resources in Complex Fluvial Channel Reservoirs
Authors: Al-Duaij E.. , Al-Maraghi M.. , Zaid T.. , Klopf T.. 
Published: October 2013

Abstract
The purpose of this paper is to show the reserve estimation procedures used by KUFPEC on the NW Shelf of Australia production license WA-49-L, which is currently under development as part of the Chevron's Wheatstone LNG project. The gas in the WA-49-L permit was discovered in a combination of structural and stratigraphic traps of a regional fluvial channel sand complex within the Triassic Mungaroo Formation. These channel sands contain gas trapped on a large structural ridge with up-dip terminations below a regional, angular unconformity and overlain by the Cretaceous Muderong Shale. Some of the deeper channel sands are trapped against the bounding fault of the ridge. These channel sands are stacked as a result of amalgamation of numerous channels, with the individual sand thickness of up to 60 meters but typically in the 15 to 30 meters range. These channel sands are discrete with individual gas-water-contacts, and clearly visible on seismic and inversion data as low impedance, Class 3 AVO (amplitude versus offset) anomalies.
The estimation of gas resources is delineated by 20 wells drilled through April 2011 on WA-49-L. Limitations of the seismic frequency content result in channel thicknesses of less than 5 meters not being visible. Seismic inversion attributes are used to estimate gas sand probability, sand thickness and porosity. Rather than using large scale net-to-gross assumptions commonly used in the industry for reserves calculations, KUFPEC used maps of individual sand bodies based on the inversion impedance amplitudes and gas sand probability (GSP) attributes to compute each sands' likely range of resources values.
Improved Desalting of Challenging Crude Slates
Authors: Sellman Erik , Mandewalkar Pavan , Sams Gary 
Published: October 2013

AbstractCrude slates containing a blend of traditional and heavy crude oil are challenging to desalt in most refineries.In addition to the higher crude oil viscosity and reduced oil / brine density difference, heavy crude oil also provides additional challenges in the form of higher crude oil conductivity and solids stabilized emulsions. Blended oils often have a higher solids content which can stabilize rag layers inside the desalters.Many refineries use AC type electrostatic technology operating at line frequency, 50 or 60 Hz. Conventional AC desalters provide limited voltage gradients and are not efficient for treating conductive crude oils.Advancements in electrostatic desalters have resulted in desalters providing stronger electrostatic forces and improved conditions for coalescence of brine droplets.Computational fluid dynamics (CFD) has also provided a better understanding of the oil and brine flow inside refinery desalters, which has lead to the use of improved internals which provide a better fluid distribution, elimination of recirculation areas and allowing higher flow rates at constant BS&W and PTB.More efficient desalting of crude oil in refineries can provide the following benefits: –OPEX:○opportunity to process higher volumes of cheaper opportunity crude oil○reduced volume of wash water○lower operating temperature○lower demulsifier dosage○higher desalter uptime–CAPEX○use of smaller desalters (only applicable for new desalters)○reduced transportation costThis paper describes new enhanced electrostatic desalting technologies, including case studies.
Full Field History Matching For Chemical Flooding With The Adjoint Method
Authors: Douma Sippe G. , Abu-Shiekah Issa , Kindi Zakariya 
Published: October 2013

AbstractEnhanced Oil Recovery is firmly established in the hydrocarbon maturation plans of PDO and Shell with successful ongoing thermal and polymer field developments and many novel methods being piloted. The current developments and trials undergo in-depth study to leverage the learnings for portfolio-wide application. In optimizing a current or derisking a future EOR development, understanding of the reservoir is key and more crucial than during primary and secondary development because of the complexity of the processes and higher costs involved.In this paper the use of an advanced history matching technique for improving reservoir understanding is discussed in the context of full field chemical flooding. A powerful feature of the Shell proprietary reservoir simulator is the availability of the so-called adjoint method which allows history matching of gridblock parameters such as permeability and porosity in an efficient and effective manner. The method is applied in a workflow coined model maturation (Joosten & Altintas (2011)), where the local permeability updates are used to highlight deficiencies in the geological model (e.g. missing faults, aquifer locations, pinch outs).In this particular study the adjoint method improved the pattern match significantly but more importantly revealed the need for fine scale local geological features, confirmed by other data. The improved models describe the observed polymer behavior in line with our theoretical and analytical understanding of polymer flooding. The study showed that understanding EOR processes can only be done after a proper understanding of the reservoir.
Stochastic Optimization of Cyclic Steam Stimulation in Heavy Oil Reservoirs
Authors: Azad Madhar Sahib , Alnuaim Sami , Awotunde Abeeb A. 
Published: October 2013

Abstract
Cyclic Steam Injection (CSS) has been used in the industry to increase the recovery factor and production rate from heavy oil reservoirs. CSS is multi-cycled steam recovery process with three stages and five operational parameters (injection rate and its duration, soak time, production rate and its duration) in each cycle. Determining the optimal values of the operational variables in each cycle, for the existing reservoir conditions is challenging. The difficulty stems from the fact that these parameters cause significant changes in reservoir fluid flow, reservoir behavior and recovery performance during the project duration. Ability to effectively determine the best values of these parameters is expected to increase the recovery efficiency and the profitability of the project.
In practice, the parameters of cyclic steam stimulation are often determined by running limited sensitivity studies on some or all the parameters. Such sensitivity studies are however very limited in scope and cannot explore the entire domain of interest. A more efficient method to estimate the optimal parameters of the CSS is to perform automatic optimization using an effective stochastic optimization algorithm. In this work, we propose the use of stochastic optimization to estimate the parameters of CSS. Three different CSS models were developed with three well types (vertical, horizontal and inclined wells). The operational parameters are extremely interdependent in CSS which has mulitiple drive mechanisms. The need for global search is imperative to find the best operating parameters in each cycle. Covariance Matrix adaption Evolution Strategy (CMA-ES) was used to optimize the operational parameters. The project net present value (NPV) was used as the objective function in the optimization process. Results showed that the NPV can be increased significantly when all the operational variables of CSS are optimized. This signifies the importance of simultaneous optimization of soak time, cycle length and rates. The results also showed that the vertical well model gave a higher NPV than the other two well models. The horizontal well model gave the lowest NPV.