bluuebunny/crossref_metadata_2025_split huggingface dataset:
Emulsion Characteristics and Novel Demulsifiers for Treating Chemical Induced Emulsions
Authors: Nguyen Duy , Sadeghi Nicholas , Houston Christopher 
Published: July 2011

Abstract
In this paper, the stability of oil-in-water emulsions produced from chemical enhanced oil recovery processes was investigated over a wide range of parameters. These parameters are surfactant concentration, polymer concentration, mixing speed, asphaltene concentration, salinity concentration, water cut, temperature, and alkaline concentration. Emulsion stability decreased with an increase in temperature, salinity content, or water cut. Increasing surfactant concentration, polymer concentration, or shear rate enhanced emulsion stability. One of the main contributions for the tight emulsion from alkaline surfactant polymer (ASP) flood was the addition of alkaline. The surfactant, alkaline, and polymer decreased the size of oil droplets, increased the surface charge of oil droplets, and increased the film elasticity, thereby making oil-water separation difficult. Selected cationic surfactants (patents pending) proved much more effective than conventional nonionic resins and polymeric cationic flocculants in separating oil-in-water emulsions. We also studied the effect of alkyl chain length (C8 – C18) of benzyl and methyl quats on demulsifying efficiency and compared the performances of monoalkyl quat with dialkyl quat. As the surfactant concentration in the brine decreased, the concentration of the cationic demulsifier required to separate the emulsion decreased and the optimum chain length of the cationic demulsifier also changed. Particle video microscope and focused beam reflectance measurement probes showed significant increase of the size of oil droplets and reduction in the number of oil droplets in the presence of a cationic surfactant. This is in agreement of a decrease of the anionic charge on the surface of the oil droplets and a reduction of the film elasticity in the cationic system. Application of this novel demulsifier resulted in a much more effective oil/water separations process with the production of dry oil and clean water at a pilot ASP flood that was experiencing very stable emulsions.
Prediction and Experimental Measurements of Water-in-Oil Emulsion Viscosities during Alkaline Surfactant Injections
Authors: Kalra Amrit , Raney Kirk , Dindoruk Birol , Venkatraman Ashwin 
Published: July 2011

Abstract
Oil production is generally a complicated multi-phase flow inside pipelines, with possible W/O emulsions present with other usual phases such as free water and free oil. The water-in-oil (W/O) emulsions formed can present significant hurdles in production facilities for pumping fluids and during pipeline transport. It is well known that high shear rates provided by pumps, chokes or valves result in stable emulsion behavior for a field in primary production. Several field tests are underway to test the potential of surfactant flooding as a tertiary recovery mechanism. The effect of addition of surfactants on the emulsion rheology of production fluids, as in Alkaline Surfactant Polymer (ASP) flooding, is not very well understood. This understanding of W/O emulsion rheology in ASP injected oil recovery is essential for design of pumps and pipelines as well as for handling flow assurance issues.
In this paper, we report results from experiments as well as modeling of W/O emulsion rheology that can form during ASP injections. We focus here only on the Alkaline Surfactant (AS) part of these injections in order to clearly understand the impact of surfactants and removing the uncertainities that come with large rheology changes with polymer addition. The effect of surfactants on the rheology of W/O emulsions was studied by making two different types of emulsions: 1) native brine W/O emulsions without surfactants to provide a baseline 2) W/O emulsions with surfactants used in AS injections. This way, the impact of AS injections on emulsion rheology can easily be quantified. A new correlation is developed, based on in-house historical experimental data, to describe rheology of emulsions without surfactants. This correlation should assist in managing the uncertainties that come from extrapolating emulsion rheology measured in the laboratory to actual field conditions. Further, in order to understand the effect of AS injections, new experimental measurements were made by adding surfactants to brine solutions. The addition of surfactants resulted in different rheology as compared to emulsions formed by brine solutions. These differences have been attributed to the water-oil interfacial tension (IFT), and IFT was added to modify the original correlation. To our knowledge, this is the first study that explicitly relates emulsion rheology with interfacial tension.
Adjoint-based Optimization of Polymer Flooding
Authors: Van Doren Jorn , Douma Sippe , Wassing Bart , Kraaijevanger Hans , de Zwart Bert-Rik 
Published: July 2011

Abstract
In this work we consider model-based optimization of polymer flooding. The reservoir performance is optimized by finding for each injection well optimal values for control variables such as injection and production rates, polymer concentrations, and times when to switch from polymer to water injection (i.e. polymer grading). The same technique can also be applied to optimize other EOR processes such as for example designer water flooding, alkali-surfactant polymer (ASP) flooding and foam flooding. The optimization method that has been used relies on the adjoint implementation in our in-house reservoir simulator to efficiently calculate the gradients. The adjoint method enables the computation of gradients with respect to injection and production rates, injection compositions of each well and switching times of each well at the additional cost of approximately the computation time of a single reservoir simulation. The optimization method uses the adjoint-based gradients to estimate the values of all polymer injection control variables that maximize reservoir performance.
The optimization method is demonstrated on a full-field reservoir simulation model. The physics that is modeled includes polymer mixing, hydrodynamic acceleration of the polymer molecules and adsorption of the polymer to the rock. The example shows that the Net Present Value increases significantly as a result of the optimization, mainly due to increased oil production and decreased polymer injection. The obtained optimal control is physically interpreted, so that the learning points from the model-based optimization can be applied to the field and can be used to enhance the polymer flood.
EOS Modeling, The First Step in Detailed EOR Potential Evaluation - A Case Study
Authors: Sah Pashupati , Pedersen Karen Schou , Azeem Shaikh Jawad 
Published: July 2011

Abstract
The paper presents an Equation-of-State (EOS) modeling work carried out for a Middle East reservoir fluid for which gas injection was considered for increasing ultimate recovery. The aim of the work was to develop an EOS model that would accurately reproduce the phase behavior in a reservoir on injection of either a hydrocarbon gas (mix of gas condensate and associated rich gas) or a CO2 rich gas. A single EOS model was developed, which provided a good match of data for both injection gases. This EOS model enables compositional reservoir simulation studies to be carried out comparing and contrasting the recovery from the field with each of the two injection gases.
Extensive PVT data was available and to be matched by a 9-component ‘lumped’ EOS model. Available data included classical PVT data as well as gas injection (EOR) data including solubility swelling, equilibrium contact and slim tube tests. A major challenge was to develop a model which, in addition to classical PVT data, which can easily be regressed to, also matched slim tube minimum miscibility pressures (MMPs). A multi-component tie-line method was used considering combined vaporizing/condensing drives, and the tie-line MMP was afterwards verified using a cell-to-cell simulator.
Depth gradient simulations indicated that the transition from liquid-like to vapor-like properties in the reservoir did not take place through a sharp gas-oil contact (GOC), but happened continuously in a‘transition zone’. An EOS model neglecting such‘transition zones’ or simulating a sharp gas-oil contact may lead to severe misinterpretations in reservoir simulations. A segregation model based on irreversible thermodynamics was used to investigate the influence of an observed vertical temperature gradient on the compositional variation with depth.
Estimates Of Surfactant Concentration Used For EOR In Daqing Oilfield Low Permeability Oil Reservoir
Authors: Hongwei Yu , Taoping Chen , Ming Gao , Jinshan Liu , Jijun Liu 
Published: July 2011

Abstract
In low permeable reservoirs of Daqing oilfield, the water drive recovery efficiency is low and other technology, such as polymer flooding, which have been successfully put into use for largely enhance oil recovery in medium or high permeable reservoirs could not be applied in the low ones due to high injection pressure.
Based on the description of characteristics and surfactant flooding mechanism, the practical conditions of Daqing oilfield low permeable reservoirs were simulated. Some experimental EOR studies of new surfactant named SY used for flooding have been done in the lab with low permeable artificial and natural cores. In a constant temperature, after the water flooding, 5 different concentrations (0.1%, 0.2%, 0.3%, 0.4% and 0.5%) of SY surfactant were used for flooding.
The result shows that the displacement efficiency of the SY surfactant is different under 5 concentrations, at the concentration of 0.5%, the recovery efficiency could be enhanced greatly, by 12.2%, and at the concentration of 0.3% and 0.4%, the recovery could be enhanced by 11.78% and 11.86%, nearly that of the concentration of 0.5%, but at the concentration of 0.1% and 0.2%, the recovery could only be enhanced by 5.23% and 6.85%.Because of the low surfactant usage and good oil recovery enhancing characteristics, 0.3% is the best concentration to be used. Reservoir simulation predicts that if the concentration of 0.3% can be used in low permeable reservoir C-1 block in Daqing oilfield, the recovery can be enhanced by 3.5% in 3 years flooding, and the final recovery can be enhanced by 11.52%.
The study has reference value to low permeable oilfield which will use the new type of SY surfactant to enhance recovery.
Study on the Safety Geology Sequestration after CO2 Displacement in Low Permeability Oil Reservoir
Authors: Hong-wei Yu , Ping-ping Shen , Yan-yao Shi , Yong-zhi Yang , Jing-yao Wang , Hong-wei Yu 
Published: July 2011

Abstract
For the purposes of winning economic performance and environmental performance, the application of CO2 displacement might be a viable option due to enhancing oil recovery significantly and sequestrating part of CO2 permanently.
Molecular diffusion is the key migration style of sequestrated CO2 due to concentration gradient in geologic body, so in the process of CO2 concentration goes to a balance condition, the sealing performance of cap rock for CO2 is influenced by some extent.
According to actual geologic parameters of Jilin CO2 flooding pilot test, CO2 diffusion coefficients were investigated in cores of super-low permeability saturated with in place oil under both miscible and immiscible pressure. Results obtained from these experiments were used to gas saturation field prediction for 1000 years after CO2 flooding on 12 homogenetic models considering immiscible, near-miscible and miscible conditions and cap rock thickness from 10m to 100m.Based on the prediction, CO2 geology sequestration safety template was built considering both miscible condition and the thickness of cap rock, which allows getting optimum reservoir and geological parameters for CO2 sequestration.
This research has reference value on the evaluation for CO2 geology sequestration ability and safety in low permeability oil reservoir.
Optimizing Simulation Studies for Miscible Gas Injection Process Using Horizontal Wells
Authors: Zakaria Ahmed S. 
Published: July 2011

AbstractThe use of Horizontal well has been increasing very rapidly throughout the oil industry and its applicability is now extended to the secondary and tertiary recovery processes. In this paper, a study on mature oil field case has been made to assess the technical feasibility of miscible gas injection using horizontal wells and to investigate the impact of gas injection horizontal wells on ultimate oil recovery. A reservoir model using 3-D compositional equation of state simulator is built to carry out different development scenarios to optimize the field development and increase the oil recovery using miscible gas injection process. The model is used to investigate the impact of using different combinations of horizontal and vertical injection and production wells on the performance of the process. The impact of alternative development scenarios on oil recovery, plateau oil production rate, and fluid saturation distribution are evaluated. The results show that the use of horizontal gas injection wells resulted in increase in cumulative oil recovery and gives better sweep efficiency.A sensitivity study is also presented in this paper to evaluate the parameters that affect the performance of the horizontal well pattern used in miscible gas injection process. The study emphasized on the horizontal permeability, permeability anisotropy, horizontal well length. From the simulation results, the model is found to be most sensitive to permeability anisotropy followed by horizontal permeability then to horizontal well Length. Thus it is recommended that these parameters must be properly estimated prior to use in simulating miscible gas injection process using horizontal well pattern.
Selecting the "Right" ASP Model by History Matching Coreflood Experiments
Authors: Karpan V.. , Farajzadeh R.. , Zarubinska M.. , Dijk H.. , Matsuura T.. , Stoll M.. 
Published: July 2011

Abstract
In order to design and analyze Alkaline Surfactant Polymer (ASP) pilots and to generate reliable ASP field forecasts a robust scalable modeling workflow for the ASP process is required. A starting point of such a workflow is to carry out ASP coreflood tests and history match those using numerical models. This allows validation of the models and generates a set of chemical flood parameters that can be used for field-scale simulation forecasts.
It is well established that lowering of interfacial tension due to maximum of in-situ generated soap with injected surfactant and improved mobility control due to the polymer play a crucial role in the ASP process. Therefore, all models for the ASP process take into account these mechanisms in one way or the other. However, ASP models can differ in the detail in which (geo-) chemical reactions and the phase behavior are addressed. Inclusion of the more details into the numerical model could result in better understanding and more accurate prediction, but it comes at a price, viz., it requires more measured input data and increases computational time. Thus, depending on the accuracy requirements, available experimental data and time the modeling of ASP flood can be performed using different simulation approaches.
This paper describes several modeling approaches for ASP. We start with a brief description of these methods and their input requirements. Then we compare the ASP coreflood simulation results demonstrating the advantages and disadvantages of presented approaches. We also demonstrate that both ASP models can be applied at the field level by simulating an ASP flood in a sector model. Finally we give some recommendations and guidelines on how and when the proposed models should be used.
Quantitative Uncertainty Estimation and Dynamic Model Updating for Improved Oil Recovery
Authors: Maucec Marko , Cullick Stan , Shi Genbao 
Published: July 2011

Abstract
Optimal Improved Oil Recovery (IOR) depends significantly on the ability to estimate volumes and locations of bypassed oil from available historical data. Assisted simulation history-matching techniques are being used to estimate remaining reserves volumes and locations. This paper presents an approach to history match that more accurately captures model uncertainty. The novelty lies in direct interfacing between the geological modeling software and a forward simulator with the rapid generation of model updates in wave-number domain.
We describe a Bayesian workflow based on two-step Markov chain Monte Carlo (MCMC) inversion. Arguably, the MCMC methods statistically provide the most rigorous way of sampling posterior distribution, but when deployed in direct simulation, suffer from high computational cost. We outline an approach where the proxy model is guided by streamline-based sensitivities, dispensing with the need to run forward simulation for every model realization. We generate an ensemble of sufficiently diverse static model realizations at the high-resolution geological scale that generates more accurate results by obeying known geostatistics (variograms) and well constraints. An efficient model parameterization and updating is described for rapid characterization of the main features of geologic uncertainty space: structural framework, stratigraphic layering, facies distribution, and petrophysical properties.
We validate the workflow on a case study combining geological model with ~900k cells, four different depositional environments and 30 wells with 10-year water-flood history. The method can be used for successfully identifying the highest potential to capture bypassed oil and for implementing IOR. A history-match method is presented that has potential to lead to better IOR decisions and results through more accurate simulation models and inherent quantification of uncertainty.
Visualization of CO2 Displacement Process under Gravity Domination
Authors: Mohiuddin Zeeshan , Haghighi Manouchehr 
Published: July 2011

Abstract
The gravity dominated CO2 injection has received increased attention in the oil fields as it utilizes gravity force to stably displace the remaining oil after primary and/or secondary recovery. Effect of gravity is also important in some CO2 sequestration in aquifers. To visualize the fluid-solid interaction mechanisms at pore scale and to determine the controlling factors for a stable gravity dominated process, parameters such as fluid and porous media properties should be evaluated. The visualization of displacement process at the pore level could help to identify the critical range of controlling parameters. These visual experimental results could validate the modelling of fluid flow at pore scale. Therefore, an experimental study was conducted using a glass micromodel and visual results have been analysed. The details of experimental setup including micromodel construction, holding rig and the instrumentation have been addressed in this paper.
The experiments were conducted using CO2 injection to displace water at various rates under different gravity conditions. This displacement under pressure slightly above the atmospheric conditions has been characterized as partial miscible displacement. Experimental results determined the relationship of porous media characteristics such as dip angle and porous medium heterogeneities on the process at pore scale. The results were analysed using dimensionless Darcy Rayleigh number and mobility ratio to extend the results at larger scales and different fluids. The experimental results show that Darcy-Rayleigh number is proportional to the displacement efficiency however; at moderate flow rates and the dip angle of 45°, lower recovery was observed compared to horizontal case. Also at dip angle of 45° and with higher viscosity of the defending fluid (lower mobility ratio) a more stable process was observed.
Laboratory Assessment and Field Pilot of Near Miscible CO2 Injection for IOR and Storage in a Tight Oil Reservoir of ShengLi Oilfield China
Authors: Ren Bo , Xu Yang , Niu Baolun , Ren Shaoran , Li Xiangliang , Guo Ping , Song Xinwang 
Published: July 2011

AbstractGas injection into tight oil reservoirs, as a secondary recovery technique, can be favorable and promising in terms of high gas injectivity and good displacement/sweeping efficiency over water injection. Particularly, CO2 injection is the best option due to its superior miscibility effect with oil and in consideration of geological storage of the greenhouse gas. In this study, CO2 injection into a tight oil reservoir for IOR is assessed and a pilot project is underway. The reservoir is located in the G89 Block of Shengli Oilfield East China, which has very poor water injectivity due to very low permeability of less than 5 mD in average, and has been producing via natural depletion since 2005. The original reservoir pressure was over 40 MPa, and the reservoir temperature of 126  . A CO2 injection and storage program has been proposed, and CO2 will be from a coal-fired power plant 30 km away under a Sinopec’s CCS (Carbon Capture and Storage) scheme. Laboratory investigation includes PVT experiments, slim tube test and core flooding/displacement experiments, in order to study the miscibility effect and displacement efficiency via CO2 injection at various conditions. Reservoir simulations were performed to predict the IOR potentials of CO2 injection at different pressures, namely at immiscible, miscible and near-miscible modes. The MMP (Minimum Miscibility Pressure) of the reservoir oil is determined as over 29 MPa, while the reservoir pressure at the beginning of CO2 injection was around 23 MPa after several years’ depletion. Therefore, CO2 flooding at a near miscible mode will prevail. A field pilot of CO2 injection at current reservoir conditions (at near-miscible mode) is designed and its performance is presented in the paper.
Comprehensive EOR Screening and Pilot Test for Thar Jath Heavy Oil Field, Sudan
Authors: Suliman Abdalla Elhag , Ngah Ab. Wahab , Basbar Ashraf Elfadil , Anua Nor Aidil , Hashim Salaheldin Tawfig 
Published: July 2011

Abstract
Many of Sudan’s large oil fields suffer from low recovery factors and decline in primary production due to low oil gravity (&lt;22 API) and viscosities above 100 cP. Many wells experienced premature water production. As such, Enhanced Oil Recovery project seems to be the option to improve oil recovery in Sudan.
Thar Jath field contains in excess of 1.2 billion STOIIP, 75% of the STOIIP comprises 20° API oil with 120–160 cP viscosity while the remaining STOIIP comprises 16° API with viscosity &gt; 680 cP viscosity. The Full Field Review which was carried out through 2009 recognized that primary and secondary recovery could only recover, at best, 9.0% of the STOIIP with infill drilling. As such, a considerable number of Enhanced Oil Recovery (EOR) techniques have been assessed in order to recommend suitable EOR development project for the field, and to position the field as leading the way in Sudan. In the absence of a miscible gas option, dynamic reservoir simulation schemes were developed for the natural depletion, water flood, chemical, thermal and immiscible gas methods.
The three most promising techniques; ASP, steam flood/CSS and in-situ combustion were developed to optimize pattern spacing, injection rates and pressures for each technique. Thereafter, facilities schemes and notional costs were developed so that economic viability could be assessed to select the most preferred technique going forward. EOR has been found to be economically and technically feasible with highest economic recovery across all reservoirs from Steam technique. There is scope for thermal recovery to take recovery factor above 40% overall. The pilot test design study is on going with the objective to proof the concept and confirm scope of recovery from steam flooding prior to full field implementation.