bluuebunny/crossref_metadata_2025_split huggingface dataset:
Polymer Chemical Structure and its Impact on EOR Performance
Authors: Beteta Alan , Nurmi Leena , Rosati Louis , Hanski Sirkku , McIver Katherine , Sorbie Kenneth , Toivonen Susanna 
Published: August 2020

Abstract
Polymer flooding is a mature EOR technology that has seen an increasing interest over the past decade. Co-polymers of Acrylamide (AMD) and Acrylic Acid (AA) have been the most prominent chemicals to be applied, whereas sulfonated polymers containing 2-Acrylamido-tertiary-butyl sulfonic acid (ATBS) have been used for higher temperature and/or salinity conditions. The objective of this study was to generate guidelines to aid in the selection of appropriate polyacrylamide chemistry for each field case. Our main focus was in sandstone fields operating at the upper end of AMD-AA temperature tolerance, where it needs to be decided whether sulfonation is required. The performance of the polymer throughout the whole residence time in the reservoir was considered since the macromolecule can undergo some changes over this period.
Several key properties of nine distinct polymer species were investigated. The polymers consisted of AMD-AA co-polymers, AMD-ATBS co-polymers and AMD-AA-ATBS ter-polymers. The polymers were studied both in their original state as they would be during the injection (initial viscosity, initial adsorption and in-situ rheology) as well as in the state which they are expected to be in after the polymer has aged in the reservoir (i.e. in a different state of hydrolysis and corresponding viscosity retention and adsorption after ageing for various time periods). We note that the combination of viscosity retention and adsorption during the in-situ ageing process has not been typically investigated in previous literature, and this is a key novel feature of this work. Each of the above parameters has an impact on the effectiveness and the economic efficiency of a polymer flooding project. The content of ATBS was limited to 15 mol%. Buff Berea sandstone was applied in the static and dynamic adsorption experiments.
The majority of the work was carried out in seawater at temperature, T = 58°C. Under these conditions AMD-AA samples showed maximum viscosity and lowest adsorption when the content of AA was moderate (20 mol%). When the AMD-AA polymers were aged at elevated temperature, the AA content steadily increased due to hydrolysis reactions. When the AA content was 30 mol% or higher, the viscosity started to decrease, and adsorption started to increase as the polymer was aged further. Thermal stability improved when ATBS was included in the polymer structure. In addition, sulfonated polyacrylamide samples showed increasing initial viscosity yields and decreasing initial adsorption with increasing ATBS content. For most of the samples, the maximum observed apparent in-situ viscosity increased when the bulk viscosity and relaxation time of the sample solution increased.
The information generated in this study can be used to aid in the selection of the most optimal polyacrylamide chemistry for sandstone fields operating with moderate/high salinity brines at the upper end of AMD-AA temperature tolerance.
Managing Gas-Injection-Induced Excessive Water Production in Tight Oil Reservoirs by Optimizing Operational Constraints
Authors: Zhang Chi , Tian Ye , Wu Yu-Shu 
Published: August 2020

Abstract
A CO2 huff-n-puff pilot implemented in the Midland Basin demonstrated a significant oil rate improvement, but also witnessed an escalation in water-cut up to 0.3. A compositional model was established to consider the complex physics including cyclic stress changes, reopening of water-bearing layers, reopening of unpropped fractures and its resulting relative permeability shift. Our previously published work suggested that the reopening of unpropped fractures and its resulting relative permeability shift contributes most to the abnormal water cut surge after gas injection. In this study, we further proposed several operational constraints to manage such high water-cut occurrence after gas injection. The optimized simulation results suggested that around 1.5 times increase in recovery factor can be achieved after six CO2 huff-n-puff cycles. Sensitivity analysis was subsequently conducted regarding parameters such as soaking time, injection time, and bottom-hole pressure. It was found that soaking time and bottom-hole pressure did not have much influence on cumulative oil production. Setting injection time as 150 days in each cycle can achieve the highest net present value. The primary objective of this study is aimed at optimizing techniques for conducting CO2 huff and puff process to maximize oil production and minimize CO2 emission.
An Advanced Compositional Analysis of Crude Oil-Brine Interface and the Effect of Involving Interactions on the Performance of Low Salinity Water Injection
Authors: Fattahi Mehraban Mohammad , Farzaneh Seyed Amir , Sohrabi Mehran 
Published: August 2020

Abstract
Despite the plethora amount of research have been conducted on the Low Salinity Water Injection (LSWI) and the pertinent mechanisms, this Enhanced Oil Recovery (EOR) method still seems not to be well understood. Although the rock/fluid interactions are used to be highlighted as the main elements of chemical mechanism of LSWI, fluid/fluid interactions have been brought into attentions much more than anytime before. Formation of microdispersion within the crude oil phase leading to wettability alteration has been proposed repeatedly as the underlying mechanism of LSWI without clarifying the functional compounds of crude oil toward this EOR method. Discovering the responsible compounds of crude oils towards Low Salinity Water (LSW) and formation of microdispersion is demanding to achieve a reliable screening tool of oil reservoir toward LSWI.
For this purpose, the crude oils and brines were contacted for an extended period of time until the oil/water interface reached an equilibrium state right before taking crude oil samples from the interface. The Karl Fischer titration (KFT) analyses were carried out to quantify the amount of microdispersion within the crude oil phase. The crude oil sample with the strongest propensity toward microdispersion formation was further investigated through Fourier Transform Infrared (FT-IR) spectroscopy and Negative Electrospray Ionisation (NESI) mode of Fourier Transform Ion Cyclotron Resonance mass spectroscopy (FT-ICR) to evaluate the chemical compositional changes taking place at the interface due to salinity effect.
FT-IR analyses revealed the conjugated acidic compounds or the acidic asphaltenes within the crude oil to be the most functional compounds toward microdispersion formation. Consistently, the NESI mode of FT-ICR MS suggested the carboxylic acids (with C=O functional groups) promoting the formation of microdispersion when the crude oil is swept by LSW. Also highlighted was the structure of functional carboxylic acids during LSWI that appeared to be those compounds with DBE of 1, 2, and 3 and carbon number of C15-C20.
The results of this study represent an important step toward understanding the mechanism responsible for the LSE. The knowledge will help the oil and gas industry in the task of evaluating and ranking oil reservoirs for EOR by LSWI.
Impact of EOR Chemicals on Oil-Water Separation Processes, from Laboratory Scale to Flow Loop Scale
Authors: Cassar Cyril , Mouret Aurélie , Salaün Mathieu , Klopffer Marie-Hélène 
Published: August 2020

Abstract
With the use of chemically-based enchanced recovery methods, water management which has always been a major point in the production operation processes, needs to be considered and adapted as the whole water cycle will be impacted by the back-produced additives. The main issues encountered in oil-water separation processes are directly related to the risk of tight emulsions formation which may considerably complicate the water treatment surface processes.
The objective of this paper is to underline the impact of EOR chemicals (surfactants) on the produced water cycle, when they are back produced firstly, at a laboratory scale and secondly, on a large scale separation unit using an industrial size flow loop and a well instrumented separator.
At the lab scale, impact of having surfactant within produced fluids on oil/water separation (regarding the separation kinetics but also the oil and water phases qualities) will be evaluated by performing bottle tests.
Those laboratory bottle tests enabled us to screen various different parameters such as the surfactant concentration, the water cut that may strongly impact the type of formed emulsion (O/W or W/O) and its stability. The oil and water phases qualities were quantified and correlations with parameters related to the large scale experiment have been drawn, helping us in defining the key parameters for this last campaign.
Indeed, to get closer to a field case, a semi industrial-scale test platform (IFPEN GOwSP loop) was used. Main operating conditions are liquid flow rate set between 6 and 10 m3/h and temperature 50 °C. The influence of different parameters may be studied such as the concentration of surfactant, the mixing conditions (liquid flow rate), the residence time controlled by the height of water phase in separator, the water cut and the presence of chemicals that will help the separation process. Different types of emulsion were formed depending on the tests conditions and their stability were evaluated through the measurement of separation profiles using a SECAP probe within the separator.
The presented results will show how the surfactant but also the demulsifier concentration have led to different types of emulsions and have influenced the oil-water separation processes.
Laboratory workflows as well as experiments carried out at large scale using an industrial size separator could help the de-risking of operations to mitigate these challenges in terms of separation issues.
This work illustrates that water management is a major challenge for produced fluids containing EOR chemicals that need an integrated approach and should be studied beforehand.
New Insights into the Interfacial Phenomena during Miscible Displacement by Hydrocarbon Solvents and CO2 in Heavy Oil Reservoirs
Authors: Mohammed Mohammedalmojtaba , Babadagli Tayfun 
Published: August 2020

Abstract
Injection of solvents (hydrocarbons in liquid and gas form or CO2 and their combinations) is an alternative method for heavy and extra heavy-oil recovery where thermal methods cannot be applied, like in thin reservoirs, wormholed reservoir after-CHOPS (cold heavy-oil production with sands), or fractured reservoirs. The solvents normally exist in their liquid or supercritical phase under reservoir conditions and may not be miscible with heavy oil at first contact. Coupling with the fact that diffusion into highly viscous fluids tends to be very slow and an interface exists in the first contact of liquid solvent and oil, displacement by capillary imbibition may take place. This displacement eventually improves the contact area between oil and solvent and results in enhancement of the mixing process by diffusion.
To understand this phenomenon and fully capture the interaction of solvent and heavy oil in different rock systems, experimental investigations were conducted using sandstone and limestone core samples. The samples were saturated with different types of oils (viscosities ranging between 14 and 170,000 cP) and the solvents tested were heptane, propane, decane, CO2, and naphtha. To maintain the pressure of propane and CO2 above the saturation pressure, a specially designed high-pressure imbibition cell was used and the imbibition-diffusion process was visualized through the glass window of the cell. The color of the mixture and the amount and the shape of produced oil over time was used to analyze the mass transfer and flow behavior qualitatively and quantitatively by observing the evolution of oil production from core samples that were saturated with heavy oil and then immersed into solvents.
We observed that in the solvent/heavy oil system, where molecular diffusion is a slow process, a dynamic interfacial tension IFT exists, but vanishes over time; when the CO2 is in the non-wetting phase the capillary force acts to retain the oil in porous media. As the IFT is reduced, capillary force is weakened and gravity governs the process. Hence, the fluid saturation in the porous media is totally determined by density and viscosity difference. If the wettability of the rock is altered during the process from oil-wet to more CO2 wet, because of oil-rock interaction, then it is possible for the porous media to spontaneously imbibe CO2.
A Case Study of SACROC CO2 Flooding in Marginal Pay Regions: Improving Asset Performance
Authors: Kalteyer John 
Published: August 2020

Abstract
Since the beginning of injection in 1972, carbon dioxide has been utilized at the SACROC Unit of the Kelly-Snyder Field to improve and enhance oil recovery. As one of the first fields in the world to attempt this technique, SACROC provides a unique opportunity to study, learn from, and improve upon the development of this technology.
Between initial gas injection and the year 2000, approximately 1 TCF of CO2 had been injected into the Canyon Reef reservoir. While multiple pilot programs from this time period reported incremental response following CO2 injection, many of these volumes are now attributed to residual waterflood affects as many of these projects were not truly miscible CO2 floods. Since that time, advances in technology, improvements in reservoir knowledge, and increases in scale have expanded the boundaries of economically viable enhanced oil recovery. As a result, projects that were once considered marginal in reservoir quality and redevelopment potential are now exhibiting improved recovery responses across the field. Since taking over as operator at SACROC in 2000, Kinder Morgan has redeveloped more than 25 major project areas including more than 600 patterns within the unit. Under Kinder Morgan operations, cumulative CO2 injection has surpassed 7 TCF yielding a cumulative enhanced oil recovery of over 180 million barrels.
This case study will review the history of enhanced oil recovery at SACROC, discuss changes in theory over time, and provide a forward look at what remains for this field. This analysis will focus on the first CO2 injection pilot programs, dimensionless oil and CO2 recovery performance and their impact on forecasting, and inclusion of the transition zone and other marginal pay areas in redevelopment. Additionally, this study will highlight the major operational issues encountered over time and the associated improvements that have contributed to enhanced oil recovery. These advancements include conformance improvements, upgraded field surveillance, and proper management of the overall injection- production system. In conclusion, the case will review the Hawaii and East Flank CO2 Flood Expansions: two recently developed marginal pay projects undergoing miscible CO2 flooding at SACROC. Successful redevelopment of these marginal pay projects is allowing for expansion to areas of the field once considered marginal in quality and accordingly uneconomic.
Thermally Activated Particles Injection for Deep Conformance Control to Improve Oil Recovery in an Argentina Mature Waterflooded Reservoir: Cerro Dragon Field. Design, Field Implementation and Results
Authors: Iuliano Alberto , Gómez Javier E. , Martínez Christian R. , Alonso Laura C. , Kazempour Mahdi , Kiani Mojtaba , Alzate Daniela , Singh Praveen , Jerauld Gary 
Published: August 2020

Abstract
The interplay among reservoir heterogeneities, structural complexities and unfavorable mobility ratios are usually responsible for premature water breakthrough in brown fields across the world. Recently, a deep conformance control technology, known as Thermally Activated Particle (TAP), has been successful in addressing this challenge. Limited intervention and lower deployment cost make it very attractive for mature waterflooded fields.
Cerro Dragón is a giant field located in San Jorge Gulf basin with multi-layered channel deposits. Presence of highly conductive channels and unfavorable mobility ratios have severely impacted the sweep efficiency, resulting in low oil recovery and high water production. Building on the learnings from the previous pilots, TAP has been recently deployed at a segment scale in one of the blocks of Cerro Dragón field. This paper shares the technical details behind the screening, designing and the deployment of TAP technology.
After initial screening of multiple candidates, a reservoir segment has been selected for TAP implementation. Inter well tracer data with comprehensive injection/production data analysis identified the communicating wells and thief zones volumes were then estimated around each injector. The estimated thief zones volumes were also confirmed by volumetric calculation. Thermal modeling and numerical simulation were utilized using a representative and history matched model to finalize the size, concentration and the proper activation of injected TAP molecules.
Subsequently, in early 2018, nearly 360 metric tons of TAP was safely deployed into six target injectors. This campaign met all design guidelines, all planned surveillance data was acquired, and the project was executed on time and on budget. Post deployment, frequent sampling at offset producers was performed confirming no breakthrough of un-activated polymeric particles. Oil rates and WOR trends are currently being monitored, as part of the longer-term surveillance plan, to quantify incremental benefits from TAP EOR technology.
Previous 2011 implementation and positive results in other segments of the field were an important input and they are also described in this paper.
The results of this treatment will provide very helpful guidelines that can be used in any brown fields to improve the efficiency of waterflooding especially in highly heterogeneous reservoirs with low waterflooding performance.
Seismic AvO Inversion and Net Sand Estimation in Deep Water Turbidite Sands, Kangaroo Field, Offshore Nigeria
Authors: Osayande Francesca , Oguntola Somime , Sonde Adenike , Biambo Tamunotonye , Osho Olaseni , Okpako Kelvin , Musa Joel , Anaevune Austin , Mora-Glukstad Miguel , Yamusa Idris 
Published: August 2020

Abstract
The Kangaroo is a field located in the Deepwater Nigeria in water depths ranging from 950 to 1,500 meters. Structurally, the field can be described as a NW-SE trending shale-cored anticline with crestal faulting. Several wells have been drilled encountering primarily oil, in a series of Upper to Middle Miocene channelized turbidite reservoirs. The Kangaroo field is a brown field with challenges of unlocking its full potentials. The key subsurface uncertainties identified, were sand distribution and intra-reservoir connectivity. The existing reservoir models did not fully describe the reservoir net sand thickness and as a result, recent drillings have highlighted series of surprises warranting a study, to gain more insights into the sand distribution and reservoir heterogeneity.
This study highlights a multi-stack simultaneous seismic inversion used in conjunction with rock physics analysis, for a detailed reservoir characterisation, re-mapping of key reservoirs and prediction of Net-to-gross away from well control. Five offset angle seismic sub-stacks have been inverted with a Simultaneous Inversion algorithm, ultimately converting the reflectivity seismic data into rock property models, generating acoustic impedance (Zp), shear impedance (Zs), and density (ρ).
A feasibility study including crossplots of petrophysical and elastic properties from well data was carried out to establish rock property relationships in the interval of interest and this formed the basis for the seismic inversion studies. Key business driving value for this study, is the derivation of a robust estimates of net sand distribution, its impact on modelling reservoir parameters, and consequent estimation of in-place volumes.
A single oral fixed-dose praziquantel-miltefosine nanocombination for effective control of experimental schistosomiasis mansoni
Authors: Eissa Maha Mohamed , El-Azzouni Mervat , El-Khordagui Labiba Khalil , Bary Amany Abdel , El-Moslemany Riham Mohamed , Salam Sara Ahmed Abdel 
Published: August 2020

Abstract
Background: The control of schistosomiasis has been centered to date on a single drug, praziquantel, with shortcomings including treatment failure, reinfection, and emergence of drug resistance. Drug repurposing, combination therapy or nanotechnology were explored to improve antischistosomal treatment. The aim of the present study was to utilize a novel combination of the three strategies to improve the therapeutic profile of praziquantel. This was based on a fixed dose nanocombination of praziquantel and miltefosine, an antischistosomal repurposing candidate, co-loaded at reduced doses into lipid nanocapsules, for single dose oral therapy. Methods: Two nanocombinations were prepared to provide 250 mg praziquantel-20 mg miltefosine/kg (higher fixed dose) or 125 mg praziquantel-10 mg miltefosine/kg (lower fixed dose) respectively. Their antischistosomal efficacy in comparison with nontreated control and their praziquantel or miltefosine singly loaded counterparts was assessed in murine schistosomiasis mansoni. A single oral dose of either formulation was administered on the initial day of infection, the 21st and 42nd days post infection. Scanning electron microscopic, parasitological and histopathological studies were used for assessment. Preclinical data were subjected to analysis of variance and Tukey post hoc test for pairwise comparisons. Results: Lipid nanocapsules (~58 nm) showed high entrapment efficiency of both drugs (>97%). Compared to singly loaded praziquantel-lipid nanocapsules, the higher dose nanocombination showed a significant increase in antischistosomal efficacy in terms of statistically significant decrease in mean worm burden, particularly against invasive and juvenile worms, and amelioration of hepatic granulomas (p ≤0.05). In addition, scanning electron microscopic examination showed extensive dorsal tegumental damage with noticeable deposition of nanostructures. Conclusions: The therapeutic profile of praziquantel could be improved by a novel multiple approach integrating drug repurposing, combination therapy and nanotechnology. Multistage activity and amelioration of liver pathology could be achieved by a new praziquantel-miltefosine fixed dose nanocombination providing 250 mg praziquantel-20 mg miltefosine/kg. To the best of our knowledge, this is the first report of a fixed dose nano-based combinatorial therapy for schistosomiasis mansoni. Further studies are needed to document the nanocombination safety and explore its prophylactic activity and potential to hinder the onset of resistance to the drug components.