bluuebunny/crossref_metadata_2025_split huggingface dataset:
Controlling Gas Channeling Problem Within and Near Vicinity of a Gas Well: Case Study Bagla Gas Field
Authors: Ahmed Shakeel , Majeed Arshad , Ahmed Bashir , Aftab Farrukh 
Published: December 2007

ABSTRACT
Integrity of well structure is a vital factor to produce hydrocarbons from subsurface. It is important that well structure along with cement behind the casings remains intact to get controlled and risk free production during life of a well. This objective is achieved by making every effort to ensure good cement behind pipe and selecting suitable well tubulars honoring reservoir fluid composition and fluid flow rates. In case the criteria of well integrity is not met, flow of fluids behind casing and communication between tubulars create problems and may lead to uncontrolled flow of well fluid creating environmental and safety hazards.
Bagla gas field is located within the Indus Basin with producing horizon in Lower Goru Formation of Cretaceous age. This is a single well field, which was drilled by Phillips Petroleum Exploration Ltd during 1988. Later on OGDCL acquired this field. The field could not be developed due to its marginal reserves, remote location, non-availability of gas buyer in near vicinity of the field and non-attractive economics in case gas is sold to SSGCL due to high cost of pipeline quality gas to SSGCL gas transmission network.
During April 2004 gas channeling to surface was observed in the nearby area located within a radius of 2-3 km from the Bagla well. This gas channeling was causing environmental and safety hazards in the area. This paper discusses the measures taken by OGDCL to diagnose the cause of problem and efforts made to control the well to contain the environmental and safety hazards in the area.
Drill Automation for the Space Environment: Lessons Learned
Authors: Zacny K. , Paulsen G. , Cooper G. 
Published: December 2007

Abstract
This paper examines drilling autonomy in the context of space exploration and how it might differ from autonomy required in an oil well drilling.
The main driver in the planetary drill automation is a large communication delay (i.e. the drill can not be remotely controlled) whereas in the petroleum well drilling it is reduction in manpower as well as it serves to remove human operators from a dangerous location where heavy equipment is operated 24 hours a day regardless of the weather conditions. Both planetary and petroleum drills share common problems such as data ambiguity (the same data can come from two different events) as well as a large number of data inputs that need to be processed and analyzed in real time for automation to be effective.
The petroleum industry is profit driven; thus reliability of various mechanical components is carefully optimized since higher reliability means also higher cost. In the space industry, the reliability of all systems and especially those that form a single point failure must be very high. This requires a lot of testing and makes space exploration very expensive.
Since automation is inherently expensive, a careful analysis needs to be performed in order to determine which operations may be optimized and which should not. This is because some operations are still done better and cheaper with humans.
Compositional Modeling of Two-Phase (Gas/Water) Flow in Gathering and Transmission Pipeline Systems
Authors: Zaghloul Jose , Adewumi M. A. , Ityokumbul M. T. 
Published: December 2007

Abstract
The current work presents a fully-compositional tool for modeling systems exhibiting two-phase (gas-water) flow. The tool couples complex hydrodynamic and thermodynamic models to describe the behavior of fluids flowing in a pipe.
Results show that the model is capable of predicting water condensation in the pipe, estimating pressure/temperature profiles, and handling different flow patterns and their transitions. Moreover, the model has the capacity of estimating the concentration of hydrocarbons, carbon dioxide, hydrogen sulfide, methanol, and other substances dissolved in the aqueous phase.
Hydrate formation is related to the presence of methane, ethane, propane, butanes and nitrogen in a gas stream, while acid is expected to form when significant amounts of CO2 or H2S are present in the aqueous phase. The model developed in this study provides production engineers with an excellent tool for evaluating the potential formation of hydrates and/or acids in piping systems.
Several cases were used to validate the model. Model predictions were compared against experimental data obtained by Eaton et al. (1967). The flow patterns and pressure profiles calculated by the model accurately matches experimental data. The pressure profile calculated is within 2.0% of the reported experimental values. Similarly, the average liquid holdup estimated was in good agreement with the values reported by Eaton et al. (1967).
The model is capable of predicting the initial water condensation point in the pipeline and the concentration of different substances in the aqueous mixture. The tool gives production engineers important information on how much hydrate/corrosion inhibitors to inject and where, thus saving in the design, operation and maintenance of pipeline systems.
Crude Oils of Kentucky and Tennessee: Characteristics, Problems, and Solutions
Authors: Barker K. M. , Breitigam J. V. , Brotherton R. L. , Goff L. L. , Hake K. J. , Schofield R. D. 
Published: December 2007

Abstract
Paraffin and asphaltenes can cause many types of problems depending upon the characteristics that they give to a particular crude oil. The problems can range from deposition of paraffin or asphaltenes in the formation or equipment, causing the oil to congeal, oil wetting of the formation, causing emulsions or rigid film emulsions during acid treatments. The analysis of crude oils from wells in Kentucky and Tennessee has been carried out to determine the possible organic problems that will affect the production from these wells. Problems, causes, and solutions will be discussed with case histories presented.
Is Bati Raman Heavy Oil Field a Triple Porosity System?
Authors: Arslan Izzet , Akin Serhat , Karakeçe Yildiz , Korucu Özlem 
Published: December 2007

Abstract
This paper presents a seamlessly integrated naturally fractured reservoir (NFR) modeling process for the ongoing Bati Raman heavy oil field rejuvenation project. As a part of the project, remedy of ongoing immiscible CO2 injection and successfully achievement of a near term steam flooding pilot test depend on understanding the heterogeneous natural fracture system. The naturally fractured rock and vug characteristics of the reefal/subreefal carbonate reservoir, and lateral and vertical facies distributions have been a challenge for establishing a successful 3D conformance process.
An improved static model was constructed using the results of 2D and 3D seismic, sedimentological model and systematic fracture characterization. The new 3D seismic survey helped to identify the fracture regions, and had direct input to the new reservoir model with new structural information as well as fracture attributes. Fracture density and apertures of rare large true fractures were observed in the reservoir both on cores using a drill-core imaging system, and in FMI log findings. FMI logs provided the textures of vugs as well, ranging from less than 1 mm to 5 cm in size. The vuggy porous medium was handled in two ways: the interconnected vugs added into the fracture system since they build major pathways in the fractures between injector-producer pairs, while the isolated vugs are a part of the matrix system adjusted for compressibility. Matrix and fracture properties were distributed using sequential Gaussian simulation (SGS) and neural network algorithm constrained to the conventional log profiles within a 3D structural framework. This was followed by a calibration of well tests and CO2 breakthrough patterns, and hydrocarbon volume uncertainty assessment. The methodology optimizes a multi-disciplined integration and interpretation workflow for an unconventional multi-porosity complex model that is required in the distribution of flow properties such as saturation and pressure.
Shapes of Flood Fronts in Heterogeneous Reservoirs and Oil Recovery Strategies
Authors: Montaron Bernard A. , Bradley David , Cooke Anthony , Prouvost Laurent , Raffn Anne Gerd , Vidal Alain , Wilt Michael 
Published: December 2007

Abstract
The limited grid resolution used for dynamic reservoir simulations has contributed to convey the perception that fluid flood fronts have fairly smooth shapes. However it has been known for a long time that reservoir permeability heterogeneities create fractal-like fluid front surfaces. Many sandstone reservoirs and most carbonate reservoirs are known to be highly heterogeneous. Fractures, texture, depositional facies, diagenesis are well known causes of heterogeneity in carbonates. In this paper we present new results of computer simulations at high grid resolution of water flood fronts in reservoirs with heterogeneous wettability distributions. Wettability is an important factor in carbonate reservoirs and these simulations clearly show the critical impact of heterogeneous wettability distributions on sweep efficiency and recovery factors. Also discussed are results for reservoirs combining heterogeneities of various origins such as matrix permeability, wettability and large scale heterogeneities such as fracture corridors. The geometry of fluid fronts predicted by these simulations is compared with actual fluid fronts monitored using advanced processing technology of high resolution 4D seismic. We also review how saturation profiles in swept zones can be estimated using well-to-well electro-magnetic image cross-sections. Finally, the impact of complex front shapes on sweep efficiencies, recovery factors, water breakthrough predictions and water cut curves versus time is discussed. Examples of possible production scenarios using intelligent completions and fluid front monitoring techniques to maximize recovery in spite of reservoir heterogeneities are presented.
Imaging Injected Water flood Fronts between Wells in a Complex Carbonate Reservoir: Designing Completions to Optimize Image Resolution
Authors: Bhatti Zahid , Shuaib Mohamed , Wilt Michael , Levesque Cyrille 
Published: December 2007

Abstract
In the paper, we will briefly review the pilot design and demonstrate the utility of applying the EM imaging to the pilot. We will also show the benefit of the optimized casing material on the resolution of the crosswell EM resistivity images and describe the methods employed for monitoring the fluid flow and show preliminary results of the modeling process. This crosswell EM technique which has been successfully employed and proven in other geographical areas is being implemented first time in UAE.
The EMI technology is being deployed in southern part of a complex carbonate reservoir in the middle-east where an uneven flood front advance has been observed in different reservoir units. It has been observed that water front has advanced much faster in the highly permeable upper reservoir units as compared to lower reservoir units. In order to understand the horizontal and vertical fluid flow behavior, an inverted 5-spot water injection pilot pattern is being implemented. The pilot will address the issues of the uneven sweep efficiency, bypassed oil and effectiveness of stylolites across different units. The pilot results and observed data will be used in the simulation to design an optimum development scheme for the lower reservoir units in the southern part of the field.
The current dynamic simulations predicted that the injected water will reach producers after 7 to 10 years. However, the decision on field developments have to be taken early enough to avoid the slumping of water from upper to lower units and loss of reserves in the lower units. Early imaging of the injected water from the injection well into the reservoir is paramount in assessing the success of the pilot and future field development issues.
It is anticipated that this tomographic Cross-well Electro-magnetic (EM) resistivity technique will provide sufficient imaging information to track the water flood movement between wells. The most favorable conditions to acquire reliable formation resistivity distribution information, EMI require at least one kilometer distance or separation between wells.
Prior to the field deployment, simulations were run to confirm the applicability of the technique and define the parameters for the survey with objectives; 1) to check the sensitivity of EM technique to the reservoir conditions and injected fluids, and 2) to carry out actual EM tool simulation and check the quality of tool response. The study concluded; 1) cross-well EM resistivity technique is well suited for tracking the water front in the current reservoir conditions, 2) the injected fluids create enough resistivity contrast to be easily picked up by the technique, and 3) the flood front progress can be captured by conducting the surveys in a time-lapse mode.
As part of this project, lab tests were conducted to choose a material that would limit the attenuation at high frequency as much as possible at source and receiver locations.
Fieldwide Reservoir Characterization Based on a New Technique of Production Data Analysis: Verification Under Controlled Environment
Authors: Mata D. , Gaskari R. , Mohaghegh S. 
Published: December 2007

Abstract
Intelligent Production Data Analysis – IPDA, is a new methodology for Reservoir Characterization based only on monthly production rate data. This technique combines conventional methods of production data analysis (decline curve analysis, type curve matching and history matching) with intelligent systems. The study targets the validation of this methodology under a controlled environment, attempting three main objectives: Identifying Sweet Spots, Forecasting Reserves and recognizing under-performer wells.
The study investigates the behavior of five different reservoirs, modeled using a commercial simulator. The structure, parameters and heterogeneity of each configuration was inspired by existing formations. Records of production rate data were generated from the simulated fields (both single and multi-layer formations) and used as input to perform an "Intelligent Production Data Analysis".
The findings highlight strength of this technique in tracking the fluid movement in the reservoir as a function of time. Furthermore, this study identifies some limitations and circumstances under which the analysis may not result in correct recommendations.
Advances in Measuring Porosity and Permeability from Drill Cuttings
Authors: Lenormand R. , Fonta O. 
Published: December 2007

Abstract
Drill cuttings can provide quick and useful information for reservoir characterization, especially when cores are not available. So far, several petrophysical properties can be determined from cuttings: porosity, permeability and T2 NMR distributions (directly related to the pore size distribution) Several laboratories are working to improve the techniques of measurements and also the drilling tools to minimize the damage to the rock. In this paper, we present new results for porosity and permeability measurements down to cuttings of diameters around 0.5 mm and the application to a field test.
The methods for measuring the porosity on cuttings are the same as for cores when the sizes are larger than 3mm. For smaller cuttings (most of cases), the best results are obtained using a centrifuge or a porous plate to remove the interstitial liquid with a controlled capillary pressure. With this method, porosities were measured within 1-2 PU (Porosity Units), even for the flat cuttings with diameter around 1mm and thickness around 0.5 mm collected during the field case.
For permeability, we used the technique developed by IFP based on the diffusion of a pressure wave in a viscous liquid saturating the cuttings. The results were improved by a better choice of the viscosity of the liquid used to saturate the cuttings. The suitable viscosity must satisfy two opposite constrains: high viscosity for a relaxation time large enough to be measured (larger than 0.2 second), and low viscosity to allow spontaneous imbibition in a short time. The results of the study are presented in a diagram, showing the viscosity to be used as a function of cuttings sizes and permeability. Porosity and permeability methods have been tested on synthetic cuttings obtained by crushing cores of known parameters.
Finally, the methods were tested on real cuttings sampled especially for this study every 20 cm in a carbonate formation (125 samples). The results are discussed and compared to porosity logs obtained in the same well. The porosities measured on cuttings agree with the log value for values larger than 5 PU. The T2 NMR relaxation times (peaks) are also in good correlation with the amount of clay given by the gamma ray log. However, the porosities and the sizes of cuttings are two small for permeability determination. Both porosities and T2 relaxation times give a good depth matching prediction with log less than 1 meter.
Experimental and Modeling Requirements for Compositional Simulation of Miscible CO2-EOR Processes
Authors: Shtepani E. 
Published: December 2007

Abstract
In order to design a successful miscible CO2 gas injection-EOR project, it is important to understand the physics and mechanisms by which the CO2 displaces oil in porous medium.
CO2 gas, under proper conditions of pressure and temperature, and in the presence of favorable reservoir oil composition, can become miscible with reservoir oil, helping remobilize and produce the oil remaining in the reservoir. The development of miscibility between the injected CO2 gas and the reservoir oil is through in-situ composition changes that occur from multiple fluid contacts and mass transfer between the reservoir oil and CO2 gas.
Trapping and mobilization of fluids in a porous medium are known to depend on (i) Pore Structure, (ii) Fluid/Fluid Interaction (reflected in interfacial tension (IFT) and mobility), and (iii) Fluid/Rock Interaction (related to wettability). Trapping and mobilization mechanism is related to the above factors in a complex way which can be described by complex interactions between viscous, gravity and capillary forces. EOR processes from fields typically involves altering the relative importance of these forces.
This paper discusses several aspects of miscible CO2 flooding and describes how these relate to the experimental and modeling studies required for a successful compositional simulation of miscible CO2-EOR processes.
The phase behavior experiments and EOS modeling of CO2-reservoir fluid system, as critical factors for an accurate performance prediction for miscible CO2-EOR projects, are reviewed.
In addition to PVT experiments, special coreflood experiments and numerical coreflood simulations to determine the micro-scale conformance of the CO2 displacement, identify CO2 breakthrough characteristics and longitudinal dispersion coefficient, are discussed in detail.
Finally, the importance of water injection and other factors related with CO2 injection, which could extend the miscible CO2-EOR technology to a broader range of oil reservoirs, has been given considerable attention.
Waterflood Conformance Study for a Carbonate Reservoir
Authors: Al-Anzi Khalaf , Kumar Rajendra , AL-Rashidi Tahani , Cumming John , Mckean Howard , McKie Calum 
Published: December 2007

Abstract
Mature fields of the Middle East have some of the longest production histories and richest data sets of any oilfields in the world. Waterfloods in fields that have operated for many years are reaching a stage in which better understanding of the reservoir’s response to water injection is critical for optimal field management going forward. A common approach, however, is that existing data sets are often used only by individual technical disciplines for relatively narrow purposes, such as well performance diagnoses.
An integrated, multidisciplinary study of a carbonate reservoir in the Minagish Field was implemented to better evaluate the conformance and integrity of current water injection operations, and make recommendations for improvement. A secondary objective was to establish a solid interdisciplinary workflow to support periodic reevaluation and update of the study.
A joint team of reservoir engineers and geoscientists was formed from KOC’s West Kuwait Asset Team and Halliburton’s Landmark group. Using a Common Visualization Environment (CVE) (Figure 1), the team integrated the Minagish Field history with all available static and dynamic data into a single, consistent data set.
A detailed geologic model with compartmentalization and layering schemes was established which was most likely to control fluid movements within the reservoir. This was validated and a more consistent model was developed by incorporating dynamic field data. The revised model based on flow units was further validated by cross-sectional reservoir simulation models in selected areas of the field.
This study suggests KOC can produce the Minagish Field at significantly higher offtakes in the future without negatively impacting recovery.
Sequence Stratigraphy-Based Geological Modeling of the Upper Thamama (Lower Cretaceous) Reservoirs of a Giant Abu Dhabi Oil Field, United Arab Emirates
Authors: Strohmenger C. J. , Al-Dayyani T. , Clark A. B. S. , Ghani A. , Hafez H. H. 
Published: December 2007

Abstract
Important hydrocarbon accumulations occur in platform carbonates of the Lower Cretaceous Kharaib (Barremian and Early Aptian) and Shuaiba (Aptian) formations (Upper Thamama Group) of Abu Dhabi. A new, sequence stratigraphy-keyed static (geological) model has been built for the Upper Thamama (Lower Cretaceous) Kharaib and Shuaiba formations. The Kharaib Formation contains two reservoir units (Lower Kharaib Reservoir Unit and Upper Kharaib Reservoir Unit). The overlying Shuaiba Formation is separated from the Kharaib Formation by the Upper Dense Zone (Hawar) and contains two reservoir units (Lower Shuaiba Reservoir Unit and Upper Shuaiba Reservoir Unit) only partly separated by dense intervals.
Core and well-log data of a giant onshore oil field in Abu Dhabi, as well as outcrop data from Wadi Rahabah (Ras Al-Khaimah) were used to establish a sequence stratigraphic framework and a lithofacies scheme; applicable to all four reservoir units and the three dense zones.
Six third-order composite sequences are composed of twenty-six fourth-order parasequence sets that form the basic building blocks of a new generation static model.
On the basis of faunal content, texture, sedimentary structures, and lithologic composition, fourteen reservoir lithofacies and ten non-reservoir (dense) lithofacies are identified from core. Reservoir units range from lower ramp to shoal crest to near back shoal open platform environments.
A new static (geological) model has been built to provide a more detailed reservoir description to the dynamic model to further optimize the field development plan.