bluuebunny/crossref_metadata_2025_split huggingface dataset:
Minimally Invasive Antral Membrane Balloon Elevation in the Presence of Antral Septa: A Report of 26 Procedures
Authors: Kfir Efraim , Goldstein Moshe , Rafaelov Ronen , Yerushalmi Israel , Kfir Vered , Mazor Ziv , Kaluski Edo 
Published: October 2009

Abstract
Antral septa of the maxillary sinus occurs in approximately one third of patients undergoing posterior maxillary bone augmentation and is considered a relative contraindication for lateral maxillary window (“hinge osteotomy”). We present the results of 26 consecutive cases of patients with septated maxillary sinus who underwent minimally invasive antral membrane balloon elevation (MIAMBE) followed by bone augmentation and implant fixation. After undergoing preprocedural assessment and signing an informed consent, 57 consecutive patients were referred for posterior maxillary bone augmentation. Alveolar crest exposure (via 3-mm osteotomies), MIAMBE, and bone augmentation were followed by implant placement and primary closure (executed at the same sitting). Implant loading was done 6–9 months later. Twenty-six out of 57 (45.6%) patients had significant septa (detected on computed tomography) in the designated augmentation region. Twenty-four (92%) concluded the initial procedure successfully. Two patients had membrane tear requiring procedure abortion. Mean procedure time was 48 ± 23 minutes. Incremental bone height consistently exceeded 10 mm, and implant survival of 95.2% was observed at 6–9 months. MIAMBE can be applied to patients in need of posterior maxilla bone augmentation in the presence of septated maxillary sinus with high procedural success, low complication rate, and satisfactory bone augmentation and implant survival. MIAMBE should be an alternative to the currently employed methods of maxillary bone augmentation, especially in the presence of septated maxilla.
Effect of Gravity on Squeeze Treatment
Authors: Foroushani S. Abtahi , Ravari R. Rostami , Amani M. 
Published: October 2009

Abstract
The use of scale-inhibitor squeeze treatments to prevent downhole deposition of carbonate and sulphate scale is a well-stablished procedure in both onshore and offshore oil production facilities. Such treatments are used in production wells when the watercut reaches a level where scale formation is considered to be a problem that cannot be economically controlled by remedial dissolution of the deposits. Increasing the squeeze life is the key parameter in optimizing the treatments. Many ways and solutions for optimization of treatments have been suggested. In this study we are interested in the ways which are related to gravity effects and generally the objective of this project is to investigate the effect of gravity on the different stages of a treatment.
The Comparison of Effects of Injection of Natural/Nitrogen Gases on Asphaltene Precipitation Process
Authors: Hajizadeh Alireza , Ravari Reza Rostami , Amani Mahmood 
Published: October 2009

Abstract
Asphaltene and wax depositions in the course of production of many Iranian reservoirs have become a serious problem. In order to investigate the effects of injecting rich and dry gases and also nitrogen, on the asphaltene precipitation process, a comprehensive research study was launched.
The three phase equilibrium calculation of NGHIEM and his colleagues was used [6]. In the method pure asphaltene in the oil was considered as solid and the heavy part of the oil was split as precipitating and non-precipitating. The provided model was able to describe the phase behavior of reservoir oil encountered with a compositional disturbance caused by injecting light fluids into the reservoir during the production period.
In this work, first, the natural depletion model of each case was constructed and then the changes of behavior by injecting rich and dry natural gases and also high nitrogen content gas were investigated. Also the changes in the onset of asphaltene precipitation for different injections were shown. The achieved results showed that the nitrogen gas had more moderate effect on precipitation process compared to more vigorous effect of dry and rich gases.
On the Importance and Application of Integrated Asset Modeling of a Giant Offshore Oil Field
Authors: Khedr Osama , Al Marzouqi M. , Torrens Richard , Amtereg Ahmed 
Published: October 2009

Abstract
This paper presents an application of integrated asset modeling to a giant offshore oil field. The field is located northwest of Abu Dhabi Island and is one of the largest offshore fields in the world. The asset comprises several individually modeled reservoir layers sharing a common surface facility. The traditional method of modeling this field involves running separate simulation models assuming fixed boundary conditions at the wellhead. This does not accurately model the effects of the constraints imposed by the surface facility.
The primary aim of this paper is to highlight the importance of integrated asset modeling in formulating an optimized, cost- effective development plan. This is achieved through the provision of realistic production profiles, taking into account the impact of system backpressure and changes in operating conditions. Secondly, integrated modeling acts to reduce uncertainty in the design data in terms of phased production for future facility upgrading and replacement. Finally, integrated modeling provides a framework for production system optimization under different development schemes.
Included in the discussions presented here are a validation of the integrated asset modeling tool, an overview of the business requirements for the operation of the field over the next 30 years, and analysis of selected development strategies highlighting the added value of integrated asset modeling.
The results of the integrated studies helped to formulate decisions on infill drilling based on realistic production profiles. Secondly, they served to reduce risk through better understanding of the surface and subsurface interaction. Thirdly, they helped to support the decision for commissioning a new concept facility layout (artificial islands), which represents a significantly lower CAPEX investment with more flexibility. Finally, the integrated study assisted in making decisions on the application and type of artificial lift and displacement mechanisms.
Reservoir Rock Typing in a Carbonate Reservoir- Cooperation of Core and Log Data: Case Study
Authors: Chekani Mitra , Kharrat Riyaz 
Published: October 2009

Abstract
Reservoir characterization is one of the most challenging subjects in Carbonate reservoirs. In this study Flow Zone Index, Winland and initial water saturation methods were used to classify rock typing in an Iranian oil field located in the south-eastern region. In addition, the predicted initial water saturation along with log and core data was used for capillary pressure estimation.
The studied field is a Cretaceous fractured oil bearing reservoir composed of tightly packed limestone characterized by high porosity but poor permeability with a thickness of 55-65 meters throughout the reservoir. The matrix permeabilities and porosity are in the range of 0.01-150 md and 5-40 percent respectively. The oil gravity is 21.5 degree API.
Conventional Core data were first used to define the rock types for the cored intervals in which nine district rock types were defined. Furthermore, the FZI (Flow Zone Index) log was also generated based on the permeability which was obtained from FMI (Full-bore Formation Micro Imager) and porosity logs of cored and un-cored intervals. In addition, SLMP (Stratigraphic Modified Lorenz) plots were generated for the purpose of identifying flow zone and barriers in each well. Also, Winland method was also used for the same purpose. The results of SLMP were consistent with Winland result and FZI. The Scanning Electro Microscopy Photomicrographs of the obtained rock type were studied and found to be consistent with the finding of this work.
Further, the available initial water saturations obtained from log data were classified in three groups and found to consistent with FZI and Winland methods. Based on the DRT (District Rock Type) obtained from the FZI method a correlation between initial water saturation from the log and DRT was developed for the purpose of initial water saturation prediction. The generated data was used for the capillary pressure and relative permeability estimation. The generated capillary pressure and relative permeability were consistent with available scale data and provided sufficient Pc curve for the uncored intervals.
Generating 3-D Permeability Map of Fracture Networks Using Well, Outcrop and Pressure Transient Data
Authors: Jafari A. , Babadagli T. 
Published: October 2009

This paper was prepared for the 2009 SPE/EAGE Reservoir Characterization and Simulation Conference.

Abstract
Well log and core information, seismic surveys, outcrop studies, and pressure transient tests are usually insufficient to generate representative 3-D fracture network maps individually. Any combination of these sources of data could potentially be used for accurate preparation of static models.
Our previous attempts showed that there exists a strong correlation between the statistical and fractal parameters of 2-D fracture networks and their permeability (Jafari and Babadagli, 2009). We extend this work to fracture network permeability estimation using the statistical and fractal properties data conditioned to well test information. For this purpose, 3-D fracture models of nineteen natural fracture patterns with all known fracture network parameters were generated initially. It is assumed that 2-D fracture traces on the top of these models and also 1-D data from imaginary wells which penetrated the whole thickness of the cubic models were available, as well as pressure transient tests of different kinds. The 1- and 2-D data include statistical parameters (density and length distribution) and ten different fractal characteristics of different properties of the fracture system. Next, the permeability of each 3-D fracture network model was calculated and then converted into a grid based permeability map for drawdown well test simulations using commercial software packages.
Finally, an extensive multivariable regression analysis using the statistical and fractal properties and well test permeability as independent variables was performed to obtain a correlation for equivalent fracture network permeability. The equation was validated against different natural and synthetic fracture network patterns. The cases requiring expensive well (logsand cores) and reservoir (pressure transient tests) data were identified. This approach and correlation is expected to be a useful tool for practitioners asit reduces the computational time in static model preparation significantly and utilizes the available data effectively.

Introduction
The two most common approaches proposed for model transport in fractured reservoirs (dynamic modeling) are single and dual-porosity models. These methods require grid based representation of fracture network properties like porosity and permeability. The discrete fracture network approach is morecapable of representing the complex nature of fracture networks but they are limited in modeling complex dynamic processes. Hence, an accuraterepresentation of a fracture network and its equivalent permeabilitydistribution is a crucial task in dynamic modeling.
Shale Barrier Effects on the SAGD Performance
Authors: Shin Hyundon , Choe Jonggeun 
Published: October 2009

Abstract
The SAGD process has already been implemented for commercial production in Alberta Oil Sands areas in Western Canada since early 2000. SAGD performance is very sensitive to reservoir heterogeneities such as shale barriers, bottom and/or top water zones, and a gas cap. In the SAGD process, low permeability zones such as shale layers may act as a flow barrier depending on their size, vertical and horizontal locations, and continuity throughout the reservoir thus making it very important to understand and characterize the effect of shale layers.
In this study, the impact of various sizes and locations of shale barriers have been investigated through two-dimensional hypothetical simulation models. The various simulation models have been designed to investigate the shale size and vertical location in both BIP (shale between the injector and producer) and AP (shale above the producer) cases. Two different types of models were designed to look at the effect of flow path existence between the injector and producer: type-A is designated as having a no flow path directly above the producer and type-B has a flow path directly above the producer.
The simulation results show that type-A has a greater impact than type-B on SAGD performance especially for the BIP case. Small shale sizes of 3 and 5 m have a slight impact on performance; however, cases with 10 m shale have a greater impact due to the disruption of gravity drainge to the producer. Type-A BIP may require a longer pre-heating period for successful SAGD operation. Generally, shale barriers of 5 to 25 m are not critical for an AP case regardless of vertical location of shale barriers; however shale barriers greater than 50 m may act as a barrier and reduce the effective pay thickness of the reservoir depending upon the its vertical location.
Characterization of Kerogen Reservoirs by Organic Richness from Well Logs: A New Approach for Gas and Condensate Reservoirs in Najmah Formation, North Kuwait
Authors: Acharya Mihira N. , Al-Awadi Mishari A. , Al-Ajmi Saad A. , Al-Eidan Ahmad J. 
Published: October 2009

Abstract
The characterization of the unconventional reservoirs is a challenge. Though the Jurassic formation, Najmah-Sargelu, in North Kuwait fields have been tested and found to be a prolific source-rock as well as a producer of gas, condensate and volatile oil in several wells, but raised the flagged issue as regards to its characterization and predictability for success. The drill stem test (DST) results at some wells are quite successful without any stimulation, while at other wells the DSTs are unsuccessful in spite of advanced and repeated stimulations. Thus resulting a success rate at 50% and categorizing the Najmah-Sargelu as a geologically-complex, naturally-fractured, tight gas and condensate reservoir.
The Najmah kerogen member, formally known as Najmah shale, the source-reservoir composed of highly organic rich argillaceous and calcareous clay, represented by very high total gamma ray values associated with high uranium on spectral gamma logs. The Sargelu limestone, underlying the Najmah kerogen and overlying Dhruma shale, is generally tight and occasionally fractured. Conventional characterization by multi disciplinary data integration and model could not explain the test results, suggesting the key factor making these kerogen reservoirs to producer lies outside our scanned parameters such as structural position, fractures and formation damage etcetera. Conventional petrophysical interpretation and integrated formation evaluation method fell short to explain the unique behavior of such reservoirs.
This paper illustrates the new parameter, organic richness of Najmah kerogen sub-units and the pattern relationship between the success as flowed and unsuccessful as no-flow DSTs from the well data. Thus characterizing the Najmah reservoir based on their organic richness, derived from wireline density logs. This approach has successfully predicted our recent Najmah completed wells. Understanding this critical factor will navigate the 3D model building workflow steps for seismic reservoir description and future development strategy of Najmah in north Kuwait and other regions as well.
Case Study: Integrated 3D Geomodeling of Minagish Oolite Formation, Umm Gudair Field, Kuwait
Authors: Banerjee T. K. , Haider A/Aziz , Kumar Bishnu 
Published: October 2009

Abstract
The Umm Gudair is a large matured carbonate reservoir of Kuwait with a production history of more than 45 years. Umm Gudair has been producing primarily from the Lower Cretaceous Minagish Oolite formation composed of porous limestone consisting primarily skeletal grainstones. In recent past, the main focus of the asset team on this reservoir has been to extend the plateau rate and devise a long term Field development Plan by developing a comprehensive 3D geocellular model which shall be used for running simulation.
Three cases of 3D structural modeling scenarios were considered in order to reduce uncertainty attributed to velocity models. Petrophysical data of 223 wells, Core data from 34 wells, 3D Seismic Cube along with Inversion derived porosity and High Pressure Mercury Injection (Capillary Pressure) data from 102 core-plugs were used to generate 3D property model with the help of advanced 3D geomodeling software. A Facies classification model was built utilizing observations from core description, Log data and training a supervised neural network. Porosity was modeled using sequential Gaussian simulation (SGS) honoring core observations and Seismic derived porosity cube. Modeling Permeability was most critical and complex. Analysis of core data suggested a wide variation in Permeability (between 0.2 to 4000mD) with corresponding porosity variation of 0.08 to 0.30. Average capillary pressure data from core observations was converted to Height Vs Initial Water Saturation (J-Function) and water saturation was modeled.
Despite the abundance of Log, Core, Seismic and laboratory data, creating a truly representative 3D Geomodel was a big challenge owing to complex relationship and distribution amongst various petrophysical properties. This paper highlights the integration of various data and comprehensive steps of building a consistent representative 3D geocellular model used for flow simulation studies and field development planning.
Evaluation of Infill Drilling in the Third Sand Upper Reservoir, Greater Burgan Field, Kuwait
Authors: Ma Eddie , Sanwoolu Ayodele , Abdy Yaser , Al-Jadi Menayer 
Published: October 2009

Abstract
The Third Sand Upper (3SU) is one of the three sub-reservoirs in the Third Sand of the Greater Burgan field, the world's largest sandstone oil field. Initial oil production begun in 1948 and 3SU field development has not been aggressive due to its poor reservoir quality and productivity. After 60 years of primary production, only 7.5% recovery has been achieved.
Infill drilling was identified as a key development strategy in 3SU. In 2008, a simulation study was initiated to investigate infill drilling potential and its impact on production and recovery. We opted for a sector model mainly due to practicality and time constraint. The 780,800 cells sector geological model was scaled-up to 421,632 cells for flow simulation. Due to the sand-to-sand contact with the lower Burgan sands, it is imperative to include these reservoirs in the model to achieve proper energy balance. Accordingly, four pseudo layers were added to the simulation model to allow fluid migration from the lower reservoirs. The 3SU sector simulation model has 100m X 100m areal cells and individual layers with 4-6 feet thickness. Overall, the sector model has 30 times refinement compared to previous 3SU models (Ambastha et al, 2006).
The history match has been carried out for 37 3SU historical wells with 60 years of production history. Detailed study of interactions among field permeability distribution, aquifer strength, fluid migration and fault transmissibility specifications on simulation results was key in developing meaningful history match. Water cut match was less than satisfactory for wells located in the dome area due to modeling deficiency introduced by the pseudo layers. Three infill drilling spacing scenarios were set up to evaluate prediction performance of 800-meter, 400-meter and 200-meter well spacing. Results of the 50-year prediction runs indicated that an incremental recovery of 11% can be achieved by reducing the current well spacing of 800-meter to 400-meter.
Waterflooding Optimization Using Gradient Based Methods
Authors: Asadollahi Masoud , Naevdal Geir 
Published: October 2009

Abstract
Finding the best strategy for production optimization is currently an important research task for closed-loop reservoir management. The closed-loop reservoir management consists of two main tasks: history matching and production optimization. A comparative closed loop reservoir management exercise was performed in connection with the SPE Applied Technology Workshop "Closed-loop reservoir management" in Bruges June 2008. The model used in this exercise was a synthetic reservoir with typical geological features of Northern Sea fields and considerably larger than those used in most previous studies. In a previous work (Lorentzen et al., 2009), a set of history matched models were obtained using the ensemble Kalman filter. We will use these models to investigate the effect of formulation and initial guess on gradient based optimization methods.
Within production optimization, most of the works are focused on optimizing the reservoir performance under waterflooding. We will review the waterflooding optimization studies so far. The mathematical theories of an optimization problem as well as the practical issues regarding reactive and proactive approaches are discussed. The formulation of a waterflooding optimization problem is investigated using three different optimization variables: bottomhole pressure, oil and liquid production rates. Results show that proper formulation improves the performance of gradient based methods considerably. Then it is verified that manual optimization of the initial guess based on reservoir concepts enhances both the result and efficiency of the gradient based optimization. The manual optimization saves the gradient based methods from a number of local optima and also decreases the simulation costs substantially. Two line search methods, steepest descent and conjugate gradient, are used and compared in the adjoint based optimization approach. The conjugate gradient acts slightly faster than the steepest descent method. However, the selection of a proper initial guess is far more important for the performance. Finally, the optimal solution is applied on ten more history matched realizations to check the robustness of the solution. It is shown that the well liquid rates are the best variables used for maximizing the net present value using gradient based optimization. In previous works, well bottomhole pressure has been suggested.