bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pore-network Prediction of Residual Oil Saturation Based on Oil Layer Drainage in Mixed-wet Systems
Authors: Ryazanov A. V. , van Dijke M. I. , Sorbie K. S. 
Published: July 2010

Abstract
Since EOR methods mobilize oil trapped by capillary and viscosity forces during waterflooding, prediction of residual oil saturation (Sor) after waterflooding is very important before carrying out any EOR process. The mechanism through which a particular EOR method, such as gas displacement, actually works to reduce residual oil depends in turn on how that oil is trapped at the pore scale. In this respect, pore-scale network modelling can be used to estimate both the nature of the trapped residual oil and the relevant flow parameters in its subsequent mobilization, if the correct physics of oil drainage are properly included.
During water flooding of mixed-wet systems, oil may drain down to relatively low residual saturations. A number of studies have indicated that such low saturations can only be reached when oil layers in pore corners are included in the pore-scale modelling. van Dijke and Sorbie (2006) obtained accurate thermodynamically derived criteria for oil layers existence in pores with non-uniform wettability caused by ageing, which is more restrictive than the previously used geometrical layer existence criteria. Recently, Ryazanov at el. (2009) have included these thermodynamic criteria in a two-phase pore network model, which takes as input geometrically and topologically representative networks, to calculate realistic Sor values for mixed-wet and oil-wet sandstones.
In this work, the network model has been validated through modelling of experimental data for water-wet and mixed-wet systems. A very good match has been obtained between experimental and simulated relative permeabilities for strongly water-wet Berea sandstone and oil-wet sandstone. Comparison with a range of mixed-wet core waterflooding experiments (Jadhunandan and Morrow 1995) showed good agreement with experimental residual oil and oil recovery efficiency.
This paper introduces the correct thermodynamically based physics of how residual oil is trapped in systems of arbitrary wettability. It is extremely important to understand this process, since the residual oil is the "target oil" for most EOR processes.
Upstream Oil and Gas Project Development Timing
Authors: Feng Shuqiang 
Published: July 2010

Abstract
Delays of project development have become one of the major concerns in the upstream oil and gas industry. An accurate projection of project timing is very important in production forecasting and project economics.
Statistical analysis shows that Time from Discovery to Production (TDP) has lognormal distribution, and thus, behaves like a random variable (Hattis and Burmaster, 1994). Using the historical average TDP to predict TDP of a new discovery is the same as predicting stock prices with history price data, and therefore, is not reliable, based on the random walking theory (Malkiel 1973), which states that the past movement or direction of the price of a stock or overall market cannot be used to predict its future movement. Operators have optimistic bias in their own project development timing estimation, and this becomes one of the major causes of project delays. The random nature of TDP and the operator's optimistic bias regarding project timing could mislead both investors in project economic valuation and contractors in market planning.
In order to increase the accuracy and objectivity of the project timing estimation and to predict project delays, this paper analyzes the First Production Time (FPT) estimation of oil and gas upstream projects by introducing a stage based multi-factor model in a dynamic environment. In this model, projects will be divided into seven different stages in the field development life cycle, which include Exploration and Discovery, Appraisal, Conceptual, FEED, EPC Bidding, EPC, and Producing. Then, the model will allocate estimated time to each stage including the gaps in between stages based on historical records and a set of factors. These factors include discovery commerciality, development feasibility, geopolitics, global economy, water depth, operators/partners strategy, project financing, contractor capacity constraints, etc, which would affect the project timing in specific stages.
Pore-Level Investigation of Heavy Oil and Bitumen Recovery Using Hybrid SAGD Process
Authors: Mohammadzadeh O. , Rezaei N. , Chatzis I. 
Published: July 2010

Abstract
Attempts have been made to reduce the energy requirements of a Steam Assisted Gravity Drainage (SAGD) project through coupled thermal-solvent processes such as hybrid SAGD, ES-SAGD, SAP and SAS. The augmented process brings superior features to the SAGD process in terms of reduced energy requirement, enhanced quality of produced oil and also improved oil recoveries. The pore-level recovery mechanisms of the hybrid SAGD process have not been investigated yet. The main objective of this paper is to visually investigate and to document the pore-scale events of the hybrid SAGD process using glass micromodel type of porous media. Different additives (n-pentane and n-hexane solvents) were added to steam prior to injecting into the model. Experiments were conducted in an inverted-bell vacuum chamber to reduce the excessive heat loss to surrounding. The results indicate that the gravity drainage process takes place through a thick layer of pores, in the direction perpendicular to the nominal oil-gaseous mixture interface, within the mobilized region. The interplay between gravity and capillarity forces results in the drainage of mobilized oil. The visualization results demonstrated coexistence of water-in-oil and solvent-in-water emulsification at the interface, due to the local condensation of both the steam and the vaporized solvent. The extent of emulsification depends directly to the temperature gradient between the gaseous mixture and the cold bitumen. Asphaltene precipitation was also observed when the condensed solvent reached to the bitumen interface. As the nature of the process tends towards being partially miscible, the extent of film-flow drainage type of mobilized oil was also significant. Other pore-scale phenomena such as localized entrapment of steam and vaporized solvent followed by condensation, steam and gaseous solvent condensation at the interface due to temperature gradient, capillary instabilities, and snap-off of liquid films were also illustrated using these pore-level visualization experiments.
New Analytic Solutions for Pipe Helical Buckling Problems
Authors: Teymoorishamasbi M. , Mohammadsalehi M. , Rashed G. , Salahshoor K. 
Published: July 2010

Abstract
There are some numerical solutions(4,5) for pipe buckling problems in vertical and horizontal wells, but, we need exact analytic solutions for precise analysis of pipe buckling problems. The first analytic solution for pipe buckling in a vertical well was presented by Lubinski and Woods in 1962(2). When the non-linear differential equation describing buckling behavior of pipes in vertical and horizontal wells was developed by R.F. Mitchell(6), this solution was found to be an exact analytic solution for this differential equation. No other analytic solution has been discovered until 2002(8), when, Mitchell himself developed three new analytic solutions for the vertical well buckling problems and two new analytic solutions for the horizontal well problems.
In this paper, these five solutions are described and modified to some extent, and the development and evaluation technique are presented. Some results of interest such as buckling contact force and critical force limits for pipe buckling also are developed. These analytic solutions are valuable both for predicting previously unanticipated buckling behavior and for providing guidance in further numerical evaluations of this problem.
Mechanical Alteration of Near Wellbore Mineralogy for Improved Squeeze Performance
Authors: Fleming N. , Ramstad K. , Wichers Hoeth L. , Kidd S. 
Published: July 2010

Abstract
Squeezing of clean, high permeability reservoirs frequently results in relatively short treatment lifetimes due to the low inhibitor adsorption rates achieved. One of the main controls on inhibitor retention is near wellbore mineralogy. Clay-rich reservoirs that contain abundant kaolinite, for example, often have long squeeze lifetimes as enhanced inhibitor adsorption can occur on the clay surface. The occurrence of CaCO3 cement in the near wellbore can also enhance inhibitor retention by forming a Ca2+/inhibitor complex.
Previously published research (Fleming et al., 2009a) demonstrated the potential to mechanically alter the near wellbore through incorporation of low concentrations of kaolinite and organosilane. The data presented in the present work shows that the additional incorporation of calcium carbonate provides a step change in the potential squeeze lifetimes achieved. This paper will present the results of utilising low, non-damaging concentrations of kaolinite and calcium carbonate particles in the preflush followed by scale inhibitor and organosilane in the main treatment. The kaolinite particles are retained in the near wellbore by the organosilane and enhance the number of potential sites for inhibitor adorption. At the same time, dissolution of the calcium carbonate particles by the acidic scale inhibitor forms a Ca2+/inhibitor complex that further enhances inhibitor retention.
A review of the technology performance envelope has been made through coreflooding that includes optimising the concentration of injection particles versus permeability, the ratio of injected kaolinite to carbonate particles, performance at elevated temperature (175°C) and an assessment of how often a well would require retreatment with particles. The latter has involved successive coreflooding of the same plug with the full treatment package followed by brine flowback and retreatment with scale inhibitor alone or with organosilane. This information can be used by the assets in their evaluation on potential use of the technology.
Field Implementation of a Novel Solids-Free System to Minimize Fluid Loss during Overbalanced Workover Operations
Authors: Vasquez Julio , Waltman Bart , Eoff Larry 
Published: July 2010

Abstract
Controlling fluid loss into the formation is of critical importance during overbalanced workover operations to minimized near-wellbore damage invasion by the completion fluid, which can yield problems associated with poor wellbore cleanout and loss of hydrocarbon reserves. In addition, fluid loss can increase costs associated with rig time and treatments devoted to restore the initial condition of the formation. Traditional techniques to minimize fluid loss use solids or viscous pills, although it has been amply documented that these systems can damage the formation if not properly removed after the treatment.
This paper presents the laboratory development and validation of a novel solids-free fluid-loss (SFFL) system used during overbalanced workover operations. This system relies on an ionic polymer that decreases matrix permeability to aqueous fluids, limiting leakoff into treated zones. This polymer immediately adsorbs to the surface of the rock, eliminating the need to shut the well in. In addition, this system does not require the use of breakers, which eliminates negative impact on post-stimulation well productivity. Laboratory test data show the capability of the material to control fluid leakoff and achieve high levels of regained permeability to hydrocarbons.
To date, about 60 jobs have been performed with this novel SFFL system. The paper discusses field results from the application of this system during overbalanced workover operations and other applications where maintenance of a hydrostatic column is necessary for well control. This system has been proposed for solving partial and total loss to full circulation in overbalanced operations such as: (1) lost-circulation events occurring during cementing, fracturing, and drilling, (2) well intervention cleanouts by coiled tubing (CT) and hydraulic workover (HWO), (3) gravel packing, (4) replacement of artificial lift equipment (i.e., electrical submersible pumps), and (5) overbalanced tubing-conveyed perforating (UTCP), among others.
Optimization, Uncertainty Analysis and Upscaling of Rock-Physics Models
Authors: Kazemi Alireza , Modin Dimitry 
Published: July 2010

Abstract
During the last years, geomodel to seismic 3D and 4D feed back loops are becoming a new industry standard in geoscience. These loops are basically suited for automatic geomodel updating and history matching where the discrepancies between seismic data and geomodel petrophysical infilling are detected. One of the most important components of this type of loops where the synthetic seismic data computation is a compulsary step is the Rock-Physics (RPM) or Petro-Elastic Model (PEM). RPMs are widely used in geoscience for different reasons: 1) modelling of the elastic logs to provide different fluid scenarii; 2) quantitative lithoseismic interpretation and supervised seismic facies classifications; 3) 3D and 4D loops.
In this paper we address several aspects: 1) different issues of RPM optimization at log scale; 2) uncertainty assessment of the RPM modelling results; 3) different approaches for RPM upscaling / recalibration at geological grid scale. The problem of RPM optimization and upscaling is an inverse nonlinear problem where around 20 of non-correlated coefficients in shale and sand compaction depth trend laws need to be found. Optimization is carried out with the means of global optimization tool based on simulated annealing algorithm. During the optimization the choice of the cost function is of a high importance. The uncertainty analysis is basically performed to assess the quality of the optimization and to establish some thresholds above which the results of modelling are qualified.
Our methodology was applied for a turbiditic West African offshore field. The result shows that such optimization methodology can reduce significantly the differences between observed P, S-impedances data and modelled ones from the optimized RPM compared to the base RPM. The results of forward modelling in elastic domain match better the 3D inverted seismic data with around 15% reduction of residuals due to only RPM recalibration.
From our observations, an upscaling of the RPM remains a delicate task which is of a second order importance compared to the fine tuning of the RPM at log scale. When the RPM is used for the forward seismic modelling, correct restitution of the elastic properties contrasts by the RPM is of high importance.
Interpretation of DFA Color Gradients in Oil Columns Using the Flory-Huggins Solubility Model
Authors: Zuo Julian Y. , Freed Denise , Mullins Oliver C. , Zhang Dan , Gisolf Adriaan 
Published: July 2010

Abstract
Downhole fluid analysis (DFA) has been successfully used to delineate reservoir attributes such as vertical and lateral connectivity and properties of the produced fluids. The new-generation DFA tools not only measure bulk fluid properties such as gas/oil ratio (GOR), density, and light-end compositions of CO2, C1, C2, C3–C5, and C6+ more accurately but also color (optical density) that is related to the heavy ends (asphaltenes and resins) in real time at downhole conditions. In addition, the color measurement is one of the most robust measurements in DFA. Therefore, color gradient analysis in oil columns becomes vital to discern reservoir complexities by means of integrating advanced asphaltene science with DFA Fluid Profiling.
In this paper, a thermodynamic asphaltene grading model was developed to describe equilibrium distributions of heavy ends in oil columns using the multicomponent Flory-Huggins regular solution model combined with a gravitational contribution. The variations of oil properties such as molar volume, molar mass, solubility parameter, and density with depth were calculated by the equation of state (EOS). A three-parameter Gamma distribution function was employed to characterize asphaltene components. The primary factors governing asphaltene distribution in reservoirs are the gravitational term, which is determined in part by the size of the asphaltene molecular or colloidal particle, and the solubility term, which is determined in large part by the GOR. Consequently, it is critical to accurately measure both the fluid coloration and the GOR to understand the asphaltene distribution. The two field case studies showed that colored resins (asphaltene-like heavy resins) were molecularly dissolved in condensate oil columns whereas asphaltenes were dispersed as nanoaggregates in crude oils. The heavy ends (resins or asphaltenes) have a preference of going to the bottom of the oil column both because of gravity and the variation of the liquid-phase (live oil mixture) solubility parameter. The results obtained in this work were in accord with the observations in recent advances in asphaltene science. The asphaltene distributions were consistent with an equilibrium distribution implying reservoir connectivity. In both cases, the subsequent production data proved the reservoir connectivity and the methods developed herein were validated. This methodology establishes a new powerful approach for conducting DFA color and GOR gradient analyses by coupling advanced asphaltene science with DFA Fluid Profiling to address reservoir connectivity.
Potential and Early Opportunity-Analysis on CO2 Geo-Sequestration in China
Authors: Xuan Zhao , He Shunli 
Published: July 2010

Abstract
CO2 geo-sequestration, as an effective method to reduce Green House Gas emissions, is a front subject in China. In order to identify the potentials of implementing large scale CO2 sequestration projects according to China's current development tendency, this paper analyzes the general formation conditions of the main oilfields in China, which are manifested in complex formation structure with strong heterogeneity, low or ultra-low permeability and low porosity.
In China, the main application mode of CO2 sequestration, also the most profitable method, is to inject CO2 into oil and gas reservoirs to enhance recovery. Meanwhile, 60%-80% of the injected CO2 could be stored into the formation. Jilin oilfield in northeast of China, the dominant test field for CO2 sequestration, has been listed into the National Key Program in 2006. Pilot tests reveals formation here is featured with well developed sand body, good connectivity, well defined cap rock, undeveloped fractures, and independent hydro-geological system, which contribute to a considerable and secured storage for CO2. Though still on the initial stage, studies here would shed light on the further researches in China.
Some unique advantages of conducting CO2 sequestration projects in China have been summarized and analyzed in this work too. Most of the new-found oil and gas reservoirs belong to low-permeability reservoirs, wherein CO2 flooding shows its superiority over conventional water injection in tight formations. Moreover, both main CO2 sources (coal-fired plants & power plants) and injecting sites(low-permeability reservoirs) locate in northern and eastern China, which would meet the demand of CO2-EOR and shorten the distance of transportation to reduce corrosion risk and operation cost. Although being not regulated by Kyoto Protocol, positive measures of CO2 sequestration in China possesses a significant and far-reaching meaning to releive the pressure of global environment.
Calcite Scale Prediction and Management in a Chalk Reservoir – Field Cases
Authors: Zhang Yuping , Samuelsen Eivind , Frederiksen Rene , Roberts David , Ginty Bill 
Published: July 2010

Abstract
This paper demonstrates a field case study where large volumes of deferred oil, due to calcite deposition, have been reduced by effective scale modeling and a strong focus on optimised well performance.
The South Arne field, operated by Hess Denmark, on behalf of the South Arne Partnership, is an oil field in the Danish sector of the North Sea. Production is from a chalk reservoir using de-sulphated seawater injection for pressure support. Calcite deposition has been problematic in some of the wells with a variety of mitigation and clean-up methods being employed. The deferred production peaked with 100,000 barrels of oil in 2006. Since then, the oil deferment has been reduced by 75 % by continuously improving the calcite scale prediction and prevention for the wells.
Modeling carbonate scale deposition is challenging and many scale prediction models can be over-conservative, leading to unnecessary chemical injection, excessive use of chemicals and sub-optimal oil production. A new methodology for predicting calcite scale has been applied to the South Arne field, becoming a successful tool for downhole scale management.
This new approach is based on scale kinetics as a function of temperature, integrated with detailed pressure-temperature traverse data derived from the interpretation of well tests and gas lift performance. Results have been used to guide well operation decisions and to support a new scale prevention strategy based on deep injection of large volumes of lift gas.
Accurate calcite scale prediction is sensitive to the carbonate alkalinity. The approach described here is based on simulating the calcite scaling kinetics from reservoir to wellbore. Model results show that produced water is close to calcite saturation from deep reservoir to the wellbore, and this has been used as the basis for calculating carbonate alkalinity in the produced water. Hence in this paper the calcite saturation index for the onset of scaling has been defined using calcite kinetics to give a fixed scaling rate rather than the more customary use of a fixed saturation index.
In addition, well performance models were completely re-worked to include observations from recent well interventions and new data input parameter validations.
The calcite scale prediction methodology described here has provided the South Arne field with benchmarked operating scale envelopes that on a regular basis are utilised to optimise well performance in terms of risk and reward.