bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Oil Solubilization Using Microemulsions With Linkers
Authors: Pietrangeli Gianna , Quintero Lirio 
Published: June 2014

Abstract
In recent years, applications of microemulsion technology have increased in the drilling and production industry. Some of these applications include oil-based drilling fluid displacement to water-based fluid, near-wellbore remediation, well stimulation, enhanced oil recovery and flow-back recovery in shale gas wells.
Microemulsion formulations for these applications need to have high oil solubilization and very low interfacial tension, which is achieved with relatively high concentration of surfactants. High-performance microemulsion systems with lower surfactant concentrations are desired to optimize the cost of the technology application.
The reduction of surfactant concentration could be achieved by introducing linker additives in the formulations. The addition of linker molecules enhances the microemulsion solubilization property, which increases the hydrophilicity and/or the lipophilicity behavior of surfactants. Previous studies indicate the addition of a linker substance could double the solubilization of the system by segregating at the interface. The linker molecules create chaos, avoid formation of organized structure and decrease the viscosity, which helps to pack surfactants more efficiently at the interface. Some examples of linker additives include amines, acids, alcohols and phenols.
This paper presents systematic studies that have been carried out to determine the influence of lipophilic and hydrophilic linkers in an anionic/nonionic surfactant mixture when exposed to olefin-based oils that are used in synthetic-based drilling fluids.
The results of the study include phase behavior of a microemulsion system, interfacial properties and kinetic diffusion under several temperatures, as well as evaluation of the system with and without the addition of linker molecules for cleanup of synthetic and oil-based drilling fluids.
Risk Assessment of Concurrent Hydrate and Wax Formation for Deepwater Production Restart Modeling and Experimental Results
Authors: Oschmann H. , Alapati R. , Paso K. 
Published: June 2014

Abstract
This paper presents the successful implementation of a flow assurance strategy for a new deepwater production system offshore Africa derived from results of experimental assessments of associated paraffinic and hydrate formation. The rheological behaviour of production fluids under field conditions at various pressures and temperatures are compared with results from conventional PVT and flow modelling including latest models specifically designed to review pipeline clearance times and pressure wave propagation during restart.
These assessments differentiated between the individual contributions of hydrate formation and paraffin gelling and included analysis of the interaction between hydrate crystals and the wax-gel network.
Additionally, the performances of Low Dosage Hydrate Inhibitor (LDHI) and Pour Point Depressant (PPD) were assessed for various production conditions in the presence of other production chemicals in the temperatures range of 65°C to 4.5°C. The results showed excellent performance of both LDHI and PPD and additionally an incremental performance from the synergy between the two applied chemistries.
The predicted flow behaviour of the multiphase system based on the modelling was aligned significantly with the findings of the experimental assessment creating confidence for planned optimisation of the shutdown/restart procedure.
Simultaneous formation of gas hydrates and paraffinic gels during multiphase transportation poses significant potential risks for interruption of production in deepwater operations. An accurate assessment of these risks is critical in implementing a cost-effective flow assurance strategy which will minimises downtime during shutdown and restart procedures.
This investigation realises the potential development of a best practise solution to gelling problems associated with complex micro-crystalline paraffin wax. Crude oils which contain large fractions of branched and cyclic alkanes typically show poor performance with conventional PPD chemistries, but may show improved effective treatments with new chemistries specifically designed to lower the yield stress. Extension of this new treatment technology on complex waxy crude oils can encourage development of new reserves in regions such as Southeast Asia, west coast Africa, and South America where traditional chemistries are ineffective.
The Evaluation and Optimization of Hydrogen Sulfide Scavenger Applications Using Ion Mobility Spectrometry
Authors: Matherly Ron , Taylor Grahame 
Published: June 2014

Abstract
Field Asymmetric Ion mobility spectrometry (FAIMS) is commercially available equipment has been used to assay certain challenging analytes. This is a field capable method and has recently been applied to optimize the chemical use and flow parameters for conventional and flowing (Ultrafab) type hydrogen sulfide scavenger towers. An analysis method and appropriate calibration for the analytes of interest was developed "in house" followed by the application of this equipment in a field environment. By monitoring the chemical makeup of the partially spent scavenger fluid in these towers it is possible to a) more efficiently use the appropriate scavenger and b) monitor the degree spent to enable more effective monitoring of the consistency of the spent fluids and avoiding troublesome solid deposition.
Enhancement of Heavy Oil Demulsification
Authors: Wiggett A J , Ricza T 
Published: June 2014

Abstract
Demulsification is well known and tested, however with regards to heavy oil treatment, the crudes become more difficult to handle. Demulsification is subject to a number of external factors such as temperature, viscosity and crude oil composition, which affect the rate of water drop and resolution of emulsions. Heavy oil is composed of many components, but especially asphaltenes, which are unstable in produced crudes. As a result of their instability, asphaltenes tend to precipitate and fall out of suspension, eventually blocking production flowlines and separators.
It is widely known that many crude oils contain asphaltenes. They affect the oil/water and emulsion separation in these heavy crudes, causing increased usage of demulsifiers and system upsets. There have been many attempts to improve demulsifiers, but this has met with limited success.
We discuss a possible practical chemical technique to help resolve the emulsions in these types of crudes more easily, to maximize separation efficiency.
The use of asphaltene dispersants has been employed to deal with precipitated solids after they have agglomerated, but we investigate examples where the addition of other asphaltene inhibiting products may help improve the demulsification process. The impact of the improved separation would enable the crude oil to better meet its sales specifications. It may also help reduce system upsets and improve the oil production systems, enabling the customer to meet compliance with oil production quotas.
Smart Well With Autonomous Inflow Control Valve Technology
Authors: Aakre Haavard , Halvorsen Britt , Werswick Bjørnar , Mathiesen Vidar 
Published: June 2014

Abstract
A smart well concept with autonomous inflow control valve (AICV) is presented. AICV utilized the best from smart wells (ICV) and inflow control devices (ICD). The technology is presented, discussed and compared against other conventional inflow control technologies, id est (i.e.) passive ICD. The flow characteristics are presented and implemented in reservoir model simulations. Significant increased production and recovery are shown for the application in a thin oil rim with gas cap and heterogeneous reservoir. The AICVs are autonomous, i.e. self-regulating and do not required any external control or force. This makes them simple and robust, and a large number of control valves can be mounted in the well, i.e. one in each screen. When water and/or gas breakthrough occur the valves in the breakthrough zone will autonomously shut-off. This provides the operator with a significantly more efficient production and increased recovery. The AICV technology also enables opportunities to drill longer wells and achieve maximum reservoir contact of each well. In addition, the AICV removes the risk, cost and requirement for separation, transportation and handling of unwanted fluid.
Status of Drill-Stem Testing Techniques and Analysis
Authors: Van Poollen H.K. 
Published: June 2014

Abstract
This paper is a compilation of the latest drill-stem testing techniques. New tools are described, together with present-day interpretation techniques, and their limitations are given. The importance of proper times for shut-in and flow periods are stressed. A number of suggestions for the future are given, and a rather complete list of references in the field of drill-stem testing has been supplied for use by interested readers.

Introduction
A drill-stem test (DST) is a temporary completion. It consists of a combination of a packer arrangement and drill pipe or tubing. Valves are present in this arrangement to open and close the tool, and pressure and temperature recording devices are employed. Upon completion of the test, the entire arrangement is withdrawn from the well.
The purpose of a DST isto determine whether or not to complete the well andto obtain reservoir or aquifer information for exploration applications.
The DST will render a wealth of information - e.g., a sample of the fluid itself, the actual productivity index, the reservoir pressure, the theoretical productivity index and the amount of wellbore damage.
The fluid will show whether the well can be completed as an oil well, a condensate well or a gas well; or, it will show if the formation should be abandoned (for being a water producer or for being dry). Tests can be run on the sample to determine the hydrocarbons present, viscosity of the mixture, API gravity, paraffin content, pour point or gas-oil ratio. The water produced can be analyzed for salinity and electrolytes present to aid in stratigraphic correlation, and the resistivity of the water will aid the logging engineer in his evaluation of the electric logs. The DST further aids in determining gas-oil or oil-water contacts, and the proximity of pinchouts or faults.
Experimental Investigation of Liquid-CO2 and CO2-Emulsion Application for Enhanced Heavy Oil Recovery
Authors: Emadi Alireza , Sohrabi Mehran , Farzaneh Seyed Amir , Ireland Shaun 
Published: June 2014

Abstract
CO2 Injection in heavy oil reservoirs improves oil recovery and at the same time may reduce some of the environmental concerns associated with heavy oil recovery by thermal methods. Depending on the reservoir conditions and oil properties, viscosity reductions of up to two orders of magnitude may be achieved as a result of CO2 dissolution in heavy oil. However, adverse viscosity ratio which results in viscous fingering and early breakthrough of CO2 is a challenge for application of CO2 in heavy oil reservoirs. Therefore, CO2 injection needs to be combined or augmented by other displacement mechanisms (e.g. waterflood, foam injection) to efficiently displace the heavy oil diluted with CO2. In our previous papers, the micro-scale displacement efficiency and mechanisms involved in CO2 and CO2-foam injection in heavy oil systems were investigated and presented through vivid micromodel images. This paper presents the results of a series of coreflood experiments performed to evaluate the potential of liquid-CO2 and CO2-emulsion injection in a heavy oil reservoir.
The coreflood results show a very good performance for CO2 injection. An ultimate recovery of around 70 %OOIP as a result of secondary and tertiary CO2 injection was achieved which was twice the recovery obtained by waterflood in this heavy crude oil. This substantial recovery improvement was a consequence of a massive viscosity reduction (up to 97.5% of the original oil viscosity) at reservoir conditions. Co-injection of liquid CO2 and a selected surfactant also resulted in in-situ formation of a very stable CO2-emulsion which reduced mobility of injected CO2 by three orders of magnitude in presence of oil. In-situ generation of CO2-emulsion as evident from an increased in the pressure drop across the core was observed even at high oil saturation of up to 50%. The results of this work show significant potentials for immiscible CO2 and CO2-emulsion injection as an effective enhanced heavy oil recovery technique.
Investigating Residual Trapping Mechanism in CO2 Storage in the Brine through Analytical and Numerical Simulation Methods
Authors: Soroush Mansour , Wessel-Berg Dag , Kleppe Jon 
Published: June 2014

Abstract
Injecting CO2 in subsurface formations bearing brine creates different storage mechanisms. Firstly, CO2 will have an upward movement due to the buoyancy and it will be trapped below a geological barrier. During this stage of flow brine starts to imbibe into the pore spaces already occupied by CO2. Because of the wetting behavior of the system and CO2-brine capillary pressure, fractions of CO2 remain as residual saturation in the pore spaces. This is an important phenomenon that affects the storage capability and security. Later, and in a long term process, CO2 starts to dissolute into the brine and its density will be increased; and as a result convection mixing phenomena will starts.
To clarify the trapping mechanism, two different issues are discussed. One is the one dimensional, two phase behavior during CO2 injection and the second is the water imbibition process that includes the trapping mechanism. By arranging the flow equations and normalizing them by dimensionless parameters, main scaling parameters that define the physics in each problem are obtained. These parameters are CO2-brine mobility ratio and special gravity and capillary dimensionless numbers for each problem. In the water imbibition problem, hysteresis in relative permeability results in modifications to the dimensionless scaling parameters. These parameters are key factors in design and scaling of the experimental measurements to the simulation and analytical results.
To verify the analytical analysis, a numerical simulation model is constructed for the problems. Reservoir parameters of the Sleipner CO2 storage reservoir and the Viking formation (Bennion et. al. 2008) are used in this study in order to construct the model. This time, dimensionless parameters are defined according to the reservoir parameters. Analytical models are established based on simplifying assumptions, while simulation results are dependent on key scaling parameters obtained from analytical clarification. This means that they are good representatives of phenomena at reservoir conditions and can be used as a conceptual model before performing a fine scale, time consuming reservoir simulation study.
Impact of Completion on Wellbore Skin Effect
Authors: Alshawaf Mohammed H. , Gringarten Alain 
Published: June 2014

Abstract
Wellbore completions are a key well component and could have a positive or a negative impact on productivity, thus designing a suitable completion and implementing it properly must be a priority for production engineers. Consequently, well productivity indices related to specific completion designs have received much attention in the literature, with analytical and numerical models used for simulating various completion properties. The completion impact on wellbore skin effect, however, is seldom documented.
This paper looks at the effect of completion and reservoir characteristics on skin factors, and focuses on perforated, gravel-packed and frac-packed wells. For this study, a commercial black oil simulator was used to simulate different reservoir conditions and completion strategies, and the resulting skin effects were estimated by well test analysis of the corresponding synthetic pressure and rate data.
Results show that decreasing perforation density and tunnel length leads to high skin values due to wellbore flow restrictions. Moreover, it shows how a damaged gravel-pack completion coupled with a highly permeable formation results in high skin values that range between 1 and 100. Finally, in frac-pack completions, it is important to find the right balance between formation permeability and proppant permeability in the fracture as well as the permeability contrast between the proppant and the gravel as this dictates how a frac-pack will perform. Thus, depending on permeability of proppant and gravel-pack, skin values for frac-pack completions range between -2.5 to 15
Use of Oil Reservoir Simulation to Estimate Value of Flexibility
Authors: Marques Mateus D. , Gaspar Ana T. , Schiozer Denis J. 
Published: June 2014

Abstract
The selection of production strategy under uncertainties is a complicated task due to the high number of variables and uncertainties. While new information aims to reduce the uncertainty of one or more variables, consequently reducing the risk, flexibility may be used to change field operation in the future. The objective of this work is to estimate the value of flexibility through a risk-return analysis in which a company profile is taken into account represented by the iso-utility curve.
The methodology is an extension from Value of Information (VoI) assessment under uncertainties. It comprises a complete uncertainty analysis, use of representative models, generation of risk curves, optimization steps to define the strategy without flexibility which is then simulated in several scenarios verifying the bottlenecks of the strategy that may be assessed through flexibility. Finally, the benefit of each selected flexibility is estimated through risk-return analysis. The work includes a Latin Hypercube technique to combine uncertain scenarios and the use of an assisted optimization procedure to select the production strategy. It is then applied to a 28° API, low viscosity offshore oil field including production history.
Results indicate that this methodology is able to identify flexibility, in this case, the expansion of production capacity, which is then added to the production strategy with two objectives: to mitigate risk and to increase value. The tested flexibility changes the project risk and return in both objectives and allows the company to produce more efficiently in different scenarios, by producing with a higher use of installed capacity. The main conclusions are that the flexibility of production capacity expansion can be used not only to mitigate risk, but also for value creation, allowing the company to adapt its production strategy as new information is revealed.
The main contribution of this work is a new perspective in risk assessment from a probabilistic point of view, combining production strategy selection and optimization, numeric reservoir simulation and risk-return analysis. The flexibility is an alternative to information for risk mitigation, with the advantage of not holding the project back to collect new data. Furthermore, flexibilities can also be used to exploit the upside of the uncertainty if, during the production phase, such scenarios occur.
A New General Flow Model for Well Test Analysis for Fluids Used in Enhanced Oil Recovery Projects
Authors: Valdes-Perez Alex R. , Cinco-Ley Heber , Pulido-Bello Héctor , Hveding Frode , Samaniego Fernando 
Published: June 2014

Abstract
Fluids used in Enhanced Oil Recovery (EOR) projects, such as polymers, micellars solutions and surfactants are classified as non-Newtonian fluids, due to their viscosity behavior. The measuring and analysis of pressure data during injection of non-Newtonian fluids and during fall-off periods has become popular. However, the lack of appropriate tools for its interpretation might yield incorrect results when characterizing parameters are computed, such as flowing geometry around wellbore, formation permeability, skin factor at wellbore, injected fluid consistency index, etc.
This paper presents a new general flow model for non-Newtonian fluids governed by a partial differential equation. Analytical solutions for such model are also presented. The model and its solutions are suitable to identify three of the most common flow geometries (linear, radial and spherical flow), when a displacement agent is flowing within the porous media in EOR projects. Due to its behavior, this model is appropriate when extra heavy oil is flowing in the reservoir. A better understanding and representation of the fluid flowing into the reservoir can improve the monitoring and execution of EOR projects and reservoir exploitation schemes.
Linear, Radial and Spherical diffusivity equations for Newtonian fluids are particular cases of the new model. For different flow geometries, graphs of the pressure and its derivative behavior against time are presented. A method for determining fluid consistency index and flow geometry is presented. A synthetic example that describes the application of the new model is also shown.
Uncertainty Based Approach for Predicting the Operating Window in UBO Well Design
Authors: Udegbunam John Emeka , Arild Øystein , Fjelde Kjell Kåre , Ford Eric , Lohne Hans Petter 
Published: June 2014

Abstract
Underbalanced operations are carried out to bypass drilling challenges that could be difficult to resolve using conventional drilling techniques. Steady state multiphase flow models are used to construct underbalanced drilling operational windows. These advanced software models are deterministically formulated. It is known that some of the model input parameters such as the multiphase flow parameters, friction factors, and reservoir productivity, are subject to uncertainties. Failures to capture these variabilities may introduce some error in the model prediction, resulting in poor well planning and implementation.
The purpose of this work is to implement probabilistic modeling of underbalanced drilling using a simple steady state two-phase model. Both predefined uncertain and fixed factors serve as inputs to a pre-existing deterministic model. By applying Monte Carlo simulations, the model predicts outputs which follow a statistical distribution. A sensitivity analysis is conducted to determine the input factor mostly responsible for the uncertainty in the predicted bottomhole pressure.
The results demonstrate that uncertainty modeling can improve underbalanced drilling design and operations. A more realistic operational window is obtained, ensuring that underbalanced condition is maintained throughout the target section.
With a better understanding of uncertainties and the corresponding impacts, well planners can make better decisions regarding well design criteria and safe operational conditions, and avoid huge economic consequences.