bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory Investigation of Polymeric Surfactants for EOR in High Salinity and High Temperature Reservoir
Authors: Guo Lijuan , Han Ming , Fuseni Alhasan , AlSofi Abdulkareem 
Published: March 2016

Abstract
Great attention has been paid recently to polymeric surfactants due to their structure. The incorporation of polymer and surfactant properties in one macromolecule offers significant advantages for chemical flooding. Aiming at high salinity and high temperature reservoirs, several polymeric surfactants were investigated for their potential in improving oil recovery. Experimental results demonstrated polymeric surfactants' good compatibility with field brines (both injection and produced brines). The interfacial tension (IFT) can be reduced by one order of magnitude compared to regular polymer solutions that have no surface activity. The emulsification can be significantly increased, too. The viscosity of the polymeric surfactants is much higher than regular surfactant solutions. With these unique properties, polymeric surfactants are considered a potential alternative to traditional surfactant-polymer formulations for chemical flooding in high salinity and high temperature reservoirs.
A New Approach to Obtain Producer FBHP and FBHT from SCADA Data in the Schoonebeek Steamflood
Authors: Zakharov Alexander 
Published: March 2016

Abstract
Two novel methods are presented, that allow estimating downhole P&T conditions by using wellhead measurements in the Schoonebeek steamflood development: one method allows determining flowing bottomhole pressure (fBHP) and the other bottomhole temperature (fBHT). The resultant estimates are confirmed by fluid level measurements and observation well pressure data.
The fBHP calculation is based on the fact that rod loads are dependent on fluid level. A simple but robust model is presented, which accounts for impact of other parameters (pump speed, watercut, etc.) and allows fine-tuning to match available downhole measurements. The fBHT is estimated by using a simplified analytical wellbore heat loss model that is history matched to wellhead temperatures (WHT) at different well rates.
Both models are applied in the Schoonebeek field steam flood development. Their creation was necessary because operational constraints severely restricted usage of standard surveillance techniques like fluid level measurement and use of downhole gauges on hot producers.
The presented methods allow acquiring robust estimates of downhole P&T regime for flowing producers by using easily accessible SCADA data that is continuously collected at the wellhead. These data are normally used to optimize the rod pump operation and have been recorded since the start of the steamflood (2011–2015); hence, by using simplified rod load models and some statistical analysis it was possible to recover and validate the full fBHP/fBHT history for the hot wells – even for the periods when the fluid level measurements were unavailable or inconsistent.
The models were tested and matched against historical field measurements (fluid level measurements and data from observation wells) and were found to provide sufficient accuracy for use in normal operations (P&T within a few bars / 10 degrees C).
The novelty of the methods is in the ability to use existing wellhead data to come up with robust estimates for downhole P&T conditions on flowing wells. Nowadays continuous SCADA are industry standard; thus, near-continuous fBHP and fBHT monitoring can be achieved without using any additional equipment.
Clear benefits are surveillance cost reduction together with improved well/reservoir management; also, extra data helps improving reservoir model history match quality and forecast accuracy.
Impact of Oil on Steam Foam Formulations at 250°C
Authors: Cuenca Amandine , Lacombe Emie , Chabert Max , Morvan Mikel , Delamaide Eric 
Published: March 2016

Abstract
The most widespread thermal EOR method relies on steam injection. Steam is employed to warm up the reservoir, increase oil mobility and in turn enhance heavy oil recovery. In steam injection processes, recovery of oil is limited by steam channeling due to reservoir heterogeneities. Early breakthrough implies large consumption of steam and incomplete reservoir drainage. A low cost viable option to minimize heat loss consists in generating steam foam in situ. Foam will reduce steam mobility, increase its apparent viscosity and reduce steam channeling. Foam should form and flow in reservoir swept regions containing residual oil saturation. For a field application, where the residual oil saturation may vary from 0 to 30% depending on the recovery method applied, any effect of the oil on foam stability becomes a crucial matter. The scope of this work is to design an appropriate foaming surfactant solution in reservoir representative conditions of 250°C. We study the impact of crude oil on its foaming properties.
Previous publications demonstrate that formulation viscosity as well as foamability and foam stability are key parameters to optimize steam mobility reduction in model porous media. It is also well known that measuring foam properties at 200°C in presence of heavy crude oil is an experimental challenge. Injecting heavy oil in common equipment is often problematic, due to its high viscosity and low flowability. Our methodology is based on the use of high pressure/high temperature set-ups, such as sapphire view cell to measure foam stability, capillary rheometer to measure formulation viscosity and high temperature sandpack experiments to measure gas mobility reduction in model porous media. We also present a new high pressure/high temperature screening tool based on disposable containers to evaluate foaming properties in presence of heavy crude oil.
We have shown in previous work that long chain surfactants present high foam forming ability at 200°C. We build on our knowledge to demonstrate foam existence at 250°C. This study highlights the performance of new foaming formulations at this temperature. Our development effort has been concentrated on building a novel experimental setup and also providing data to evaluate the impact of heavy crude oil on foaming performances. Based on our experimental results, we demonstrate that foam stability in presence of crude oil can be improved by surfactant synergetic associations.
Overall, this work offers new insights to design efficient steam foaming formulations up to 250°C, in particular in presence of heavy crude oil. This novel approach helps in developing more efficient steam foam EOR solutions and in optimizing steam injection processes.
Challenges in Full Field Polymer Injection Mangala in Field
Authors: Mehta Nirav , Kapadia Gautam , Panneer Selvam V 
Published: March 2016

Abstract
Polymer flood process has the potential to significantly improve sweep efficiency in the fields with viscous oil, due to unfavorable water-flood oil-water mobility ratio resulting in a relatively inefficient water-flood. A successful field implementation would lead to extended production plateau and increased ultimate recovery (EUR). Cairn India Ltd is engaged in Oil and Gas exploration and production in RJ-ON onshore block in India. Mangala oil field is the largest discovered field with significant oil production potential (Total estimated water flood recovery of around 37 %). The field which contains moderately viscous but waxy oil with high pour point is currently under hot water flood to provide pressure support, sweep and prevent any in-situ wax drop-out. Post success of a polymer pilot trial, the full field polymer flood project is being implemented in the field with the concept of a Central polymer preparation plant distributing the concentrated polymer mother solution to the injection wells which are scattered across the field. The mother solution is diluted with the injection water to required polymer concentration before final injection into the well. Full field Polymer Injection it is expected to yield additional recovery of 5–7% of the STOIIP over base water flood.
This paper discusses the challenges faced during the execution of the polymer injection in the full scale with respect to, Supply chain management of polymer w.r.t framing the polymer supply contracts, screening of multiple vendors in different geographical location and the logistics management of large volumes of polymer,Laboratory techniques in screening the polymer, challenges faced in laboratory measurements including viscosity measurement in aerobic/anaerobic conditions, low shear high pressure sampling, and compatibility of oil field chemical additives with Polymer,Operational challenges including viscosity with available water quality & higher oil in water, TSS, Fe content and impact of temperature variation on viscosity of mother solution and diluted polymer solution,Produced fluid handling challenges with Polymer breakthrough with respect to adequacy of oil-water-gas treatment facility to handle emulsion, scaling/gelling issues in heat exchangers and the capacity limitations caused by viscosity and hydraulics.
To summarize, for the full field polymer injection, the challenges discussed with respect to unwieldy logistics of polymer procurement, mother and dilute polymer solution preparation at low shear and high pressure environment followed by polymer breakthrough resulting in tighter emulsion, etc need to be addressed proactively in order to achieve the targeted recovery from the Project. The focused efforts on these areas of concern are the drives for the success of all the stakeholders.
Comparison of Implicit-Texture and Population-Balance Foam Models
Authors: Lotfollahi Mohammad , Farajzadeh Rouhi , Delshad Mojdeh , Varavei Abdoljalil , Rossen William R. 
Published: March 2016

Abstract
Simulation models for foam enhanced oil recovery are of two types: those that treat foam texture or bubble size explicitly (population-balance models) and those that treat the effects of foam texture implicitly through a gas mobility-reduction factor. The implicit-texture models all implicitly assume local equilibrium (LE) between the processes of foam creation and destruction. In published studies most population-balance models predict rapid attainment of local-equilibrium as well, and some have been recast in LE versions.
In this paper we compare population-balance and implicit-texture (IT) models in two ways. First, we show the equivalence of the two approaches by deriving explicitly the foam texture and foam-coalescence-rate function implicit in the IT models, and then show its similarity to that in population-balance models. Second, we compare the models based on their ability to represent a set of N2 and CO2 steady-state foam experiments and discuss the corresponding parameters of the different methods.
Each of the IT models examined was equivalent to the LE formulation of a population-balance model with a lamella-destruction function that increases abruptly in the vicinity of the limiting capillary pressure Pc*, as in current population-balance models. The relation between steady-state foam texture and water saturation or capillary pressure implicit in the IT models is essentially the same as that in the population-balance models. The IT and population-balance models match the experimental data presented equally well. The IT models examined allow for flexibility in making the abruptness of the coalescence rate near Pc* an adjustable parameter. Some allow for coarse foam to survive at high capillary pressure, and allow for a range of power-law non-Newtonian behavior in the low-quality regime.
Thus the IT models that incorporate an abrupt change in foam properties near a given water saturation can be recast as LE versions of corresponding population-balance models with a lamella-destruction function similar to those in current PB models. The trends in dimensionless foam texture implicit in the IT models is similar to that in the PB models. In other words, both types of model, at least in the LE approximation, equally honor the physics of foam behavior in porous media.
Polymer Injectivity Test in Bhagyam Field: Planning, Execution and Data Analysis
Authors: Sharma K Kaladhar , Mishra Sudhakar , Kumar Pankaj , Pandey Amitabh , Jain Shakti , Ghosh Priyam , Mishra Lokranjan , Koduru Nitish , Agrawal Nitesh , Kushwaha Malay Kumar 
Published: March 2016

Abstract
The Bhagyam Field development is part of the Mangala- Bhagyam -Aishwariya (MBA) development in the Barmer Basin, Rajasthan, India. The Bhagyam field is a shallow field with ~12B dip, containing good quality fluvial sand(s), medium gravity crude with a viscosity gradient (vertically) in the oil column and low water salinity (~5000 ppm). The field is currently being developed using down-dip water injection. The effectiveness of the waterflood will be limited by the adverse mobility ratio and reservoir heterogeneities. A polymer injectivity test was conducted in two wells with two main objectives: (1) to establish injectivity within the designed surface pressure, and (2) establish the ability to prepare polymer solutions of the desired viscosity using produced water for re-injection (PWRI).
Operationally, the test was conducted using a skid mounted unit with regular monitoring facilities in place. Surveillance activities included frequent spinner surveys, bottom-hole pressure measurements, fall-off tests and offset production well tests. Rigorous monitoring of injection water quality, polymer solution quality was carried out. An inline viscometer was used for continuous polymer viscosity monitoring. This was supplemented by periodic sample viscosity measurements using special samplers with chemical stabilizers. The test was conducted in two wells and important lessons have been learnt which would be incorporated during full-field implementation of a polymer flood in Bhagyam.
The injectivity test establishes that polymer injection is viable in Bhagyam Fatehgarh reservoirs. A history matching exercise was carried out using a sector model extracted from our full-field simulation model. The effect of production and injection in offset wells was captured in the sector model. Local grid refinement enabled us to adequately capture polymer rheology. The modelled rheology was found to be in close agreement with laboratory data. The production history of the wells in the sector and vertical injection profile of the injector well was incorporated. We obtained a good history match of the injection bottom-hole pressures.
This paper presents details of the polymer injectivity tests including bottom-hole pressure measurements, fall-off tests and production logging which were conducted during the tests. As PWRI was utilized for preparing polymer solution, the effect of additives to the polymer solution viscosity was also analyzed. The test included use of not so commonly used equipment like inline viscometer, special samplers with chemical stabilizers, preparation of high concentration mother solution and injection of heated polymer solution.
Use of Solvents With Steam - State-of-the-Art and Limitations
Authors: Bayestehparvin Bita , Ali S. M. , Abedi Jalal 
Published: March 2016

Abstract
Steam injection is a widely used oil recovery method that has been commercially successful in many types of heavy oil reservoirs, including oil sands of Alberta. Steam is very effective in delivering heat that is the key to heavy oil mobilization. In the distant past, and also recently, solvents are being used as additives to steam for additional viscosity reduction. This was done previously in California heavy oil reservoirs also. The current applications are in SAGD (Steam-Assisted Gravity Drainage) and CSS (Cyclic Steam Stimulation) field projects.
The past and present projects using solvents are reviewed, and evaluated viz ES-SAGD (Enhanced solvent SAGD) and LASER (Liquid Addition to Steam for Enhancing Recovery). The theories behind the use of solvents with steam are outlined. These postulate (1) additional heavy oil mobilization; (2) oil mobilization ahead of the steam front, and (3) oil mobilization by solvent dispersion due to frontal instability. The plausibility of the different approaches is discussed.
Recent theoretical work is described that compares thermal and solvent diffusion, showing that the time scales of the two processes are quite different casting doubt on the effectiveness of the use of solvents with steam. The numerical and analytical solutions have been compared for effect of cold solvent, hot solvent, steam only, and co-injection of solvent and steam on bitumen mobilization.
The outcome of this study can be used for better understanding of mechanisms and theories behind co-injection of solvent with steam.
Case Study in Middle East, Improve Heavy Oil Production and Recovery by Reservoir Modification as Alternative Technology to Steam and Miscible Gas Injection
Authors: Al Saadi Hassan , Mirza Mirza , Al Amri Bader , Mucharam Leksono , Nugroho Wisnu , Al-Hinai Khaldoon 
Published: March 2016

Abstract
Increasing oil production and recovery for Heavy Oil can be achieved by reducing oil viscosity. With reference to Darcy law, reducing the oil viscosity results in an increase in oil productivity. The current technologies for reducing viscosity are Steam injection and Miscible Gas (hydrocarbon or carbon dioxide) injection. However both steam and miscible gas has technical and economic limitations, and an alternative technology is required to extend beyond the limitations in both steam and miscible gas injection.
The technology described herein is based on reservoir fluid and rock modification by chemical technology approach. Reservoir modifications are made by ability to mix between oil and water, and the mixed viscosity is designed to be reduced to close to, but higher than, water viscosity. Because the viscosity is still higher than water viscosity, the fluid flow becomes slower and will have enough time to react with oil and divert to the oil bank. When the modified chemical is diverted to the oil bank, then wettability alteration acts to peel out oil from the rock surface and has ability to pass through pore throatand hence flow to producing oil well.
The research programewasconducted by mimicking reservoir behaviorby implementing mixture viscosity sensitivity performance test, imbibition tube test and coreflood test. The tests are implemented usingactual reservoir oil, water and rock. The result of viscosity reduction is able to reduce oil viscosity from more than 376 cp at reservoir temperature to less than 10 cp mixture viscosity at temperature between 60 and 90° C. For comparison, steam injection is able to reduce viscosity of heavy oil to become less than 10 cp, but requires a temperature of 350° C instead of 60 to 90° C. The imbibition test has shown incremental oil recovery at 14.7 psi (atm pressure) of two times that of reservoir water only, while the laboratory result with coreflood shows additional recovery after chemical injection of 30% to 50% beyond primary and water injection stage.
The implementation is technically simple and it is able to be conducted at relatively low cost. The result from implementation by well basis injection yielded a significant increase in oil production. By sharing this road map experience from laboratory result to field implementation of the new method of chemicalstimulation forheavyoil production, it provides an alternative to improve production and recovery of heavyoil, especially in the Middle East.
Persistence in EOR - Design of a Field Trial in a Carbonate Reservoir using Solvent-based Water-Flood Process
Authors: Alkindi Abdullah , Al-Azri Nasser , Said Dhiya , AlShuaili Khalid , Te Riele Paul 
Published: March 2016

Abstract
Primary and secondary recovery processes produce about one third of oil in place, leaving significant volumes behind. For low permeability and highly saline carbonate reservoirs, exploiting these resources is often challenging and unfeasible either technically and/or commercially.
In this paper we discuss the application of an emerging EOR technique that has shown promising results in the lab. Di-Methyl Ether (DME) enhanced waterflood (DEW) is a process in which DME is added to injection water, which upon injection into the reservoir, it preferentially partitions into the remaining oil. As a result, it swells the oil and reduces its viscosity which significantly improves oil mobility in the reservoir. Several core-flood experiments conducted in tight carbonate plugs have shown incremental recoveries of up-to 20% post waterflood. Additionally, the process provides significant acceleration to oil production, which would otherwise take several pore volume of water injection.
After successful PVT and core flood experiments, a field trial has been designed to de-risk this technology which if successful would add significant reserves. The pilot will be implemented in a tight carbonate reservoir that has been under waterflood. Some key uncertainties this pilot will address include solvent utilisation, oil incremental recovery, solvent back production and impact of geology on the process.
This paper discusses the key physical mechanisms of the process, pilot design and challenges of full field considerations. In addition, it also highlights key considerations when designing solvent-based EOR applications. The paper also highlights the need of lab work to mitigate operational issues prior to implementation. Calibrated numerical models were used to generate full field profiles, which show the need for a well optimised pattern design to make such processes feasible
Improving Reactive Transport Modelling Predictivity for ASP Flooding Simulations
Authors: Li Xipeng , Wei Lingli , Zhang Huanhuan 
Published: March 2016

Abstract
Alkaline-Surfactant-Polymer (ASP) injection into an oil reservoir triggers a series of geochemical reactions including reservoir mineral dissolution and precipitation of scales inside the reservoir and wellbores. Modelling these reactions is important for understanding the processes and designing the ASP formulation for optimal oil recovery. A number of reactive transport modelling (RTM) approaches have been reported in the literature so far, but none has addressed the importance of a geochemical database underpinning such simulations considering both equilibrium and kinetic reactions. In the meantime, experimental data available outside the oil industry can be used for calibrating reservoir mineral dissolution equilibrium constants in high pH solutions.
In this paper, experimental data of dissolution of relevant reservoir minerals and precipitation of scale minerals are compiled and compared with predictions from the widely used geochemical modelling software PHREEQC. A new database calibrated to the experimental data is developed in PHREEQC format that can be used in Shell in-house reservoir simulator MoReS for ASP flood reactive transport simulations. In order to reproduce the sequence of the observed scale deposition during an ASP flood project, the kinetic rate laws for the mineral dissolution and precipitations have also been calibrated against the experimental data.
Significant differences in the predicted mineral dissolution and precipitation between the calibrated database and the one from the official PHREEQC release demonstrate the necessity of geochemical database calibration for high pH environments. With the calibrated equilibrium constants and kinetic rate constants in the new geochemical database, the sequence of secondary mineral (scale) deposition during ASP flooding as reported in literature can be successfully reproduced. The improved modelling capability for ASP scaling prediction also increases the confidence for other aspects of simulation results such as chemical breakthrough.