bluuebunny/crossref_metadata_2025_split huggingface dataset:
South-Pars Phases 2 and 3: The Kinetic Hydrate Inhibitor (KHI) Experience Applied at Field Start-up
Authors: Glénat Philippe , Peytavy Jean-Louis , Holland-Jones Nick , Grainger Martin 
Published: December 2007

Abstract
South-Pars Phases 2&3 development in Iran is a "wet scheme" base design: no process is performed offshore, all the produced fluids (sour gas + condensate + water) are directly sent to shore through two 32" 109 km long sea lines. Corrosion and hydrate protection is based on buffered glycol (MEG+MDEA) which is regenerated onshore and sent back to the platforms through two 4½" piggyback lines.
The concomitant injection of a Kinetic Hydrate Inhibitor (KHI) and a Corrosion Inhibitor (CI) was initially considered as a back-up solution. This paper presents the field experience with KHI and CI injection which had to be applied for the field start-up during respectively 125 days and 80 days for each sea line.
This case represents the first large field application of KHI in the Middle-East and the potential of such Low Dose Hydrate Inhibitor (LDHI) is underlined.
Practical Flow Simulation Method for A Naturally Fractured Reservoir: A Field Study
Authors: El-Abd Salem , Al-Deeb Maged , Abdou Medhat , Linthorst Steef , Bahar Asnul , Kelkar Mohan 
Published: December 2007

AbstractThis paper presents the methodology, implementation and results of dynamic modeling of a naturally fractured carbonate reservoir, which consists of fracture swarm system and high matrix permeability. The focus of this paper is on the description of the dynamic single media model that was used to history match the historical production. The challenges in properly quantifying the separate effects of matrix and fracture within the framework of single media model become the major objective of the study. Brief description of the static model that consists of development of matrix and fracture models, as well as the method to integrate them, are also presented.Both matrix and fracture systems play an important role in the production mechanism of the reservoir. History matching for twenty years of production was successfully done in a single media model through an iterative process between static and dynamic models to ensure the consistency between the two models. Different sets of relative permeability curves (for matrix and fracture systems) were generated to properly simulate the fluid movement in the reservoir.The results indicate an excellent history match that is also followed by the success in the blind tests of newly drilled wells. Significant improvement was obtained compared to the previous model in simulating water production that comes from the aquifer to the wells through a complex fracture network. The results were achieved through various sensitivity analyses of fracture conductivity and by fine-tuning of relative permeability curves that are based on the eight rock types defined for the reservoir.In conclusion, the single media model used in this study can successfully simulate the behavior of a naturally fractured reservoir. The model has shown that it can produce excellent results in a very practical way.The methodology described in this paper is suitable for other naturally fractured reservoirs, especially in the Middle East Area where significant difference between core-derived permeability and the well-test derived permeability exists.
New Software Tool Improves Fractured Reservoir Characterisation and Modelling Through Maximised Use of Constraints and Data Integration
Authors: Rawnsley K. , Swaby P. , Bettembourg S. , Dhahab S. , Hillgartner H. , de Keijzer M. , Richard P. , Schoepfer P. , Stephenson B. , Wei L. 
Published: December 2007

Abstract
As part of an ongoing drive to enhance oil recovery from several fractured carbonate reservoirs in Oman, Shell's Carbonate Development Team and Petroleum Development Oman have applied a workflow and research software package aimed at better characterizing the complex subsurface. The workflow comprises several steps, each one supported by a multidisciplinary research program, and implemented in an integrated software environment for application to field development and enhanced oil recovery projects. The software tool, which interacts with the existing Static and Dynamic modeling packages, produces integrated reservoir models including fracture specific information. The capabilities include: (1) Data integration and visualization (2) Constraints definition (from subsurface, analogue outcrops, geomechanics, etc.) (3) 3D fracture modeling (4) Link to reservoir simulation.
The tool is flexible, such that any type of well data (Static and Dynamic), seismic data (attributes and interpretations), and constraints can be brought together in a single display. An analysis package allows rapid visual and interactive structural analysis to be made, with quantification of structural elements. Constraints are derived from outcrop and subsurface field examples, geomechanical data and sandbox analogue experiments. A key constraint includes mechanical layering as a control on fracture geometries. Fracture networks are generated following the defined constraints combining statistics and mechanical rules. The fracture network properties useful for the Dynamic simulation can be quickly extracted. Because emphasis is placed on characterization and maximum use of the relevant constraints, the tool helps ensuring that the fracture modeling time is spent on understanding and assessing the uncertainties.
To date this workflow has been applied to several fields worldwide, demonstrating its suitability to address problems related to Natural Depletion, Waterflooding or Assisted Steam Gas Oil Gravity Drainage.
The Synergy between Static Reservoir Modelling and Flow Simulations for the Optimization of a Field Development Plan of a Carbonate Reservoir, Onshore UAE
Authors: Ribeiro M. T. , Hassan S. R. , Gomes J. S , Bahamaish J. N. 
Published: December 2007

Abstract
This paper presents a case study where a full interaction between static reservoir modelling and flow simulation was performed to optimize the development plan of a carbonate Field in Abu Dhabi.
Since no reliable seismic attributes could be extracted from the 3D seismic, coupled with the fact the reservoir had only a few wells, several geological scenarios were modeled using both deterministic and stochastic techniques. Sensitivities were performed on variogram ranges, deterministic trends and algorithms.
The population of the model with petrophysical properties was carried out using reconciled log and core data in the crestal area of the Field and propagated downflank with the assistance of trends. The simulation of the porosity was done with Sequential Gaussian Simulation and for the permeability a co-simulation with porosity technique was applied. The results of 1D permeability simulation were also tried. Both approaches for permeability modelling were matched with the well test results. Due to the absence of SCAL data and the fact that the open-hole log saturations are not reliable (low resistivity pay in some intervals), an analog Sw curve had to be used. Two extreme Sw curves (min and max) were considered to cover the uncertainty.
Different reservoir descriptions (geological/petrophysical scenarios) were subsequently flow simulated and the results evaluated against different development options. The selected models matched water cuts and reservoir pressures without the need for permeability multipliers.
Finally, the results on new drilled wells (blind tests), namely log properties, PBU and injectivity test results, showed a good agreement with the models. The selected models were used to compare different patterns of development under multiple pressure support schemes (peripherical and updip water injection, gas vs. water injection, etc.).
This paper calls for the importance of building different static models using different geostatistical parameters to address the static-dynamic uncertainties, instead of performing a large number of stochastic realizations.
A Novel Approach to Reservoir Surveillance Planning
Authors: Sinha Satyendra P , Al-Qattan Raghad 
Published: December 2007

ABSTRACT
Reservoir Performance is tracked and monitored with the help of various surveillance measurements. The surveys may include static and flowing bottom hole pressure measurements, pressure transient studies, production logging, pulsed neutron capture logging and flow rate measurements. The measured or interpreted values include reservoir pressure, productivity index, reservoir permeability, well efficiency, flow capacity, water saturation, fluid contacts and flow rates of oil, gas and water. These values, when appropriately grouped and mapped, indicate the reservoir performance and fluid flow movement. However, the asset needs to be managed with limited surveillance every year. This brings into focus the need to optimally select the candidate wells or completions. Surveillance is planned with an objective to minimize the uncertainty in the measured values. This results in maximizing understanding of the reservoir performance leading to sound reservoir monitoring and better business decisions. Continuity, productivity, probability & uncertainty maps are regularly prepared using Kriging. Measurement errors are assumed to follow a Gaussian distribution. The maps quickly reveal the need to have surveillance in particular wells/completions. The important contributions of the value-driven surveillance planning include Data integration of well and reservoir performance including all the surveillance and well integrity data.Analysis and interpretation of surveillance data becomes a prerequisite for requisitioning surveillance. Mapping and analyzing interpreted data becomes an integral part of any surveillance process.Intuition and subjectivity in surveillance planning is substituted by an objective method based on robust geostatistics.Surveillance data becomes more visible to the team. This generates team involvement, better quality of information and a shared understanding of reservoir management needs.
Seismic Integration for Better Modeling of Rock Type Based Reservoir Characterization: A Field Case Example
Authors: Bahar A. , Abdel-Aal O. , Ghani A. , Silva F. P. , Kelkar M. 
Published: December 2007

AbstractThis paper presents the result of a reservoir study where seismic data have been fully utilized to obtain a better rock-type based reservoir characterization model. The study was conducted for a highly faulted carbonate reservoir in the Middle East. The available 3D Seismic data have been used to determine the structure map, fault and fracture network, and porosity distribution. Additionally, two seismic attributes (Energy Half Time and Max. Peak Amplitude) had also been used to assist the determination of stationarity regions used for geostatistical simulation.The reservoir characterization strategy for this study was started with the detailed development of a geological reservoir rock type (RRT) scheme. The RRT scheme was developed based on depositional facies, diagenetic overprints and petrophysical properties, including pore throat size distribution, porosity and permeability. The scheme was then used to constrain the property modeling inside a geological framework that was built based on the seismic interpretation.Prior to the development of 3D porosity model, four porosity maps were generated based on the available interpreted Acoustic Impedance (AI) and well log data. Each map represents the difference of the influence of seismic data, from full seismic influence to no seismic influence. One map has been selected to represent the seismic derived porosity based on the degree of correlation between the AI data and well-log porosity.The integration of seismic-derived porosity into the 3D simulation model was conducted using Bayessian Update principle inside a conditional simulation technique. In this technique, 3D porosity distribution honors the underlying RRT and at the same time its vertical-column average honors seismic-derived porosity. The comparison of the results between the simulation with seismic and simulation without seismic has clearly indicated the value added by seismic data, namely improving the simulation result in the areas of poor well-coverage. This is important in order to honor the diagenesis effect that is difficult to model due to a limited number of wells.
Predict Injection Profile of an Injector Using a Soft Computing Method
Authors: Wei Mingzhen , Sung Andrew H. , Wang Jiachun , Liu Lingzhi , Zhang Shujuan , Li Xuxin 
Published: December 2007

Abstract
Knowing the injection profile of each injector in a reservoir is of major importance for analyzing residual oil distribution underground. However, in practice, it is impossible to acquire real-time injection profiles for each well when they are needed.
In this paper, a two-step learning fuzzy system was introduced to predict injection profiles for wells with outdated data or without data by analyzing those injectors whose injection profiles are well characterized. Five pivotal parameters were selected to be fed into the subtractive clustering algorithm and ANFIS (adaptive-network-based fuzzy inference system) to model their non-linear relationships with the injectivity of each producing layer. Experiments in comparing the two-step method and the backpropagate feed-forward (BPFF) neural network showed that the two-step method can automatically generate a more simply structured fuzzy inference system (FIS) and can simulate complicated numerical nonlinear relationships with higher accuracy.
This method was used in injection profile prediction in one block of the Daqing oilfield. The average accuracy was shown to be above 80%.
3D Reservoir Characterization and Reservoir Management Study, October, J Nubia Field, Gulf of Suez, Egypt
Authors: Gaber Nabil Salah , Ahmed Hassan Alhussieny , Stoner Douglas T. , Artigas Gabriel B. , Mercado Gary M. , Mahgoub Ismail Shaban , Elreheem Mohamed G 
Published: December 2007

Abstract
An extensive, multi-discipline field study was completed in 1999 on the October J Nubia reservoir, located in the Gulf of Suez, Egypt. Although this field is relatively small (7 active wells, 132 MMBO OOIP) as compared to other Gupco's fields, the study proved worthwhile, generating three development prospects, all of them have been drilled and resulted in a rate increase of 6000 BOPD and a reserve gross of 6.6 MMBO.
The study team built a comprehensive, 3-dimensional Earthvision reservoir property model which was an excellent building block for understanding reservoir volumes and performance. The property model provided the tools necessary to understand fluid migration across faults in a 3-dimensional setting. The structural analysis began with the reinterpretation of a full-field, 3-dimensional seismic data set. The structural model was then populated with petrophysical parameters to produce the property model.
Extensive reservoir performance mapping also helped our understanding of fluid movement within the reservoir and helped identify areas of bypassed pay. As an example, watercut maps constructed for each of the fourteen reservoir subzones helped determine primary pathways of water encroachment.
The reservoir is a tilted fault block encompassing 750 acres. The producing formation is the highly prolific carboniferous Nubia sandstone with an average gross pay thickness of 600 feet, net pay thickness of 375 feet, porosity of 23 percent, and permeability in the darcy range. The reservoir has a fairly strong natural waterdrive, helping maintain reservoir pressure above the bubble point.
Even though the reservoir was forecasted to recover 48% of the original oil-in-place, the study located three areas of poor sweep. The three authorized drilling prospects are estimated to recover an additional, risk-weighted reserves of 9 MMBO. In addition, a detailed zonal performance analysis helped identify perforation and conformance work in existing wells, which should recover an additional 3 MMBO. The resulting property model and reservoir development plan now provide the operational tools necessary for managing this property for the next several years.
Synthetic Seismograms: Value of Adequate Log Data Process
Authors: Avu A. A. , Odegbesan C. O. , Pointing E. G. , Udoh N. B. , Kolarsky R. 
Published: December 2007

Abstract
Sonic and density logging tool responses are susceptible to poor borehole conditions. The ability to replace spurious well log responses with a reasonable estimate prior to generating a synthetic seismogram would mitigate stretching and squeezing to force a match with the seismic. This paper focuses on the importance and impact of shale editing on the quality of well – to – seismic match and describes the trend curve approach used.
A Study of IOR by CO2 Injection in the Gullfaks Field, Offshore Norway
Authors: Agustsson H. , Grinestaff G. H. 
Published: December 2007

Abstract
This paper describes the feasibility study of a large-scale miscible CO2-WAG (MWAG) injection scheme in the Gullfaks Field, offshore Norway. We describe the reservoir engineering workflow and simulation techniques, the predicted production and injection profiles, and the main infrastructure solutions under consideration.
Compositional cross-section models and recently available streamline-tracer simulation techniques are employed to scale up from element models to a fast, full-field simulator with a high degree of flexibility.
The starting point for the workflow is a set of black oil and streamline front tracking models, history matched on coarse and fine grids. A fast, finely gridded streamline model is used to identify the MWAG injection targets, define injection well locations and completion strategy. Fine gridded cross-sections are extracted and used in a compositional simulator to study and quantify the miscible displacement process. These are the used to derive scaling parameters used in a simple, ultra-fast streamline-tracer model, scaling the MWAG process up to field level. The streamline-tracer model interactively optimises solvent allocation and generates production predictions on a well-by-well basis. Water flood recovery and incremental IOR are predicted simultaneously in a single simulation run.
In addition, the general economic limitations and example technical solutions for implementation of a CO2 MWAG on the Gullfaks Field are briefly described.
Estimation of Oil Recovery and CO2 Storage Capacity in CO2 EOR Incorporating the Effect of Underlying Aquifers
Authors: Bachu Stefan , Shaw Jerry C. , Pearson Robert M. 
Published: December 2007

Abstract
Atmospheric concentrations of CO2 have risen since the beginning of the industrial revolution, primarily as a consequence of fossil fuel combustion for energy production and other industrial activities. Recognizing the challenge imposed by the potential for climate change, recent initiatives by various governments and by energy producers target a significant reduction in the intensity of CO2 emissions into the atmosphere. A major mitigation strategy for reducing the intensity and amount of CO2 emissions into the atmosphere is CO2 capture and sequestration, of which geological sequestration is a major component. Although enhanced oil recovery operations have the lowest capacity of all options for geological CO2 sequestration, they are most likely to be implemented first because of the additional economic benefit that will help offset the cost of CO2 sequestration.
Assuming that the pore space previously occupied by the produced oil can be backfilled with CO2, a methodology has been developed for the identification and screening of oil reservoirs that are suitable for CO2 flooding and for estimating their CO2 sequestration capacity at depletion, as well as under enhanced oil recovery.
The methodology has been applied to close to 11,000 oil pools in the Western Canada Sedimentary Basin that are recorded in provincial reserves databases. Of these, 4,767 oil pools are technically suitable for CO2 flooding, with an estimated incremental oil production and total CO2 sequestration capacity of 350×106 m3 (2,200 MMbbl) and 988 Mt CO2, respectively. However, only 110 oil pools have individual CO2 sequestration capacity greater than 1 Mt CO2 each, but together they account for ~61% of the total. The incremental oil production from these 110 oil pools is estimated to be 150×106 m3 (930 MMbbl) oil, and these oil pools should be considered first in detailed studies of CO2 EOR and sequestration.
To account for the effect of underlying aquifer influx that reduces CO2 storage capacity, analysis of the production history of these 110 oil pools shows that the water-oil and gasoil ratios are indicative of the strength of the underlying aquifers, but the recovery factor is not. The underlying aquifer is considered strong if cumulative net WOR&gt;0.25, and weak if WOR&lt;0.15. For WOR between 0.15 and 0.25, strong aquifer support is indicated by cumulative GOR&lt;1,000 m3/m3 (5,600 scf/bbl), otherwise the aquifer support is weak. Material balance analysis on 19 of these oil pools with active aquifers indicated that, if the reservoir pressure is only allowed to increase back to the initial pressure, the CO2 sequestration capacity is reduced on average only by ~3%, if the underlying aquifer is weak, and by ~50% if the underlying aquifer is strong.
Investigation of Liquid CO2 Sequestration and EOR in Low Temperature Oil Reservoirs in the Illinois Basin
Authors: Frailey Scott M. , Grube John P. , Seyler Beverly , Finley Robert J. 
Published: December 2007

Abstract
Current studies of geologic storage of CO2, with the exception of CO2 sequestration in coal beds, focuses on supercritical CO2, emphasizing the stability of the fluid, solubility of CO2 in saline formation water and miscibility with crude oil. Likewise, with the exception of very early research, the use of CO2 to enhance oil recovery (EOR) historically focused on supercritical CO2 to achieve miscible conditions with crude oil. The only possibility of liquid CO2 geologic storage is in formations with temperatures less than the critical temperature of CO2. Due to the naturally occurring geothermal temperature gradient, most all geologic formations currently considered for CO2 sequestration and EOR exceed the TcCO2.
A research plan has been developed to investigate the use of depleting (mature) oil reservoirs with formation temperatures less than critical temperature of CO2 to sequester liquid CO2 and investigate the implications of EOR from the liquid CO2 displacement process. Relatively higher pressures are required to attain liquid CO2, which translate to fracture gradients as high as 1.0 psi/ft. However, fracture stimulation data published in early literature and field data from fracture stimulation companies in the Illinois Basin show that fracture gradients of up to 1.0 psi/ft are commonly recorded in the shallower producing horizons of the Basin. Therefore, the pressure requirement may not be a detriment.
Because of the liquid/gas phase changes and consequent changes in density and viscosity of CO2 at subcritical temperatures, low temperature oil reservoirs provide a unique opportunity for liquid CO2 storage and the application of a novel and innovative EOR-CO2 cyclic multi-reservoir displacement process within the Illinois Basin.