bluuebunny/crossref_metadata_2025_split huggingface dataset:
Unique Expandable Sand Screen and Expandable Liner Hanger Completion for Saudi Aramco
Authors: Al-Baggal Zaki A. , Refai Ibrahim , Abbott James W. 
Published: December 2007

Abstract
This paper discusses the first well in which an expandable screen and expandable liner hanger were installed in a horizontal openhole well for Saudi Aramco. Wells in this area require sand control; however, alternative sand control solutions presented some potential problems in the Saudi Aramco wells. Supporting the borehole by packing the annulus space with gravel to prevent pockets in the screen/openhole annulus is a viable solution in some sand control environments; however, Saudi Aramco decided to investigate an expandable sand screen that has an expandable steel base pipe designed to protect the wellbore from collapse and maintain screen integrity. This screen design is considered to be the strongest in the market, with 2,500 psi collapse strength. The screen is run inside the open hole, and after expansion, the screen extends to an outer diameter that is equal to the openhole inner diameter.
The case history data will include the completion design process and a description of the successful deployment of 1,310 feet of the expandable screen into the horizontal lateral. Before expanding, the screen O.D. was 5-3/8-in, and after expansion, it had enlarged to the open hole ID of 6-1/8-in. This expandable deployment is significant as it was not only the first application of expandable, rigid, perforated base-pipe screen in the Middle East, but it was also the longest deployed to date for this type of 6-1/8-in. expandable screen worldwide. This application was also the first completion in which an expandable liner hanger was used in the same well as an expandable screen in the Middle East.
The well has been put on production and has shown excellent productivity as well as sand control.
Field Development Plan by Optioneering Process Sensitive to Reservoir and Operational Constraints and Uncertainties
Authors: Kasap E. , Sanza G. J. , Ali M. I. , Friedel T. , Waheed A. , Sukmana A. Y. , Cuauro A. , Cabrera C. , Rasol M. N. B. 
Published: December 2007

Abstract
A revised Field Development Plan (FDP) for Betty Field was prepared based on a process that was simultaneously sensitive to reservoir and operational constraints and uncertainties. This so called "Optioneering" process was an iterative, multidisciplinary optimization task that generated an action plan based on multiple options developed by reservoir, production, drilling and facilities engineering and ranked by economics. The process specifically involved first generating a series of unconstrained production options, which then considered drilling reach and anti-collision limitations, and finally had the appropriate facilities and regional evacuation constraints imposed. To achieve this, history-matched numerical reservoir models were first run within the framework of an infill well-location optimization software package. Then, drilling constraints were imposed with drilling planning software and facility constraints were included via a surface coupling system for multiple-reservoir models. Uncertainties in the reservoir characteristics and in the facilities/evacuation schemes were addressed by quantifying their impact on the ultimate recovery efficiency.
During the optioneering exercise, more than 100 unconstrained options for seventeen stacked reservoirs were identified from the perspective of infill drilling, pressure maintenance by gas injection and/or waterflooding, high pressure gas production, horizontal wells and production enhancement work. Based on typical costs and economic rank, the high potential unconstrained production options for each reservoir were determined. After imposing the drilling constraints, all reservoirs were then coupled to account for surface facility constraints. In the final analysis, five sidetrack wells reaching 12 new drainage points (NDP) over 10 reservoirs were designed. This infill drilling scheme will increase current reserves by 128%. Furthermore, a gas injection scheme identified as the optimum plan for A6.0 reservoir will increase current reserves by 28%. Field wide recovery factor will be improved by 9%.
Quantification of Fracture Permeability From Micro Resistivity Logs in Offshore Abu Dhabi Reservoir
Authors: Al-Farisi Omar , Elhami Mohamed , Barkawi Abdul Naser , Al-Marzouqi Mariam , Al-Jefri Ghassan , Kadada Talal 
Published: December 2007

Abstract
In Abu Dhabi offshore carbonates, it is recognized that fractures play an important role in influencing reservoir flow and connectivity both vertically (between reservoir units) and areally within the same reservoir unit. Image logs and borehole seismic surveys have been run to extensively identify fracture location and direction to understand the flow path of these reservoirs. However, in this paper an advanced step has been achieved in quantifying the fracture permeability from Conventional Logging Data, which is Micro-Resistivity Log, aided with Gamma-ray and Neutron-Density porosity logs. We all realized how vital, useful and critical this type of information would be as an input to reservoir simulators. This paper presents two techniques that have been developed to determine fracture permeability in reservoir rock and dense zones, these two techniques are merged to call it UFLIP (Universal Fracture Log Integrated Permeability).
The First technique is applicable for Reservoir Zones, it utilizes micro-resistivity logs as an invasion profile tool, and then by calculating Universal Rock Permeability (UROK)1, it establishes the permeability information due to invasion. It is then compared with a matrix driven permeability estimator that utilizes GR in technique called (PASZ - Permeability Active Searching) - same reference above-. The difference between these two permeability estimators indicates and produces the existence of fractures in reservoir rock and fracture permeability value.
The Second Technique utilizes UROK permeability value in addition to porosity and permeability thresholds to identify fracture permeability in Dense Zones between reservoir, as this zone is very vital the critical to production communication between reservoirs and hence production performance.
A great deal of multi-disciplinary effort is necessary to generate and validate this data for both techniques and is reflected in the extensive use of image logs and well-test-profile analysis as quality checks and correlation tools. Additional benefit is seen from this technique in having the ability to get real time fracture permeability data that helps reservoir and petroleum engineers in designing completion for optimum production.
Synthesis of Experience in Supporting Hydraulic Fracturing Treatments Using Cross-Dipole Acoustic Log
Authors: Sadykov M. R. , Pasynkov A. G. , Nikitin A. N. , Stenin V. P. , Metlin V. V. , Dobrynin S. V. 
Published: December 2007

Abstract
The only way to increase the reasonableness of candidate well selection for hydraulic fracturing treatment, as well as to optimize the technology of implementation of this production enhancement method is trough achieving a new level of information support for the preparatory stage of these operations.
As one of the types of studies to significantly facilitate generation of hydrodynamic models, the multi-array multi-wave polarized acoustic log may serve, which makes it possible to optimally compute the fracture design and to predict the direction of fracture propagation before performing the fracturing treatment, and to evaluate the actual geometry of hydraulically induced fracture with maximum reliability.
Fracture Analysis for Carbonate Reservoirs Using 3D Seismic P-Wave Data: Middle East Case Study
Authors: Wang David Y. , Lu Chih-Ping , Dong Wenjie , Johns Mary K. , DeGraff James M. , Anderson James H. 
Published: December 2007

Abstract
Seismic reflection amplitude at the top of a fractured rock layer varies as a function of both offset and azimuth. Travel time and attenuation along ray paths through a fractured layer also vary with offset and azimuth. An integrated set of procedures and a flexible workflow were developed to extract these measures of azimuthal seismic anisotropy. The procedures include screening tools to evaluate the feasibility of applying seismic inversion methods to extract azimuthal attributes, and quick-look tools to rapidly visualize seismic anisotropy that may indicate open fractures.
Azimuthal anisotropy is recognized in seismic data from a giant Middle East oil field by identifying differences between sector stacks formed from different azimuth bins. This screening analysis shows an azimuthal AVO response that seems to vary in a meaningful way across the field. Further analysis utilized a proprietary, azimuthal AVO, inversion process that estimates two attributes. The first quantifies AVO anisotropy that may be related to fracture intensity, differential stress, significant stratal dips, or other factors. The second attribute is related to fracture orientation when fractures are the cause of anomalies. A goodness-of-fit estimate quantifies the error between the fitting function and the observed data. Inversion results show areas with strong azimuthal variations that correspond well with coherent energy observed in the sector stack difference, but with improved spatial resolution and contrast.
The key to using azimuthal seismic anomalies wisely in reservoir development is their integration with subsurface data to discriminate among possible sources of the anomalies. The validation phase of the study used subsurface data on fracture intensity, in-situ stress state, stratal geometry, erosion surfaces, and production data and tests. Maps of seismic anisotropy show coherent anomalies related to known geologic features, giving confidence that the method detects meaningful geologic information that can be used to constrain reservoir quality models.
Comparative Study of Flowback Analysis Using Polymer Concentrations and Fracturing Fluid Tracer Methods: A Field Study
Authors: Asadi Mahmoud , Woodroof Robert A. , Himes Ron E. 
Published: December 2007

Abstract
This paper compares flowback efficiencies using polymer concentration and frac fluid tracer methods. Results are presented for the flowback efficiency of each frac fluid segment using non-radioactive chemical frac tracers injected in a well as well as the results for the total flowback efficiencies using polymer concentration and frac fluid trace analysis methods. Two wells were fraced and traced with various chemical frac tracers. Upon commencing flowback, samples of produced aqueous solution were collected according to a pre-designed sampling schedule that lasted for 72 hours. Samples were analyzed for tracer, polymer, calcium, potassium, sodium, and chlorine concentrations. With the use of the mass balance technique, the total flowback volume and flowback efficiency for each fluid segment were calculated using the tracer method. In addition, total flowback and flowback efficiency were calculated using both polymer concentration and tracer methods. To better evaluate and compare the results of polymer concentration and frac fluid tracer analyses, dynamic fluid leakoff tests were conducted in a laboratory environment using both low and high permeability core samples. Detailed laboratory and field results are presented along with comparison of flowback results from both polymer concentration and frac fluid tracer methods.
Reactive Transport Modeling of Carbonate and Siliciclastic Diagenesis and Reservoir Quality Prediction
Authors: Xiao Yitian , Jones G. D. 
Published: December 2007

Abstract
A fundamental challenge in reservoir characterization is the accurate prediction of diagenesis on reservoir quality and heterogeneity. Reactive transport modeling is an emerging technology that can be used to simulate coupled multi-phase fluid flow and diagenetic reactions. It has the unique capability to predict spatial and temporal variations in porosity and permeability and reservoir quality evolution at both geological and production timescales. We applied reactive transport modeling to investigate several styles of diagenesis in both carbonate and siliciclastic rocks: 1) Early diagenesis in a freshwater lens and associated hydrological zones in an isolated carbonate platform; 2) Dolomitization and anhydrite cementation in a brine reflux system; 3) Geothermal convection and burial diagenesis in a salt buried isolated platform; 4) Fault induced hydrothermal fluid flow and illitization; and 5) Formation alteration associated with steam (water) and acid injection and artificial diagenesis. Adopting a sensitivity analysis approach, we examined how key natural variables, such as climate, sea level, temperature, salinity and fluid composition and porosity/permeability heterogeneity impact different styles of diagenesis and reservoir evolution. We also examined how formation damage caused by artificial diagenesis in production can be predicted by reactive transport modeling. Linking fundamental geochemical processes to predict reservoir quality has significantly improved our understanding of several conceptual diagenetic models and paradigms. Our novel approach suggests that reactive transport models, when sufficiently integrated with traditional methods and calibrated with field data, have the potential to significantly improve our ability to predict carbonate and siliciclastic reservoir quality.
Downdip Oil Potential for an Onshore Abu Dhabi Petroleum System
Authors: Pottorf R. J. , Hussenoeder K. L. , Tseng H. , Petersen K. , Davis C. L. , Richardson M. , Pietraszek-Mattner S. , Moore D. W. , El Agrab A. F. , Khouri A. A. 
Published: December 2007

Abstract
A combination of fluid inclusion and geochemical analyses were conducted on rocks and reservoir fluids to develop an improved understanding of down-dip oil potential in a mature exploration play, onshore Abu Dhabi. Exploration for oil in the region is complicated by low permeability carbonate reservoirs, poor seismic imaging, and complex hydrocarbon maturation and migration histories. In addition, a broad range of fluid properties, including gas, condensate, and high API oil make evaluation of reservoir fluid phase difficult to evaluate.
In this challenging environment, geochemical and fluid inclusion techniques are effective tools for identifying down-dip oil potential from gas cap fluids and reservoir rock samples. Fluid inclusion data are used to develop a hydrocarbon emplacement history, which constrains the distribution of fluids throughout the exploration area. In some areas, under-saturated gas inclusions trapped at present-day temperatures suggest a high risk for down-dip oil. Conversely, other structures contain oil inclusions that have been displaced recently by saturated gas, suggesting good potential for down-dip oil. Geochemical analyses of recovered fluids were independently utilized to predict the likelihood of down-dip oil. These combined techniques were placed in a geologic framework to regionally risk the potential for down-dip oil throughout the exploration area. This allows for improved resource evaluation and prioritization of exploration efforts in areas of the play where a high probability of down-dip oil exists.
New Hybrid Steam-Solvent Processes for the Recovery of Heavy Oil and Bitumen
Authors: Nasr T. N. , Ayodele O. R. 
Published: December 2007

Abstract
Canada has declining reserves of conventional oil, but vast reserves of heavy oil and bitumen. Over 90% of the world's heavy oil and bitumen trapped in sandstones and carbonates are deposited in Canada and Venezuela. Up to 80% of estimated reserves could be recovered by in-situ thermal operation. The current in-situ thermal technologies such as cyclic steam stimulation (CSS), steam flooding and steam-assisted gravity drainage (SAGD) are energy intensive and use large quantities of fresh water. Increasing pressure of environmental concerns and the threat of a carbon tax will make it imperative to find new oil extraction technologies that are less energy intensive and that use less water. Combining technologies in the form of hybrid steam-solvent processes offer the potential of higher oil rates and recoveries, but at less energy and water consumption than processes such as SAGD.
At the Alberta Research Council, new hybrid steam-solvent processes have been undergoing development in recent years. The Expanding Solvent-SAGD (ES-SAGD)(1–2), is aimed at improving and extending SAGD performance by solvent addition to steam. The improvements include higher and faster drainage rates, lower energy and water requirements and reduced green house gas (GHG) emissions. The Thermal Solvent Hydrid process focuses on combining solvent with a small amount of steam in a VAPEX (vapour extraction) process(3–4). This process offers the potential of higher rates than cold solvent VAPEX at less energy consumption than SAGD.
Hybrid steam-solvent processes, when fully developed, will extract oil at lower cost than SAGD and will also open currently marginal resources for exploitation, increasing oil reserves. This paper presents and discusses the principal concepts and key parameters for the new hybrid steam-solvent processes and compares expected performance to SAGD.
Simulation of Microbial Enhanced Oil Recovery
Authors: Ghadimi M. R. , Ardjmand M. 
Published: December 2007

Abstract
Nowadays, the experts in biotechnology and oil engineering cooperate to improve the production of oil reservoirs. A large portion of the world energy consists of non-renewable fossilized fuels; the primitive methods in oil recovery just make 8 to 30 percent of oil reservoirs available. So, the owners of these reservoirs are trying to increase efficiency via using newer methods with lower costs. One of the most important new methods in oil recovery enhancement is the microbial method (MEOR), which is based on utilizing special microbes to increase the production of oil wells. In this project a computer software is presented for simulation of microbial enhanced oil recovery. In other words, an oil reservoir is simulated for applying microbial method.
Firstly mass balance equations of reservoir fluid (water & oil), bacterium, metabolite and nutrient are droved and analyzed considering the experimental data and mathematical relations of a MEOR model. This information is applied on one of the oil reservoirs in Persian Gulf. The equations are simulated by applying numerical methods (finite element, successive overrelaxatoin) using a computer software (MATLAB). The effectively of application by this method for enhancement of oil recovery is assessed through analyzing the graphs resulted from this software which includes the profiles of concentration (water, oil, bacterium, metabolite and nutrient), pressure and also plots of oil and water saturation, mobility of water and oil. The obtained results show that through applying this method, pressure of reservoir that is the main factor will increase linearly leading to enhanced oil recovery from reservoir.
Furthermore, this method can be used as a pattern in analyzing other reservoirs in which MEOR is used for enhanced oil recovery.
Simulation Of Microbial Enhanced Oil Recovery
Authors: Gheshlaghi M. R. Ghadimi , Ardjmand M. 
Published: December 2007

Abstract
Nowadays, the experts in biotechnology and oil engineering cooperate to improve the production of oil reservoirs. A large portion of the world energy consists of non-renewable fossilized fuels; the primitive methods in oil recovery just make 8 to 30 percent of oil reservoirs available. So, the owners of these reservoirs are trying to increase efficiency via using newer methods with lower costs. One of the most important new methods in oil recovery enhancement is the microbial method (MEOR), which is based on utilizing special microbes to increase the production of oil wells. In this project a computer software is presented for simulation of microbial enhanced oil recovery. In other words, an oil reservoir is simulated for applying microbial method.
Firstly, mass balance equations of reservoir fluid (water & oil), bacterium, metabolite and nutrient are droved and analyzed considering the experimental data and mathematical relations of a MEOR model. This information is applied on one of the oil reservoirs in Persian Gulf. The equations are simulated by applying numerical methods (finite element, successive overrelaxatoin) using a computer software (MATLAB). The effectivity of application by this method for enhancement of oil recovery is assessed through analyzing the graphs resulted from this software which includes the profiles of concentration (water, oil, bacterium, metabolite and nutrient), pressure and also plots of oil and water saturation, mobility of water and oil. The obtained results show that through applying this method, pressure of reservoir that is the main factor will increase linearly leading to enhanced oil recovery from reservoir.
Furthermore, this method can be used as a pattern in analyzing other reservoirs in which MEOR is used for enhanced oil recovery.
Enhanced Prediction of Wellbore Stability Using Seismic-Based Geomechanical Modeling
Authors: Zinchenko I. , Moiseev Yu. , Garagash I. , Baransky N. , Smirnov K. , Kozlov E. 
Published: December 2007

Abstract
The set of geologic medium parameters controlling wellbore stability includes minimum and maximum horizontal stresses, pore and fracture pressure, and intensity of natural fracturing. In this paper, we demonstrate the use of 3D seismic data for mapping these parameters related to certain depth interval. In our approach, the transfer from seismic data to the set of parameters above is carried out using geomechanical modeling. In contrast to routine techniques stemming from elastic Earth model, the mechanical model we use is based on the poroelastic Biot's theory for saturated porous rocks with elements of plasticity included to predict pore pressure and fracture pressure. Respectively, in addition to seismic velocity, the input data for the modeling includes a series of petrophysical and mechanical properties such as the rock density, porosity, permeability, the Poisson ratio, rock cohesiveness, angle of internal friction, and sometimes, the dilatancy angle.
The combined use of seismic and petrophysical data provides for a more accurate prediction of stresses, pressures and fracturing as compared to traditional approaches. Hence, a more accurate conclusion on the expected stability of a wellbore with a particular trajectory at each particular site and each particular depth interval can be derived from the modeling results.