bluuebunny/crossref_metadata_2025_split huggingface dataset:
Full Field Offshore Surfactant-Polymer Flooding in Bohai Bay China
Authors: Lu Qiong , Ning Yonggen , Wang Jianghong , Yang Xue 
Published: August 2015

AbstractThis paper presents full field offshoresurfactant-polymer (SP) floodingapplied in JZ 9–3 Oilfield, Bohai Bay, China. Followed by 3-year polymer flooding which produced 4% incremental oil, the field turned to surfactant-polymer flooding. In the first stage, SP flooding was implemented in 4 injection wells. Then full field SP flooding was conducted in 8 injectors and 23 correspondent producers were involved. The injection scheme is designed as a slug of 0.23 pore volume (PV) of polymer solution at 0.120% polyacrylamide and second slug of 0.3 PV mixture of 0.20–0.24% of HDS surfactant and 0.12–0.15% of 3640C polymer and third slug of 0.035 PV of 0.12% 3640C polymer solution.By monitoring injection characteristics, oil increasing and water content decreasing, and development index, the results show significant effect in incremental oil recovery compared to polymer flooding since 2010 when the SP flooding started.By 1st, Dec, 2014, the SP flooding has been improving oil production for 42 million tons with composite water cut 73.5% which declined by about 6.5%. There are 11 wells in 23 producers has obviously responded. The daily oil production of the center correspondent producer was doubled and water content decreased from 81% to 42%. The SP flooding effects lasted for about 2 years and could be extended further. This paper presents the feasibility of SP flooding in offshore environment.
Effect of Oil Gravity and Pore Volume Injected (PVI) of Steam to PVI of Foam During Enhanced Oil Recovery by Steam-CO2-Foam Flooding
Authors: Daraei H. Nejatian , Sahraei E.. , Solouk A.. 
Published: August 2015

Abstract
In spite of CO2mobility reduction during CO2and surfactant solution co-injection, CO2-foam flooding in heavy oil reservoirs has relatively poor sweep efficiency due to the high viscosity the oil. Therefore, reducing the oil viscosity is necessary to improve CO2-foam sweep efficiency. For this reason, steam is injected initially during steam-CO2-foam flooding to reduce oil viscosity. Displacement process is followed using CO2and surfactant solution co-injection.
In our previous experimental study, in order to highlight the potential of steam-CO2-foam flooding, three different oil recovery experiments were conducted using medium heavy crude oil (19 °API), including CO2-foam flooding after water flooding, CO2-foam flooding and steam-CO2-foam flooding. The results showed that steam-CO2-foam flooding increases oil recovery dramatically by simultaneous mechanisms such as oil viscosity reduction by steam, CO2dissolution in oil and emulsification by steam and surfactant. Furthermore, the effect of high surfactant concentration slug injection on steam-CO2-foam flooding performance was investigated. The results showed that slug causes the formation of viscous micro emulsions in front of CO2-foam flood and improves CO2-foam sweep efficiency.
In this paper, the effects of oil gravity and pore volume injected (PVI) of steam to PVI of foam on the oil recovery during steam-CO2-foam flooding have been studied. The experiments are conducted using heavy oil (12 °API) and sand pack models under reservoir conditions of 1550 psi and 131°F.
In order to investigate the effect of PVI of steam/PVI of foam ratio on the oil recovery, three different oil recovery scenarios have been conducted using heavy crude oil, including CO2-foam flooding only, steam-CO2-foam flooding including 0.14 PVI of steam/PVI of foam ratio and steam-CO2-foam flooding including 0.34 PVI of steam/PVI of foam ratio. The results show that in spite of decreasing oil recovery by decreasing API gravity of the oil during steam-CO2-foam flooding, increasing PVI of steam improves oil recovery.
The steam-CO2-foam flooding process has the following benefits. (1) Combination of steam injection and CO2-foam flooding as a novel enhanced oil recovery (EOR) method to achieve favorable oil recovery. (2) The applicability of this EOR method in heavy and medium heavy oil reservoirs.
Case Study on In-Depth Blocking for Thermal Recovery by Steam Stimulation in Heavy Oil Reservoirs
Authors: You Qing , Wang Huan , Dai Caili , Liu Yifei , Fang Jichao , Zhao Guang , Zhao Mingwei , Wang Kai 
Published: August 2015

Abstract
The conventional blocking agents are hard to solve the problem of steam channeling during steam injection. In order to increase sweep volume and improve oil recovery, the in-depth blocking agents for conformance control are proposed and developed according to temperature gradient in the stratum when injecting steam. The in-depth blocking agents consist of gel system, organic/inorganic cross-linking system and inorganic curing system with different applicable temperature 60~110°C, 120~160°C and 170~300°C. The gel system with temperature resistance is composed of non-ion polyacrylamide and organic cross-linker. The organic/inorganic cross-linking system is composed of organic resin, silicide and stabilizer. The inorganic curing system is composed of superfine cement and stabilizing Na-bentonite. In this paper, the temperature distribution of heterogeneous reservoirs during the process of steam huff and puff is simulated by CMG. According to the above temperature distribution, these blocking agents are separately used for remote zone, transition zone and near wellbore zone of steam injection well. Sandpack flood tests indicate that the in-depth blocking agents have excellent blocking performance. Furthermore, the in-depth blocking agents have been applied to two injection wells in Bin'nan oilfield. After oilfield pilot test, steam injection pressure and daily oil production increased, and the input-output ratio increased to 1:3. The success of oilfield test confirms that the in-depth blocking agents are efficient to control steam channeling.
Solvent-Assisted Start-Up of SAGD in Shallow Heavy Oil Reservoirs
Authors: Wu Yongbin , Li Xiuluan , Shen Dehuang , He Wanjun , Liu Xueqi 
Published: August 2015

AbstractEffective communication between the injector and producer with a reasonable conformance during SAGD start-up phase is crucial for the success of SAGD conversion and the following ramp-up phase. The start-up operation normally relies on heat conduction mechanism to establish heat and fluid communication between the wells. For super heavy oil reservoirs in Fengcheng project in China, since the pay zone has low thermal conductivity and extremely high oil viscosity, establishing the temperature profile required for SAGD conversion using conduction as the only heating mechanism is not efficient and can take 150 to 180 days to achieve. In order to shorten the circulation time and accelerate the ramp-up phase after SAGD conversion, an approach using solvent injection with steam simultaneously to enhance injectivity was successfully designed and implemented.This paper reviews the design criteria, tests the thermal properties of cored samples, selects the typical wellpair based on geological modeling results, carries out the reservoir engineering design of solvent injection using CMG-STARS, and discusses the implementation performance of warm solvent injection in the start-up phase of a pilot wellpair in Fengcheng project. It also compares production responses of solvent-treated wellpair with other wellpairs with comparable reservoir properties in the same pad by conventional start-up to evaluate the performance of the designed pilot.
Laboratory Evaluation of Inter-Well Partitioning Tracers for the Determination of Remaining Oil Saturation after ASP Flooding
Authors: Austine J.. , van Batenburg D. W. , Southwick J. G. , Zarubinska M. A. , Paramanathan S.. , Bouwmeester R. C. , Kechut N. I. , Viig S. O. , Haugen O. B. , Brandvoll Ø.. 
Published: August 2015

Alkaline Polymer Surfactant (ASP) flooding is an Enhanced Oil Recovery (EOR) technique aiming to mobilise remaining and residual oil. Estimating the average oil saturation prior to and post ASP flooding is a recognised challenge, but is vital to the evaluation of an ASP pilot. The use of oil-water partitioning tracers is a method to determine the average oil saturation in the water-swept regions between wells. The implementation of partitioning tracer technique is known in the industry to evaluate effectiveness of waterfloods, but its applicability in ASP flooding is a topic of investigation due to additional complexities. Often, the partition coefficients of tracers depend on salinity of the aqueous phase. It is equally important to know how the presence of polymer and surfactant may influence the behaviour of partitioning tracers.
Laboratory study has been performed to analyse the behaviour of partitioning tracers prior to and post ASP injection for a field that is currently undergoing sea water injection and is being evaluated for ASP flooding later in the field life. A group of six oil-water partitioning tracers have been included in the study. Batch (bottle tests) and dynamic (core flood) experiments were performed to evaluate the partitioning behaviour of the tracers. The residual oil saturation to water (Sorw) before ASP flooding was determined using pulse injections of tritium labelled water (HTO). Several passive tracers were also injected in the core floods and their retention times were compared with that of HTO.
Herein we describe evaluation of oil saturation, through the tracer responses, over a range of brine compositions such as soft brine, sea water, ASP and polymer solutions. Batch studies indicate the dependency of the partitioning of the tracers on brine salinity. The results of core floods show earlier breakthrough of anionic passive tracers in comparison with HTO suggesting possible rock/fluid interactions for the anionic passive tracers. The residence time distribution of HTO measured before, during and after the ASP flooding illustrates that the flow paths available for water were changed during ASP flooding.
The paper highlights the importance of good laboratory experimental protocols using a more accurate passive tracer such as tritium labelled water. The results from the experiments draw attention to the uncertainties associated with the flow of tracers under changing salinity and chemical composition.
Contribution of Pore-Shape to the Polymer Apparent Viscosity
Authors: Kawale D.. , Boukany P. E. , Kreutzer M. T. , Rossen W. R. , Zitha P. L. 
Published: August 2015

Abstract
Polymer injection is a widely used enhanced oil recovery technique. Optimizing this process requires a thorough understanding of the nature of polymer flows through the porous medium. The current approach involves using an apparent viscosity, as described by the Darcy's law. Such an apparent viscosity is an effective parameter which accounts for effects introduced by the porous medium and the bulk rheology of polymer solutions. These effects include excluded pore volume, inaccessible pore volume, adsorption/retention, shear-thinning, shear-thickening due to converging-diverging channels, non-uniform flow channels, and viscoelasticity. To explain the apparent shear-thickening behaviour in porous media, the existing models use an ad hoc hypothesis; that is, the experimental evidence for these effects is missing. The objective of this study is to obtain a mechanistic picture. We study the effect of pore shape on the apparent viscosity, as the shear rate is varied.
Microfluidic devices containing 2D planar porous media with different pore shapes are fabricated using lithography techniques. The devices are essentially periodic arrays of obstacles in square and diamond layouts. Simultaneously measuring the pressure drop while visualizing the flow field allows us to map the flow-field variations on an apparent-viscosity map. We visualize the flow by seeding the polymer solution with fluorescent particles. A time-steady flow field is observed in the shear thinning region, whereas, flow instabilities are observed at the range of shear rates where the shear thinning region ends and the shear thickening region starts. This suggests that the shear-thickening region is somehow connected to those instabilities.
Power spectral density is calculated by applying Fast Fourier Transform to the pressure drop time-series data. The power spectral density in the shear-thickening region reveals power law scaling. This power law scaling indicates that the energy from large vortices is gradually transferred to smaller vortices, until it is dissipated as thermal energy. Such an energy cascade system is a typical characteristic of large Reynolds number turbulent flow. However, in our experiments the Reynolds is low, whereas the Weissenberg number is large. Under these conditions, the flow instabilities that we observe originate from an interplay of the shear thinning viscosity and the elastic stresses in the polymer solution.
Simulation for High Viscoelasticity Polymer Flooding Pilot in LMDN4-4 Block of Daqing Oilfield
Authors: Chen Guo , Wei Changqing , Han Xu , Han Peihui , Ma Moran , Zhang Xinliang , Lu Kewei 
Published: August 2015

Daqing Oilfield has carried out a high viscelasticity polymer flooding pilot in LMDN4-4 Block, demonstrating that the high viscoelasticity polymer flood has bigger capability to further increase oil recovery over moderate viscoelasticity polymer flood. The bulk viscosity of produced polymer solution taken from a monitoring well is around 140 mPa.s, using the high viscosity data as input parameters to conduct history matching by commercial simulator indicated that injection pressure from simulation is much higher than that from observation data, resulting from the higher bulk viscosity together with having no take polymer elasticity process mechanism into account. Therefore, how to successfully conduct simulation for high viscoelasticity polymer flood is a big challenge.We have conducted a series of lab and reservoir engineering studies to further realize and characterize the polymer elasticity process mechanism so as to achieve a good history matching. Polymer flooding capillary desaturation curve at different polymer elasticity level is established, relative permeability curve for high viscoelasticity polymer flooding is obtained, and the flowing viscosity in porous media for polymer solution with high viscoelasticity is estimated based on the polymer flooding performance data. All these research results provide very accurate input parameters for the simulation model, running by an in-house simulator that has incorporated polymer elasticity process mechanism model.Based on these newly methods above, the production performance for the high viscoelasticity polymer flood pilot has been matched very well, showing that: (1) High viscoelasticity polymer flood simulation should take the polymer elasticity process mechanisms of reducing residual oil saturation and increasing oleic phase relative permeability into account, (2) It is the flowing viscosity of polymer solution that acts on the flow process in polymer flooding rather than the bulk viscosity, and the flowing viscosity is dramatic lower than the bulk viscosity for high viscoelasticity polymer solution.
Toward an Alternative Bio-Based SP Flooding Technology: I. Biosurfactant Evaluation
Authors: Luque Alanis P. A. , AlSofi A. M. , Wang J.. , Han M.. 
Published: August 2015

Abstract
Surfactant-polymer (SP) flooding is one of the most promising methods in enhanced oil recovery (EOR), especially where an existing waterflooding infrastructure is in place. This work is part of a broader research theme in which our group is evaluating the potential of biochemicals for chemical enhanced oil recovery (CEOR). Biosurfactants belong to a diverse group of surface-active chemicals generated by microbial fermentation. Recently, the use of biosurfactants in a CEOR formulation has gained greater attention due to their biodegradability, low toxicity, and effectiveness at high temperature and salinity. In this work, we evaluate the potential of a particular biosurfactant for CEOR application in a carbonate reservoir that is characterized by high temperature and high salinity. We evaluate the biosurfactant compatibility, interfacial tension (IFT) reduction, stability, and adsorption. We benchmark its performance against a synthetic surfactant that had previously proved potent. Compatibility with the field brines (injected and connate) is investigated by observation of solution appearances. IFT reduction is measured using a spinning drop tensiometer. IFT, after prolonged heating, was also measured to investigate the stability of the biosurfactant. Finally, static adsorption tests were conducted using crushed rock samples where changes in biosurfactant concentration, and adsorption, was inferred using a total organic content analyzer.
The biosurfactant showed excellent compatibility with field brines at reservoir temperature. It exhibited low static adsorption of 0.65 mg/g. Most importantly, at a concentration of 2000 ppm, the biosurfactant resulted in a very low IFT in the order of 10−2 mN/m. The biosurfactant resulted in an IFT reduction that is comparable to that achieved with the benchmark surfactant. A coreflood, where the biosurfactant was injected in a tertiary mode, demonstrated an additional production of around 6.5% OOIC (original oil in the core). The expected performance of this biosurfactant was further compared to the benchmark surfactant using numerical simulation. Core-scale simulation results suggest the biosurfactant can yield incremental recoveries that are comparable to those obtained using the benchmark surfactant. At the core-scale, a tertiary SP flood, in which a biochemical surfactant is used, can yield an additional production of around 17% OOIC. The results discussed in this paper constitute the first step toward developing an alternative bio-based SP flooding technology for carbonate reservoirs with harsh conditions.
Predicting Interfacial Tension Using Advanced Meso-Scale Modelling Technique
Authors: Kamal Muhammad Shahzad , Matar Ali-Al , Sultan Abdullah S , Hussein Ibnelwaleed A 
Published: August 2015

Abstract
Surfactant EOR is an attractive method to recover residual oil from light oil reservoirs. Selection of suitable surfactant for a particular reservoir conditions is a challenging and time consuming task. Surfactants have to be evaluated through a series of evaluation steps which include: compatibility, phase behavior, thermal stability, interfacial tension (IFT), adsorption and core flooding. IFT measurements are challenging and time consuming particularly at high-temperature. Due to dynamic nature of IFT it may take several hours to reach an equilibrium value. Moreover, commercially available techniques rely on the shape of the oil drop which is not necessarily to be exactly cylindrical. In this paper a meso-scale molecular modelling technique called Dissipative Particle Dynamics (DPD) will be used to predict IFT of water/oil/surfactant ternary system.
In this technique different molecules of similar structures are lumped into single bead. Beads don't have fixed properties being composed of different elements. Bead properties need to be determined either using molecular simulation or by experimental values. In this work bead-bead repulsion parameters were calculated using molecular simulations. Hexane, nonane and pentadecane were used as model crude oil. Sodium dodecyl sulphate was used as surfactant.
As different molecules are lumped into single beads, faster evaluation of surfactants can be performed. The interfacial properties like interface thickness and interfacial tension and their dependence on oil types, surfactant types, oil/water ratio, surfactant concentration and surfactant chain length at particular temperature and pressure were investigated. Good qualitative as well as quantitative agreement of the modelled properties was obtained with experimental data. Detailed methodology, theory and results will be discussed in the paper. DPD technique is a novel way for initial screening of surfactants and can reduce experimental tests and time.
Pore Scale Visualization during Carbonate Heavy Oil Recovery: Surfactant Alternating CO2 Foam/Polymer Enhanced Foam Flooding
Authors: Telmadarreie Ali , Trivedi Japan 
Published: August 2015

Abstract
Carbonate reservoirs hold significant reserves of heavy crude oil that can be recovered by non-thermal processes. Chemical, gas, water, and solvent injections are the main methods for carbonate heavy oil recovery. Chemical enhanced oil recovery (EOR) from oil-wet carbonate reservoirs has been focused on using surfactants to change the wettability and enhance water imbibition into matrix blocks. Due to the fractured nature of carbonate formations, many advantages of these production methods are usually contrasted by their low recovery factor. Alternative processes are therefore needed to increase oil sweep efficiency from the matrix. Foam/polymer enhanced foam (PEF) injection has gained interest in conventional heavy oil recovery in recent times. However, the oil recovery process by foam injection, especially by PEF, is less understood in fracture heavy oil carbonate reservoirs.
This paper introduces a new approach to access the heavy oil from fractured carbonate reservoirs. CO2 foam and CO2 PEF were used to decrease oil saturation after surfactant flooding. Three types of surfactants (nonionic, anionic and cationic) were used for both surfactant and foam flooding. A specially designed fractured micromodel was used to visualize the pore scale phenomena during CO2 foam/PEF injection. In addition, the static bulk performances of foam/PEF were analyzed in the presence of heavy crude oil. A high definition camera was utilized to capture high quality images.
The results showed that, in both static and dynamic studies, the PEF had higher stability than that of foams. Nonionic surfactant generated the least stable foam in the presence of crude oil. Surfactant flooding slightly increased the oil recovery from matrix after water injection. This was more evident in the case of CTAB surfactant with highest imbibition rate. This study showed that there is an acceptable relationship between the results of foam static stability and its dynamic performance in porous media. DDBS foam had higher static stability, which resulted in the highest oil recovery in dynamic experiments. Observation through this study proved that stable foam/PEF bubbles can significantly push the injected fluid toward untouched parts of the porous media and increase the oil recovery. Due to the liquid viscosity enhancement and bubble stability improvement, the effectiveness of PEF in heavy oil sweep efficiency was much higher than that of conventional foams. PEF bubbles generated an additional force to divert surfactant/polymer into the matrix. The results of pore scale visualization improved understanding of the heavy oil recovery process by CO2 foam/PEF flooding from fractured reservoirs.