bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Natural Fracture Properties on Production Variability of Individual Wells in Multiphase Oil Reservoirs
Authors: Lopez Bruno , Gonzalez Laureano , Aguilera Roberto , Garcia-Hernandez Francisco 
Published: April 2012

Abstract
Fracture properties that are responsible for production variability of individual wells in oil reservoirs are investigated with the use of multi-phase dual porosity models. Simulation work and sensitivity analyses are performed using Top-Down reservoir modeling, i.e., starting with a simple case that increases in complexity based on the understanding of basic reservoir properties. Fractional production variability plots (FPVP) are used to measure the degree of heterogeneity of the naturally fractured reservoir considered in this study. Straight lines or smooth curves close to 45 degrees in the FPVP indicate homogeneous reservoirs which can be single porosity or dual porosity with uniform fracture distribution. An increase in curvature in the FPVP indicates higher heterogeneity, particularly in the fracture system. Fracture characteristics such as fracture distribution, aperture, geometry and orientation are part of the sensitivity analyses as well as fluid characteristics and fluid-rock interaction. Fracture density and length are found to have the largest impact.
Results of this work are corroborated when compared with real data from a naturally fractured multi phase oil reservoir in Mexico. A variability distribution model (VMD) is used to match the simulated production history of the field on a FPVP plot. The FPVP curvature is found to be proportional to the simulated normalized standard deviation (NSD) of the cumulative well production. As a result two equations are developed that correlate both fracture density and length with the NSD, respectively. Scatter plots are used to identify the effect of each parameter on the NSD.
It is concluded that the variable distribution model provides a realistic assessment of heterogeneity in naturally fractured multi phase oil reservoirs and helps with characterization of the reservoir.
Improved Predictivity through Use of a 3D Integrated Seismic Water Saturation Model in the Sierras Blancas Formation
Authors: Ucan S. , Monti L. , Cersosimo D. S. , Claa R. A. , Montagna A. O. , Quintero A. I. 
Published: April 2012

Abstract
A 3D integrated saturation model was built for the Sierras Blancas Formation of the Neuquén Basin, Argentina. The saturation model was based on core, logs and seismic data. History match of reservoir pressure and well productivities were taken into account to accurately determine the gas in place and productive reservoir boundaries, specifically using 3D seismic water saturation in the gas condensate formation. The Sierras Blancas Formation is an eolian deposit. In tight, wet and diagenetically altered regions, the seismic inversion porosity and acoustic impedance based models were not adequate to describe the gas in place distribution. Further, the effective gas permeabilities in the tighter part of the reservoir are a strong function of the initial water saturation as evidenced by fewer condensate and water blocking problems of horizontal wells that navigated through low water saturation, high permeability regions. Any relationship between seismic impedance and porosity correlation degraded in areas affected by secondary diagenetic processes therefore necessitating the use of a saturation parameter. 30 vertical wells that had DT curves were selected based on their production and spatial location in order to establish a correlation between log saturation and seismic attributes. Seismic saturation cubes were generated by multiattribute seismic analysis and resampled into the simulation scale model. Log saturations were then co-kriged with the 3D seismic saturation. Water saturations obtained from the initialized simulation scale model were compared with the 2D saturation logs, the 3D seismic and the geological model scales. An objective function was defined to match the 3D seismic water saturation with the initialized simulation model water saturation. Model parameters were iterated until a satisfactory match with the initialized simulation model was obtained.
By focusing the saturation match at the initialization stage, seismic, geological, petrophysical and SCAL models were ensured to be consistent prior to the full history match. Well history matching was consequently achieved much more simply and quickly. This paper presents a new detailed methodology of 3D pseudo-seismic water saturation generation, modeling and simulation used to accurately define OGIP, the productive boundaries of the reservoir, and to design trajectories for new horizontal wells.
A Reservoir Management System for the World’s First Thermal Gas Oil Gravity Drainage Project
Authors: Rawnsley Keith , Ikwumonu Augustine , Bettembourg Solenn , Putra Pristwanto , Al-Ismaili Ibrahim 
Published: April 2012

Abstract
Thermally Assisted Gas Oil Gravity Drainage of a fractured carbonate heavy oil field in Oman is starting the full field phase. Unlike a normal steam flood, steam is used as a heating agent to enhance the existing gravity drainage mechanisms. The project has been piloted successfully.
The project start-up sequence consists of increasing off take from deviated producers followed by steam injection and aquifer pump-off. Steam will progressively fill the fractures whilst heated oil drains down in the matrix blocks and accumulates in an oil rim below the steam in the fractures. The fracture oil rim will be lowered by approximately 100m. Horizontal producers will be completed in the final fracture oil rim position.
As no analogues exist a large degree of flexibility has been incorporated in the field development plan to cover uncertainties including caprock integrity, erratic oil rim movement and heterogeneous steam distribution. To facilitate decision making an enhanced reservoir surveillance, modelling and management system has been built. Reservoir pressures, oil rim positions, temperatures and rock strain data are obtained from a range of observation wells. Further data are obtained from surface uplift, microseismic monitoring and fluid sampling. Static, fracture, dynamic and geomechanical reservoir models have guided the design of the reservoir surveillance program and underlie the operating guidelines for the reservoir. These provide operator reactions for a wide range of "what-if" events. A corporate real time data portal has been optimised for the unique requirements of this project allowing for analysis of all data streams. A system allows 3D display, through time, of reservoir data and model forecasts to ensure optimum performance analysis.
Initial application has resulted in identification of optimised well configurations and start-up sequence giving higher oil forecasts.
The learning is being applied further in Oman and has wider application.
Quantitative Remaining Oil Interpretation Using Magnetic Resonance: From the Laboratory to the Pilot
Authors: Mitchell Jonathan , Edwards John , Fordham Edmund , Staniland John , Chassagne Romain , Cherukupalli Pradeep , Wilson Ove , Faber Rien , Bouwmeester Ron 
Published: April 2012

Abstract
Laboratory and single well pilot nuclear magnetic resonance (NMR) logging results are obtained for an enhanced oil recovery (EOR) project using a common physics of measurement at both scales. Screening for chemical EOR efficacy usually begins in the laboratory before moving to single or multiple well field pilots. Laboratory experiments were conducted on a low-field bench-top NMR magnet with fluid injection protocols that matched the log-inject-log concept of the single-well in situ EOR evaluation (Arora et al. 2010). In situ measurements of the oil and brine saturations during the flood, by "diffusion-editing" protocols and by relaxation measurements alone, are shown to be in quantitative agreement with gravimetric assays of recovered oil. Spatially resolved T2 analysis (the laboratory equivalent of a standard NMR well log) revealed non-uniform oil saturation during the EOR process in short core plugs. The final remaining oil distribution is confirmed by a reservoir simulation in a geometry identical to the NMR-compatible core holder. In a region of the core-plug not influenced by end effects, complete recovery of the oil was observed, consistent with the the single-well in situ EOR evaluation. The quantitative estimates of remaining oil, using a tool-equivalent NMR protocol, demonstrate the potential for NMR logging of remaining oil in monitoring wells completed with NMR-transparent casing.
Using a new Intelligent Well Technology Completions Strategy to Increase Thermal EOR Recoveries–SAGD Field Trial
Authors: Bedry Mark , Shaw Joel 
Published: April 2012

Abstract
Well segmentation and instrumentation have been used to improve steam injection and production conformance in a completions strategy for a thermal-enhanced oil recovery (EOR) project by using intelligent well technology and interval control valves (ICVs). The initial field trial is ongoing in the injector of a Northern Alberta steam-assisted gravity drainage (SAGD) well pair. The development of the completion technology suitable for thermal conditions, initial field trial results and the plans for further development are described in this paper. The application modeling shows that, depending on the level of heterogeneity present in the reservoir, a 45% reduction in the steam-oil ratio and an almost 70% increase in recovery can be achieved in a SAGD process when both improved injection conformance and producer differential steam-trap control can be applied in a segmented horizontal well pair. A cost-effective, intelligent-well completion solution to achieve this segmentation and control has the potential to add substantial value to field developments through improved steam conformance. This will result in increased energy efficiency and oil recovery. The method under development is also applicable to a wide range of other thermal EOR processes such as cyclic steam stimulation (CSS), steam drive, and variations, including, for example, those involving solvent additives.
The initial field deployment in the injector well was initiated to prove the technology, to demonstrate the feasibility of modifying the steam distribution, and to obtain best practices for future developments. A successful installation and commissioning of the intelligent completion has validated the technology. Lessons learned are highlighted. Early injection test results and data show a significant increase in the understanding of the injection and production behavior in the well pair. A test program to optimize the distribution of the steam injection in the well is underway, and the results are discussed. The intelligent completion technology under trial and proposed further developments should enable more extensive use of downhole measurement and control in thermal EOR projects than has been possible to date.
Evaluation of the Efficient Displacement Pressure in a CO2 Pilot Feasibility Study in a Giant Carbonate Oil Reservoir
Authors: Clara Cédric , Ali Ahmed Elsayed , Sener Ilhan 
Published: April 2012

Abstract
This paper evaluates the impact of reservoir pressure on displacement efficiency when injecting CO2 injection in a super giant Abu Dhabi carbonate oil reservoir. The term Efficient Displacement Pressure (EDP) was defined to distinguish it from Minimum Miscibility Pressure (MMP). EDP has similar characteristics as MMP, resulting in very high recovery when the operating pressure exceeds EDP/MMP. The need for the EDP concept arose when evaluating feasibility of a CO2 injection project. During this evaluation, displacement by CO2 was found to be very efficient at pressures much lower than the saturation pressure, and multi-contact miscibility between the oil and the injectant could not be proven by classical slim tube experiments in the EDP pressure range. EDP was assessed using different analytical and modelling approaches in the absence of reliable experimental results: (i) Analytical means, (ii) Equation of State (EOS) PVT Softwares, (iii) 1D Compositional Numerical Modelling. Simulations were performed using a 10-component EOS, well tuned using a variety of advanced PVT experiments. The 1D model was designed to mimic a representative part of the field where the feasibility of the CO2 pilot project was being studied. Results from the different methods were analyzed and compared to properly assess the EDP range. Investigations showed that determining exact EDP values remains difficult, because the results strongly depend on the methodology used, the ability of EOS to accurately predict slim tube experiments, and the dependency of recovery factor on the grid size in numerical simulations. The sensitivity to water saturation and water blocking were not investigated here. However, in the defined EDP range, it was demonstrated that very high displacement efficiency and recovery can be achieved by injecting CO2 at an operating pressure in the identified EDP range. The recovery was found to be extremely high, even if the EDP range is below the saturation pressure, where miscibility is not necessarily guaranteed. This calls into question the general pre-requisite that operating above MMP is a necessary condition for the success of a CO2 injection project.
Stretching the EOR Boundaries: Thermal Trial in one of Petroleum Development Oman's Deep Reservoirs containing Heavy Oil
Authors: Mandhari Musallam. S. , Hinai Sulaiman , Hinai R. , Abdkadir R. , Salhi M. 
Published: April 2012

Abstract
A cyclic steam pilot has been conducted in one of Petroleum Development Oman deepest heavy oil fields. The field is considered beyond conventional and proven enhanced oil recovery (EOR) technologies. However, as the target reservoir contains several billion barrels of heavy oil, a number of potential unconventional EOR technologies have been identified and considered for trialling.
During the screening process and despite the technical challenges, cyclic steam soak stood out as the technology that can be trialled to provide valuable information to reduce subsurface uncertainties such as permeability distribution, fraccing potential, injectivity and hot oil production capacity. In addition the trial is a key enabler for potential other unconventional EOR technologies in this field.
This paper will provide an overview of the development strategy for maturing this heavy oil reserves. The initial planning and the selection of the least risk and fastest project delivery strategy were critical to the fast implementation of this single well cyclic steam soak trial (CSS). The contracting strategy and the selection of the fit for purpose industrial standards are included in the discussion. Specific topics addressed include selection of the right equipment for better water specifications and higher steam quality are addressed. In addition, cold injectivity test, the results of the early injection and production cycles, and the surveillance program are presented.
A CT Scan Study of Immiscible Foam Flow in Porous Media for EOR
Authors: Simjoo M. , Dong Y. , Andrianov A. , Talanana M. , Zitha P. L. 
Published: April 2012

Abstract
A systematic CT scan aided laboratory study of N2 foam in Bentheimer sandstone cores is reported. The aim of the study was to investigate whether foam can improve oil recovery from clastic reservoirs subject to immiscible gas flooding. Foam was generated in-situ in water-flooded sandstone cores by co-injecting gas and surfactant solution at fixed foam quality. It was stabilized using two surfactants, namely C14-16 alpha olefin sulfonate (AOS) and mixtures of AOS and a polymeric fluorocarbon (FC) esther. Effects of surfactant concentration, injection direction, surfactant pre-flush and core length on foam behavior were examined in detail. Stable foams were obtained in the presence of waterflood residual oil. It was found that foam strength (mobility reduction factor) increases with surfactant concentration. Foam development and, correspondingly, oil recovery without surfactant pre-flush were delayed compared to the case with pre-flush. Gravity stable foam injection caused a quick increase of foam strength and an incremental oil recovery almost twice that for unstable flow conditions. Core floods reveled that the incremental oil recovery by foam was as much as 23±2% of the oil initially in place after injection of 4.0 PV of foam (equals to injection of 0.36 PV of surfactant solution) compared with water flooding. Incremental oil recovery was only 5.0±0.5% for gas flooding at the same injection conditions. It appears that oil production by foam flooding occurs due to the following main mechanisms: (1) residual oil saturation to gas flooding is lower than to water flooding, (2) formation of an oil bank in the first few injected pore volumes, which coincides with a large increase of capillary number and (3) transport of dispersed oil by the flowing foam lamellae, leading to long tail production at a fairly constant capillary number. Observations of this study support the concept that foam is potentially an efficient EOR method.
Novelty in Smart-Water Screening and Designing
Authors: Sultani Billal , Horvath-Szabo Geza , Zeng Huang , Abdallah Wael 
Published: April 2012

Abstract
A customized HPLC methodology is developed to allow characterizing and screening the recovery change due to ionic variation of injected water. Extended contact time is needed to see the impact of electrolytes on oil recovery. We could not observe significant differences in oil release when hydrophobized calcite particles are flooded with seawater with or without sulfate. However, a significant recovery difference between water and 0.1M MgCl2 solution is detected, where Mg2+ solution is able to recover more oil than water.
The developed methodology here allows experiments to take place within few days to provide results, which allows many runs to be performed. The advantages of this technique compared to the currently available methodologies are due to the small sample sizes and ease of use. Many columns can be analyzed; the packing material can be changed to calcite, chalk, or silica. In addition, different types of hydrophobic layer / particles can be used to coat the packing material. Comparing different electrolytes to one another, and determining the effect of electrolyte concentration on oil recovery requires many experiments. Therefore, this technique could be useful to make studies faster and easier to validate the recovery theories.
Development of New Polymers with Better Performance under Conditions of High Temperature and High Salinity
Authors: Wu Yongfu , Mahmoudkhani Amir , Watson Philip , Fenderson Thomas , Nair Mohan 
Published: April 2012

Abstract
It is estimated that about 7,000 billion barrels of oil will remain in reservoirs after production by conventional methods. This value is the target for Enhanced Oil Recovery (EOR) techniques. The purpose of the water-soluble polymers in EOR application is to enhance the rheological properties of the displacing fluids. These polymers have been successfully implemented in China’s oilfields. Given the harsh conditions present in most oil reservoirs, new problems and challenges arise with the use of such polymers. Currently partially hydrolyzed polyacrylamides (HP AMs) are the major class of polymers used for chemical EOR application. However, due to the high flexibility of HP AM chain in aqueous solutions, particularly at high temperature (HT) and at high salinity (HS), the molecular chains begin to fold irreversibly resulting in a significant loss in viscosity. In this paper, we are reporting a bench-scale development of new PAM-based polymers with improved performance in HSHT conditions. The new polymers were evaluated conditions for their viscosity performance at various temperatures and salinities. The polymers were dissolved at different concentrations in brines with TDS (Total Dissolved Solids) of 34,655 ppm and 180,000 ppm. Viscosity measured at room temperature is in the range of 30 to 120 cP at the shear rate of 6 RPM. After aging at 90 °C and 120 °C for six months under ultralow oxygen level (&lt; 5 ppb), viscosity remains relatively stable for some polymers while show a decline for others. Compared with the conventional HPAM polymers, these new polymers have much better stability at HTHS conditions.
Residual-Oil Recovery Through Injection of Biosurfactant, Chemical Surfactant, and Mixtures of Both Under Reservoir Temperatures: Induced-Wettability and Interfacial-Tension Effects
Authors: Al-Sulaimani H.. , Al-Wahaibi Y.. , Al-Bahry S.. , Elshafie A.. , Al-Bemani A.. , Joshi S.. , Ayatollahi S.. 
Published: April 2012

Summary
In this study, a biosurfactant produced by a Bacillus subtilis strain isolated from oil-contaminated soil from an Omani oil field was tested for its potential in enhancing oil recovery by a series of coreflooding experiments. It was found that the performance of the biosurfactant was increased by mixing with chemical surfactants, by which the maximum production went up to 50% of residual oil at a mixing ratio of (50:50). The second objective of this study was to investigate the effects of the biosurfactant on wettability alteration and to estimate its tendency to loss caused by adsorption. The influence of biosurfactant on wettability was studied by contact-angle measurements, atomic force microscopy (AFM) technique on few-layer graphene (FLG) surfaces, and Amott wettability tests on Berea sandstone cores. Contact-angle measurements showed that the wettability of the biosurfactant solution changes to more oil-wet as the angle decreased from 70.6 to 25.32° when treated with 0.25% (w/v) biosurfactant solution. Amott testing showed a change in wettability index from strongly water-wet in the untreated core toward less water-wet in biosurfactant-treated cores. These results confirmed the ability of the biosurfactant to alter the wetting conditions against different surfaces, thereby serving as a mechanism for enhancing oil recovery. The maximum loss of biosurfactant caused by adsorption was 1.2 mg/g of rock, which is comparable with reported chemical-surfactant values.
Engineering Study of the Cook Ranch Field, Shackelford County, Texas
Authors: Wilson Wallace W. 
Published: April 2012

Abstract
The Cook Ranch Field produces from a very permeable lens of Cook Sand of lower Permian or upper Pennsylvanian age, occurring at an average depth of 1,300'Ft. The field was discovered in 1926, and has been operated with low pressure gas injection since July, 1927, one of the first such projects in Texas. Cumulative recovery to Dec. 31, 1950, was 14,701,131 bbl of crude oil, an average of 1,013 bbl per acre-ft of oil section, and 72.5 per cent of the oil originally in place. Analysis of the reservoir performance indicates that gravity drainage has been an important factor in the producing mechanism. The high permeability and uniformity of the reservoir were extremely favorable for this type of operation.

Introduction
The Cook Ranch Field is the largest of a number of relatively small, shallow producing areas near Albany, in Shackelford County, Texas. This field is one of the first to be operated by gas injection in Texas, and probably is the most successful low pressure gas injection project ever attempted. The field is owned entirely by Roeser and Pendleton, Inc., and Continental Oil Co., aud has been operated by Roeser and Pendleton, Inc., since it was discovered. This study has been made possible through the cooperation of Roeser and Pendleton, Inc., in making available a remarkably complete set of records covering all phases of their operations. The purpose of this paper is to present a summary of the history of the operations through Dec. 31, 1950, and to analyze some of the factors which appear to be responsible for the success of the project. Information concerning the physical plant and the early gas injection history has been presented in an earlier paper.