bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Muhammadiyah’s 47th Congress and “Islam Berkemajuan”
Authors: Ali Muhamad 
Published: September 2015

The Muhammadiyah’s 47th congress or muktamar in Makassar, South Sulawesi, 18-22 Syawwal 1436 H or 3-7 August 2015, had its theme “Enlightenment Movement toward A Progressive Indonesia”. In the opening ceremony, the chairman of the central board, Din Syamsuddin, took the occasion to propose that three of the Muhammadiyah’s leaders, namely Kahar Mudzakir, Ki Bagus Hadikusumo, and Kasman Singodimejo, be recognized as national heroes. President Ir. Joko Widodo has yet to respond to the proposal, but expressed his high appreciation for the Muhammadiyah’s contributions as the enlightenment and progressive movement to the Muslim community and the nation through its schools and universities, hospitals, and others. Joko Widodo pointed to the challenge of the nation’s plurality, and invited participants to continue to give their enlightening contributions to the nation and to the world.DOI: 10.15408/sdi.v22i2.1978
Fractures Relative Permeability and Capillary Pressure Curves - Effect on Thermal Recovery Processes of Heavy Oil Naturally Fractured Reservoirs
Authors: Ghedan Shawket G. , Kumar Anjani 
Published: September 2015

Abstract
It is common practice in modeling of naturally fractured reservoirs, NFRs, to neglect capillary pressure, Pc, and utilize straight line, zero to one, relative permeability, Kr, curves for the fracture network. More often than not, however, reservoir stresses and partial mineralization of fractures render fracture conductivity to remain relatively low for simultaneous ease of flow of two phases. Furthermore, fracture Kr is often found to be lowered by fractures’ tortuosity, and wall roughness. The objective of this study is to expand on the characterization of fractures Pc and Kr data and to determine its effect on the performance of heavy oil NFRs produced under thermal recovery processes.
According to the percolation model1, 2, fracture Kr curves approaches straight line form when gravity segregation forces dominate the capillary forces, producing larger fracture height dimensionless parameters. In heavy oil NFRs, however, smaller water-bitumen density differences coupled with smaller fractures apertures may lead to the need of using non-straight line, physical, Kr curves. This may be associated with non-zero Pc curves. The differences in heavy oil recovery performance, due to physical Pc and Kr curves, was established through Dual Porosity/Dual Permeability modeling of Steam Assisted Gravity Drainage, SAGD, thermal recovery process of a heavy oil NFR.
Fractures' heights and apertures, gas- and water-bitumen density differences, and interfacial tensions would either support the use of non-straight line, physical Kr curves or renders the use of straight line Kr curves to be acceptable. Large density differences between steam and heavy oil supports the use straight-line Kr curves for the gas-heavy oil system, while smaller water-heavy oil density differences supported the use of physical Kr curves for the water-bitumen (heavy oil) system.
Utilization of physical Kr curves revealed appreciable differences in the performance of SAGD process for smaller fracture apertures and relatively minor differences for larger fracture apertures. Straight-line Kr curves gives hot water more mobility in the fractures quickly expanding the steam chamber to contact more matrix rock and recovering more oil in the process. Physical Kr reduces the size of the steam chamber and in turn recovering less oil in the process. This paper presents the details of these results and tries to determine the effect of other reservoir parameters such as the fracture aperture, level fracture-matrix rock permeability contrast, and wettability of matrix rock on the process.
This paper adds value to the effort of proper modeling of thermal recovery processes of heavy oil NFRs through the use of more theoretically and experimentally backed fracture Pc and Kr input data. For some reservoirs, this may make or break certain thermal recovery processes, which may help to avoid wrong economic decisions for some projects.
Modelling Pipeline and Choke Optimization for Improved Gas Field Production using an Integrated Asset Model: A Case Study
Authors: Talabi O. A. , Nitura J. T. , Rodriguez N. J. , Fernandez M. , Choudhary M. K. , Johari S. F. , Hanifiah N. M. , Kumar Ashok 
Published: September 2015

Abstract
A case study modelling pipeline layout and asset-wide choke optimization in a dry gas field of multiple reservoirs is presented. The methodology utilized an integrated asset model (IAM) and lexicographic optimizer with a neural network accelerator to perform production optimization while considering system constraints on the quality of the produced gas blend as well as the effect of significant differences in reservoir pressure on total asset production. The field comprises several gas reservoirs; some are already developed and in production, and others are in development with more wells to be drilled and brought online later. Production from the different reservoir units is commingled as the units tie into a common surface production network. Based on preliminary simulation studies, the commingled pipeline causes production deferment due to backpressure. It was postulated that a dedicated, high-pressure pipeline would be required to mitigate this. The purpose of this study was to investigate if the cost of the dedicated pipeline could be avoided by selectively choking back high-pressure wells to allow lower-pressure wells to flow and assess the incremental recoverable volume is CO2 content in blended gas was optimized.
The first step of the pilot study was to create a representative surface network model that could be coupled to the available subsurface black oil simulation model for two of the fields. A model integration software platform was used for linking the surface to subsurface, and a representative simulation control strategy was input. A custom-built choke optimization logic using an optimizer that honors the CO2 constraints and maximizes gas production up to the asset sales gas plateau target was implemented and triggered every month during the simulation. The optimized simulation generates a gas rate and choke pressure drop schedule per month per well that then can be used to develop a monthly choke set-point schedule. The simulations were run for 12 years.
Based on the results, using choke optimization, the production deferment—cumulative production difference between dedicated pipeline and comingled pipeline—can be reduced by up to 80%, making the choke-optimized comingled pipeline case more economic than the equivalent dedicated pipeline case. In addition, cumulative production can be increased by approximately 34% in both dedicated and comingled pipelines while honoring the CO2 production constraint.
The results of this study demonstrate the potential benefits of choke optimization in the gas field to both increase production by better field management and offset the need for an expensive dedicated pipeline, allowing the field improve its production potential at minimal cost.
Optimization of Production in Slanted Horizontal Wells in Tight Reservoirs
Authors: Temizel Cenk , Purwar Suryansh , Abdullayev Azer , Urrutia Karelis 
Published: September 2015

Abstract
Economic production from tight-oil formations requires the same hydraulic fracturing techniques used during production of shale gas, and the same horizontal well technology is often used. Tight-oil formations are heterogeneous and greatly vary over relatively short distances. Thus, even in a single horizontal drilled hole, the amount recovered can vary, just as recovery within a field or even between adjacent wells can vary. This can make evaluation and decisions regarding profitability difficult. In relatively thinner pay zones, horizontal or slanted wells can be successful in terms of productivity as long as robust reservoir management is applied with well designs that consider both geology and operational control variables. Thus, it is crucial to understand every control and uncertainty parameter to help maximize efficiency and recovery within such systems.
Robust commercial optimization and uncertainty software is coupled with a full-physics commercial simulator that models this phenomenon to investigate the significance of major parameters on the performance of horizontal wells in tight-oil formations.
Slanted wells provide more flexibility and access to pays than vertical wells drilled from the same surface location, which is of more significance in tight formations because of less communication between zones. The results of the study not only confirm this, but also show the increased value provided using slanted wells compared to vertical wells in tight formations. The study also illustrates the significance of each optimization and uncertainty variable in terms of the success of recovery from slanted horizontal wells in tight formations.
The results and sensitivities are compared and discussed considering a comprehensive literature review of recycling gas-condensate reservoirs using different process optimization methods. The significance of all major parameters is outlined using tornado charts to serve as a practical example for optimization of similar future applications.
Compositional Subsurface-Surface Simulation of a Complex Miscible Acid Gas Injection System
Authors: Kathrada Muhammad 
Published: September 2015

Abstract
An integration study on a complex system of several sour oil and gas-condensate fields based in the south of Oman has been conducted. Sour components are removed from the sales gas stream with the resultant concentrated acid gas being reinjected into the reservoirs. Acid gas is highly miscible and improves ultimate recovery from the reservoir. Hence it is imperative to model the separation and injection of this acid gas accurately. The system is further complicated in that there are two surface plants with different reservoirs flowing into them leading to mixing of fluids. Tracking these fluids with time requires a completely integrated model. To this end subsurface reservoir simulation models, the pipeline production and injection networks and the surface facilities have been linked in a closed loop.
The objective of the model is for long term forecasting and development optimisation. It is also a useful diagnostic tool in debottlenecking the system and identifying areas of process improvement. Such large scale detailed complex integration studies can be very time consuming. Getting all the correct data from the respective stakeholders, overcoming software limitations, troubleshooting and optimizing various elements within the integrated model all make for an arduous task. The final result though is a model with all the working elements of the system that stakeholders can modify and interrogate on the whole to better plan and optimize the cluster development from both a sub-surface and surface perspective.
Detection of Bedding Corridors From Open-hole Logs in Vertical Wells and Their Impact on Geomechanical Assessment
Authors: Sirat Manhal , Noufal Abdelwahahb 
Published: September 2015

Abstract
Bedding corridors are sub-horizontal tabular bodies of bedding plane weak zones formed as shear swarms, which vertically divide the entire reservoir thickness and extend laterally as their layers. Bedding corridors are genetically related to shearing along the bedding planes and they contribute to the conductive systems in few Abu Dhabi reservoirs. They can be best identified from horizontal borehole image logs, and as spikes in open-hole logs. Natural bedding corridors can be considered as indicators of the reservoir stress history, where they form extraordinary clusters of a huge number of quasi-parallel shear fractures in a transpressional regime.
In many oil and gas reservoirs, natural bedding corridors networks help drain hydrocarbons and other fluids. The role of bedding corridors is particularly important in reservoirs having a tight matrix. In carbonate formations, for example, it is quite common to observe a permeability contrast of 1000mD or more between the rock matrix and surrounding bedding corridors. In this paper we differentiate between image-log porosity and density-neutron porosity, which is regarded as secondary porosity attributable to fractures. We also introduce here a working hypothesis about their effect on hydrofraccing being part of geomechanical assessment.
Results indicate that the horizontal stress anisotropy (Shmin/SHmax ratio) is the key parameter to predict bedding corridors behavior under different stress regimes. Swapping stresses with depth is common in Abu Dhabi fields, where a strike-slip regime can open and dilate the shear along the bedding planes. It is recommended to opt for horizontal wells hydrofraccing to maximize the intersection of those bedding corridors compared to vertical wells.
The significance of this approach is that once a diagnostic signature can be recognized in open-hole logs, in combination with lost circulation data, it can be used to locate bedding corridors in other vertical wells with no image logs. Geomechanically, these corridors can be used efficiently to increase production particularly in tight and unconventional reservoirs.
Experimental Study of Wettability Alteration during Nanofluid Enhanced Oil Recovery Process and Its Effect on Oil Recovery
Authors: Li Shidong , Genys Mindaugas , Wang Kun , Torsæter Ole 
Published: September 2015

Abstract
Nanoparticle was proposed as a new Enhanced Oil Recovery (EOR) agent for its great potential of increasing oil recovery and wettability alteration was suggested as one of main EOR mechanisms. We conducted a series of core flooding experiments with nanoparticles fluid (nanofluid) as tertiary recovery method. Core plugs injected by nanofluid were performed for Amott test to measure wettability index and showed the effect of nanofluid injection on wettability alteration. During core flooding experiment aged Berea sandstone cores were employed and pressure drop across core was measured, oil production rate was recorded as well. Hydrophilic silica nano-structure particles and hydrophilic silica colloidal nanoparticles with different concentration were utilized in above experiments. The objective of this experimental study is to investigate wettability change of core during nanofluid flooding process and its effect on oil recovery.
The results showed that injection of nanofluid can increase oil recovery, for some cases effect of nanofluid flooding on recovery is quite significate. Colloidal nanoparticles fluid injection didn't affect pressure drop obviously, while pressure drop increased significantly during nano-structure particles fluid flooding, which might be one of EOR mechanisms. Nanofluid flooding can change core to be more water wet and presence of crude oil can affect wettability alteration process by nanoparticles. However, increase of wettability index is independent of nanoparticles concentration.
Detailed Reservoir Characterization for Key Strategies of Unconventional Reservoir Development
Authors: Cui Esther 
Published: September 2015

Abstract
Unconventional resources play significant role with the increasing demand of hydrocarbon. Horizontal well drilling and multiple-stage hydraulic fracturing are the dominant technology required to achieve economical gas flow rates and improve gas recovery. The accurate prediction of well performance is a major challenge, which involves exploration and evaluation of gas reservoir, proper gas reservoir management, well spacing and hydraulic fractured well design, reservoir simulation and completion process, and reservoir specific issue. The identification and evaluation of tight gas reserves and proper production calculation is the priority. Integration of multi-discipline and multi-scale data is important for field development of unconventional reservoir as compared to the conventional reservoirs.
Integration of Microseismic Monitoring and Advanced Production Analysis: A Real Case Study for an Unconventional Reservoir
Authors: Turri F. , Sciortino M. , Brignoli M. , Mantica S. , Rotondi M. 
Published: September 2015

Abstract
The exploitation of unconventional reservoirs requires hydraulic fracturing treatments, aimed at enhancing reservoir rock permeability through the re-activation of existing natural micro-fractures and the generation of new fractures in the near-wellbore area. Microseismic Monitoring (MSM), which consists of acoustic recording of the induced fracturing events, has nowadays become a common approach for real-time tracking of the fracture network evolution.
The present work is based on the analysis of microseismic and production data coming from three multi-fractured wells drilled in a shale gas reservoir. Information derived from MSM is integrated with the Advanced Production Analysis (APA) results, to assess if the MSM interpretations are able to provide preliminary indications about the production behavior of the fractured wells before start-up. The spatial localization of microseismic events and their moment magnitude are derived from the interpretation of the seismic signals recorded by geophones during hydraulic fracturing. Data analysis, based on the cross-plot of the event moment magnitude versus the distance between the event and the nearest geophone, allows the determination of the spatial range bias, i.e. the effect for which the level of the recorded magnitudes depends on the distance from the geophones. A novel methodology was developed to correct the spatial range bias by combing a Gaussian function and the Gutenberg-Richter law for fitting the Frequency Magnitude Distribution. After the correction, microseismic data from different wells and frac stages can be directly compared and used for the evaluation of the Stimulation Efficiency (SE) and the Stimulated Reservoir Volume (SRV).
APA is used to analyze production data from the three selected wells in order to characterize both the fractured system and the reservoir.
Even if the results obtained from MSM and APA techniques are often at different scales and not quantitatively comparable, it is still possible to obtain useful information from their integration. APA confirms, indeed, the interference between wells production due to the overlap of different SRV, as initially estimated from MSM interpretation. Thus, the results of the developed methodology allow to improve well placement, stimulation operation design and field development strategies.
Well Placement Optimization Using Imperialist Competition Algorithm
Authors: Al Dossary Mohammad A. , Nasrabadi Hadi 
Published: September 2015

Abstract
Developing an efficient and optimized field development plan is a crucial and vital task that aims to increase the productivities as well as the recovery factors of oil and gas fields and hence increase the profitability in the most effective manner. In this paper, a novel algorithm has been applied for the first time in oil & gas industry to find the best optimum well location for maximum well productivity. The Imperialist Competitive Algorithm (ICA) is an evolutionary algorithm that mimics the social political imperialist competition. In this algorithm, an initial population that consists of colonies and imperialists are assigned to several empires. The empires then compete with each other and weak empires collapse and the powerful empires possess their colonies. The ICA performance was compared with the well-known Genetic Algorithm (GA) in three optimization scenarios: 1) a vertical well in a heterogeneous reservoir, 2) a vertical well in a channeled reservoir, and 3) a horizontal well in a channeled reservoir. In all three scenarios, it was observed that the ICA resulted in better solution compared to GA at a fixed number of simulation runs.
Mechanistic Modeling of Alkaline/Surfactant/Polymer Floods Based on the Geochemical Reactions for Snorre Reservoir
Authors: Khaledialidusti Rasoul , Kleppe Jon , Enayatpour Saeid 
Published: September 2015

Abstract
A considerable amount of oil resides in many reservoirs around the world such as the Snorre reservoir, a sandstone reservoir in the North Sea. The effect of lowsal waterflooding was explored in this field and the laboratory via Single Well Chemical Tracer (SWCT) and coreflood tests. Since the results showed that the amount of oil recovery after lowsal waterflooding was insignificant, the effect of alkaline/surfactant/polymer (ASP) flooding is investigated.
Mechanistic modeling of ASP injection is performed based on the geochemichal reactions such as aqueous, ion exchange, and precipitation/dissoloution using the reservoir properties. Due to lack of ASP flood of the laboratory corefloods for the Snorre reservoir, first, ASP coreflood is modeled based on the performed laboratory coreflood to validate the procedure of the mechanistic modeling of ASP. Second, the feasibility of ASP method for the Snorre oil field is investigated by a series of 1D coreflood simulations. Different strategies are designed to identify key parameters and an optimum design is determined based on the simulation results.
Since the propagation of alkali, in-situ surfactant (soap), and surfactant plays a vital role to succeed ASP method, mechanistic modeling of ASP flooding in the core is an effective tool to ensure the proper propagation to support low IFT and favorable salinity gradient. The results of different strategies demonstrate that alkali, surfactant, and polymer propagate simultaneously and in consequence, ASP flood can be feasible in the Snorre reservoir. The effect of the combination of low-salinity with ASP in order to provide optimum salinity for the soap/surfactant phase behavior is studied. The results also verify that the amount of oil recovery increases by injecting more slug size of chemicals; however, almost the same amount of oil is recoverable by injecting half or less of chemicals by designing the salinity gradient in the injected fluids. The effect of cation exchange reaction (CEC) is also investigated. The results show that the higher CEC leads to higher alkali consumption and it results in slower propagation of the alkali and pH front.
Mechanistic modeling of ASP is a highly sophisticated process due to the complicated ASP phase behavior and the geochemical reactions that happen in the reservoir. In this paper, all of the key parameters such as the chemical reactions, alkali consumption, soap generation, and the effect of the phase behavior are considered using the UTCHEM simulator. Geochemist’s Workbench® release 6.0 database is used to find the thermodynamic reaction equilibrium data for solution and solid species. The initial equilibrium concentrations of aqueous, solid, and adsorbed species are calculated using the EQBATCH program.
New Use and Interpretation of Production Logging Infractured Reservoir Wells with High Water Cut
Authors: Villasana Julio , Ham J. M. , Perez R. , Mehranfar R. 
Published: September 2015

Abstract
Production records provide important information about volumes and contribution areas in oil wells. Over time, the records are also a great contribution to monitoring of oil water contacts. In adition, with these records it is possible to test production pressure without surface wellhead’s measurements.
This new approach to obtain such information results from the need to determine the source of water in sime carbonate fields with channeling and / or coning problems, as well as to decide an optimum choke in the operation of the well.
For this reason we have implemented a new way of obtaining production records that allows us to maximize the use of data by analysis of applied engineering.