bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Cross-Polarized Microscopy to Optimize Wax-Treatment Methods
Authors: Bacon Mark M. , Romero-Zerón Laura B. , Chong Ken K. 
Published: October 2009

Abstract
Paraffin wax deposits are known to be a worldwide problem in the upstream petroleum industry. Considerable resources are expended on inhibiting or removing wax deposits every year. Paraffin wax is not the only type of crude oil based wax. Microcrystalline waxes, composed of naphthene and iso-paraffin molecules, also exist but are not well studied. The predominance of paraffin (also called macrocrystalline) wax and paraffin wax inhibition techniques will likely lead to paraffin wax treatments being applied to naphthene based reservoirs. It is unclear how well a paraffin based treatment will apply to naphthene based oil.
The current study investigates the use of Cross-Polarized Microscopy (CPM) to determine if a crude oil contains macrocrystalline or microcrystalline waxes. CPM can determine the size and morphology of wax crystals because crude oil wax crystals are known to be anisotropic. Macrocrystalline waxes are known to present with larger, elongated structures while microcrystalline waxes present with smaller, rounded structures. The type of wax present in the crude oil can be determined using crystal morphology and size. Knowing which type of wax is present in the oil will help to choose which type of wax inhibitor will be used. This study has shown that CPM can be an effective tool to determine the type of wax present in a crude oil. Paraffin wax crystals are shown as being elongated structures with statistically larger sizes than the microcrystals. Microcrystalline waxes are shown to be statistically smaller and rounded structures. CPM is a simple, cost-effective method that can be used in addition to standard tests to determine if a crude oil is paraffin or naphthene based. In the future this test can be used to prevent paraffin wax treatments being applied to naphthene based reservoirs and to help optimize the specific inhibitor chosen.
Complex Flow and Composition Path in CO2 Injection Schemes from Density Effects in 2 and 3D
Authors: Nasrabadi Hadi , Firoozabadi Abbas , Ahmed Tausif 
Published: October 2009

Abstract
CO2 injection has been used to improve oil recovery for the past three decades. In recent years, the improved recovery method has become more attractive because of the dual effect; injection in the subsurface allows: 1) reduction of CO2 concentration in the atmosphere to reduce global warming, and 2) improved oil recovery.
Some of the projects considered for CO2 injection are based on CO2 miscibility with oil at the minimum miscibility pressure (MMP). The MMP is often measured in a slim tube. The slim tube data are used for the purpose of field evaluation and for the tuning of the equations of state. The slim tube represents one-D horizontal flow.
In this work, we will show that CO2 MMP, often measured in a slim tube, may not have relevance to CO2 injection in a 2D (or 3D) reservoir. When CO2 dissolves in the oil, the density often increases. The increase in density changes the flow path form one-D to two-D (downward flow). On the other hand, when a gas phase evolves from mixing of CO2 and the oil, the gas phase is often lighter than CO2 and the oil. In downdeep injection for the some of the cases when CO2 is heavier than the oil (in the conditions of some offshore high pressure field) the evolved gas phase moves upward due to buoyancy. As a result of these two density effects the compositional path in a reservoir is radically different from the flow path in a slim tube. The change in flow path may prevent miscibility development. The flow path is also altered from heterogeneity and from diffusion.
In this work, we present results from simulation in slim tube and in a two-D vertical reservoir and show significant effect of gravity and heterogeneity. One main conclusion from this work is that for successful CO2 injection projects there is need to have accurate density data for CO2/oil mixture with different CO2 compositions.
A Macroscopic Method of Measuring Microscopic Scale Phenomena in Porous Media: The Transition Between a Sharp and Diffuse Imbibition Front
Authors: Aminzadeh Behdad , DiCarlo David 
Published: October 2009

Abstract
The efficiency of one fluid displacing another through a permeable medium depends greatly on the pore-scale dynamics at the main wetting front. In particular, the capillary desaturation curve (CDC) shows that with increasing capillary number the residual nonwetting phase saturation (Sor) decreases. This is hypothesized to be a result of the complex dynamics at the main wetting front, which manifests also itself in whether the front is sharp or diffuse. In the sharp front regime, the displacing fluid occupies nearly all the pores and throats behind the main wetting front and the saturation changes abruptly. In contrast, in the diffuse front regime, pores are filled gradually at the main wetting front, and the saturation change is gradual in space. Along with affecting the CDC, the different fronts can greatly alter the relative permeability curves, and the specific trapping mechanisms. Directly measuring the dynamics at the front is difficult. Instead, here we correlate the front dynamics to saturation overshoot, which occurs for moderate to high flux vertical displacements of low density fluid by a higher density fluid in 1-D homogenous permeable media.
We hypothesize the sharpness of wetting front can be explained by competition between two different pore - filling mechanisms (called snap-off and piston-like). The competition controlled by the velocity of the front and thus the injected capillary number. We conduct a series of infiltration experiments to determine the saturation profile as a function of capillary number for seven different fluids. We find that for each fluid there is a capillary number (called overshoot capillary number) below which saturation overshoot ceases and the front is diffuse. We find that overshoot capillary number is independent of the viscosity of the fluid, but does show a dependence on the surface tension. We also find that the fluid's vapor pressure plays no role in the front dynamics. We discuss how overshoot and desaturation have the same overall dependencies, but with critical capillary numbers 2-3 orders of magnitude apart which are most likely due to the lack of initial wetting layers.
Development of a Coupled Compositional Wellbore/Reservoir Simulator for Modeling Pressure and Temperature Distribution in Horizontal Wells
Authors: Shirdel Mahdy , Sepehrnoori Kamy 
Published: October 2009

Abstract
The calculation of production parameters that address multiphase flow in wellbores is challenging. A great deal of research has been conducted to simulate fluid flow in horizontal wells. In most cases, only stand-alone wellbore models for black-oil have been used to simulate reservoir and well dynamics interactions. These models are based on simplified assumptions that lead to unrealistic estimation of pressure and temperature distributions in the well. In addition, most reservoir simulators use rough estimates of perforation pressure as boundary conditions between wellbore and reservoir, and neglect pressure drop in the horizontal wells. A steady-state, non-isothermal, fully-coupled compositional wellbore/reservoir simulator is developed to simulate fluid flow in horizontal wells in conjunction with vertical wells. This simulator is capable of handling concurrent flow of gas, oil and water in both horizontal and vertical wellbores. It can also accurately calculate pressure and temperature profiles, holdup, and component mass-flow rates in wellbores. Our simulation results can explain remarkable differences in flow rate between coupled wellbore/reservoir simulator and stand-alone reservoir simulator at the early stage of production. In this study, variation of liquid fraction along the well is also investigated. Liquid is unloaded in the horizontal well at the early stage of production and then loaded, starting from the upstream of flow, at the late stage of production.
Pros and Cons of Applying Proxy-Models as a Substitute for Full Reservoir Simulations
Authors: Zubarev D. I. 
Published: October 2009

Abstract
This paper presents a comparative study of proxy-modeling methodology (also known as surrogate modeling or metamodeling) as a computationally cheap alternative to full numerical simulation in assisted history matching, production optimization and forecasting. The study demonstrates the solution space complexity for different simulation models and the applicability of the proxy-models to mimic it. Focus is given to the practical aspects of model construction and to the limitations of which engineers should be aware. Results of stochastic optimization driven by full numerical simulation are compared to the proxy-model solutions in order to demonstrate strengths and weaknesses of each approach and determine desirable areas of application.
Several simulation models of different complexity were used to demonstrate the impact of model structure, number of uncertainty parameters and type of problem on simulation model response and on efficiency of proxy-model application. The results are presented for different datasets, proxy-models and simulation model outputs to demonstrate the dependence of the approximation quality on these parameters. The dependence of the proxy-model prediction quality on sampling method, and on uncertainty domain complexity has been revealed. The efficiency of proxy-model application in history matching and production optimization was compared to stochastic optimization with full reservoir simulation.
The results of this study have demonstrated that with increasing complexity of the solution space and number of uncertainties, the application of the proxy-modeling methodology is not recommended for history matching. In the history matching case, the use of full reservoir simulations, combined with stochastic search methods, is preferable and, above a certain level of complexity, the only acceptable solution. Nevertheless, proxy-modeling might be a good approach for certain production optimization projects and appropriate tool for forecasting of Hydrocarbons Initially In Place (HCIIP) and oil recovery (OR).
This study suggests areas of application for proxy-models and full numerical simulation. It addresses pros and cons of both approaches in reservoir simulation and provides advice for their efficient application.
Surfactant Screening for Wettability Alteration in Oil-Wet Fractured Carbonates
Authors: Gupta R. , Mohan K. , Mohanty K. K. 
Published: October 2009

Abstract
Surfactants have been identified that can change the contact angle of an initially oil-wet calcite plate for all four types of reservoirs: low temperature-low salinity (&lt;50 °C, &lt; 3 wt %), high temperature-low salinity (70-90 °C, &lt; 3 wt %), low temperature-high salinity (&lt;50 °C, 4-8 wt %) and high temperature-high salinity. The contact angle was found to decease with the increase in temperature for all surfactants. About 35-70 % OOIP was recovered with most of the screened surfactant in all four regimes. The oil recovery was found to be a gravity-driven process. Rate of oil recovery increases with an increase in the extent of wettability alteration towards water-wet condition, temperature, and fracture density. Increase in IFT increases the oil recovery rate if the wettability can be changed to water-wet conditions and vice versa if the rock remains oil-wet.
New Mixer Optimizes Crude Desalting Plant
Authors: Linga H. , Al-Qahtani F. A. , Al-Qahtani S. N. 
Published: October 2009

Abstract
Saudi Aramco Gas Oil Separation Plants (GOSPs) utilize conventional static mixers (usually globe valves) for mixing of crude with fresh water (wash water) as part of the desalting process. This mixing method often results in consuming high quantities of wash water and chemicals with relatively low mixing efficiency.
In order to optimize GOSPs’ operations, a trial test of a new mixing technology provided by ProPure was conducted at Shedgum GOSP-4 during the period December 2007 – May 2008. The ProPure mixing system technology (ProSalt mixer system) was installed at the inlet line of the desalter in parallel to the arrangement of the conventional mixing valves (three in parallel).
The objective of the test was to evaluate the technology performance and reliability in optimizing desalting processes for Saudi Aramco crude processing facilities. This can be achieved by providing more efficient and effective use of wash water and chemicals while maintaining GOSPs treated crude specifications within Saudi Aramco acceptable criteria which are salt content below 10 PTB (Pounds per 1000 Barrels of Crude) and BS&W (Basic Sediment & Water) below 0.5% by volume.
At the end of the trial test, the Saudi Aramco team evaluated the ProPure mixing technology in comparison to the conventional type and concluded the following results;
Pressure drop across the ProPure mixing system decreased by 60% Wash water rate was reduced by 40% (from 50 GPM to 30 GPM) Oil in water content reduced by 40% The salt content and BS&W have been on spec all the time
The paper describes the mixer concept and results at Shedgum GOSP-4 and further quantifies the implications on installation, treatment capacity and consumables as wash water and demulsifier.
A Hybrid Ensemble Kalman Filter with Coarse Scale Constraint for Nonlinear Dynamics
Authors: Watanabe Shingo , Datta-Gupta Akhil , Efendiev Yalchin , Devegowda Deepak 
Published: October 2009

Abstract
The recent interest in Ensemble Kalman Filters (EnKF) is driven to a large extent by the need for continuous reservoir model updating and uncertainty assessments based on dynamic data. The EnKF approach relies on sample-based statistics derived from an ensemble of reservoir model realizations. Sampling error in these statistics, particularly with the use of modest ensemble sizes, can severely degrade EnKF performance leading to parameter overshoots and filter divergence. However, for computational efficiency, the ensemble size needs to be kept small resulting in spurious sample correlations and loss of geologic realism during model updating. Moreover, facies-based non-Gaussian geologic models and the non-linearity of multiphase flow problems pose significant additional challenges for the EnKF. The EnKF updates are designed to be optimal only for Gaussian priors and linear model dynamics. For multiphase history matching, the posterior distribution will be nonGaussian and the ensemble mean is not a good representation of the central tendency. As a result the EnKF can result in a poor match to the data or unrealistic model updates.
The hybrid multiscale EnKF proposed here provides an improved approach to operational data assimilation problems and tends to overcome many of the limitations associated with the classical EnKF implementation. Our approach combines nonlinear inversion with the EnKF to account for the inherent non-linearities of multiphase inverse problems. Specifically, we update the ensemble mean in a conventional EnKF through a non-linear inversion at selected time intervals and replace the ensemble mean with the ‘posterior mode’ from the inversion. This explicitly recognizes the fact that for non-Gaussian distributions, the posterior mode is a better representation of the central tendency compared to the ensemble mean. Furthermore, the inversion results are imposed on the individual ensemble members via a coarse-scale constraint using a sequential second stage updating in the conventional EnKF and a flow-based upscaling. Our approach ensures that the ensemble members in the conventional EnKF will follow the trajectory of the non-linear inversion within a specified degree of tolerance. This not only allows us to account for non-linearities in the model updates but also prevents filter divergence arising from the use of limited ensemble size. We first illustrate the advantage of the hybrid approach using a synthetic example and present a detailed validation of our results. Next, the approach is applied to a west Texas carbonate reservoir to demonstrate its power and utility for practical field problems.
Simultaneous Interpretation of Pressure, Temperature and Flowrate Data for Improved Model Identification and Reservoir Parameter Estimation
Authors: Duru Obinna O. , Horne Roland N. 
Published: October 2009

Abstract
Permanent downhole gauges (PDGs) provide a continuous source of downhole pressure, temperature, and sometimes flowrate data. Until recently, the measured temperature data have been largely ignored. However, a fine scale observation of the temperature measurements reveals that the temperature signal is not constant but changes with changing flow conditions.
This observation inspired the study of the temperature distribution in the reservoir as a possible source of additional reservoir information beyond that conventionally obtained in pressure transient analysis. As a first step to this problem, a physical model was developed for the temperature profile in flowing and shut-in reservoirs as a function of formation parameters, fluid properties, and flow conditions in space and time. A semianalytical solution scheme, Operator Splitting and Time Stepping (OSAT), was applied to the model and this gave an approximate solution in the form of a convolution integral between a convective temperature term, which depends strongly on flowrate, and a diffusive temperature term. This convolution is also quasilinear between temperature and flowrate measured at the well. The solution matched both field and synthetic data.
In the second step, Bayesian inverse modeling was applied to the problem for the assimilation of pressure and temperature data. This stochastic inverse technique treats parameters as jointly distributed random fields, and yields confidence intervals in addition to best estimates of the parameters. When applied to this assimilation problem, the method allowed for the deconvolution of the pressure and temperature signals, yielding discrete forms of their kernel, which are useful in reservoir parameter estimation and flowrate reconstruction. A useful outcome of the temperature function deconvolution is the ability to generate approximate estimates of the flowrate using temperature signals only. This is a useful in the common situations where downhole flowrate information is unavailable. The Bayesian inverse method was also applied to data denoising in cases where the temperature, pressure and flowrate signals are corrupted with noise. When applied iteratively, the method yielded estimates of the signals that were very close to the true reservoir response. The Bayesian inversion framework also allows also the computation of large number of conditional realizations which are equiprobable solutions given the data and these in turn help give better understanding of the unknown function.
Acoustic Signatures, Impedance Microstructure, Textural Scales, and Anisotropy of Kerogen-Rich Shale
Authors: Prasad Manika , Mukerji Tapan , Reinstaedtler Michael , Arnold Walter 
Published: October 2009

Abstract
Organic-rich shales (ORS) have been studied in detail to understand the provenance and the generation of oil from source rocks. Organic-rich gas and oil shales are gaining importance as unconventional hydrocarbon resources in their roles as source, reservoirs, and as sealing formations. Proven and recoverable oil reserves from these shales account for about 33 trillion tons of shale and 68 billion tons of oil, respectively. However, a successful exploration and production program for these resources requires reliable characterization of the physical properties, maturity, and changes in mechanical, elastic, and flow properties through indirect methods. The seismic properties of kerogen are still poorly understood and so, predictions of kerogen maturity and rock-kerogen systems remain a challenge. Assessment of maturity from indirect measurements can be greatly enhanced by exploiting correlations between physical properties, microstructure, and kerogen content.
In this paper, we analyze possible reasons for changes in impedance microstructure and elastic properties of ORS due to maturity. We have examined scanning acoustic microscopy images to quantify textural anisotropy, size of heterogeneities, and relative acoustic impedance contrast in the images and related these textural properties to maturity and to impedance from ultrasonic wave propagation measured at centimeter scales. This combined study of impedance and microstructures of ORS gives important insight in changes due to kerogen maturation.
We find that Porosity exhibits a first order effect on velocity: in high-porosity ORS, velocity has a direct correlation with porosity.In low-porosity ORS, velocity is directly correlated with kerogen content. The acoustic impedance of an ORS is related to its total organic content and to its hydrogen index (HI).Quantifying microscale impedance texture and contrast in the images allows us to correlate them with larger-scale ultrasonic measurements.Textural heterogeneity, elastic impedance, velocity, and density increase with increasing shale maturity.