bluuebunny/crossref_metadata_2025_split huggingface dataset:
CO2 Mobility Control With Dissolved Polymers: A Core-Scale Investigation Of Polymer-Rock and Polymer-Oil Interactions
Authors: Rousseau David , Renard Stéphane , Prempain Benoît , Féjean Christophe , Betoulle Stéphane 
Published: April 2012

Abstract
CO2-dissolved polymers could be used as mobility control agents for CO2-EOR. Unlike classical CO2 mobility control techniques, using polymers would involve a single thermodynamically stable CO2 phase and would not require water injection, which would eliminate difficulties linked to well acidification. Developing an industrial "CO2-polymer" EOR method implies three challenges. i) Suitable polymers must be evaluated in terms of solubility in CO2 under reservoir conditions and thickening ability. ii) Polymer-oil and polymer-rock interactions must be understood. Their consequences in terms of effective polymer transport far from the injection wells and potential mobility or permeability impairment must be physically modeled. iii) Reservoir scale simulations must be carried out to determine an economically optimal scenario (with parameters such as viscous slug size and polymer concentration).
Although the first of the abovementioned topics has received some attention from researchers in the past years, the two others have not been studied yet. In this paper, we report, for the first time, an investigation of polymer-oil and polymer-rock interactions from coreflood experiments involving polymer-thickened CO2. We have studied polydimethylsiloxane-based model systems whose solubility in CO2 and viscosity enhancement ability have been previously evaluated in the literature. The coreflood tests were carried out with an experimental setup designed to enable on-line viscosity measurements downstream the cores and quantitative compositional analysis of the effluents. Results show that part of the injected polymer is immobilized in the porous media, and that this phenomenon originates not only from adsorption/retention in the rock surface/matrix but also from polymer dissolution in residual oil. We have also observed that polymer immobilization had moderate impact in terms of injectivity degradation and no impact in terms of irreversible permeability reduction. These insights could be used as input data for reservoir simulation.
Controlled Hydrophobe Branching to Match Surfactant to Crude Oil Composition for Chemical EOR
Authors: Barnes Julian R. , Groen Khrystyna , Dubey Sheila , Reznik Carmen , Buijse Marten A. , Shepherd Andrew G. 
Published: April 2012

Abstract
In this paper an innovative structure/property approach is used to evaluate several commercially available surfactants in tests relevant to both alkaline-surfactant-polymer (ASP) and surfactant-polymer (SP) floods, in order to gain an understanding of how hydrophobe structure is related to surfactant performance and crude oil composition. The surfactant structural elements considered here include relative branching level and carbon chain length. This has application to chemical EOR implementation in fields over a range of reservoir temperatures and salinity. Phase behavior (giving interfacial tension), and micro-emulsion viscosity tests were carried out for internal olefin sulfonates and mixtures with alcohol propoxy sulfates to identify those that perform well while minimizing or eliminating the use of costly co-solvents. Hydrophobe branching and carbon chain length, characterized by gas chromatography, were used to match surfactants to certain crude oil properties such as natural surfactants, including total acid number (TAN) and asphaltenes, and the ratio of saturates/aromatics. The paper also examines how crude oil sampling influences crude properties and surfactant performance. The approach used and associated data contribute to cost reduction of formulations through a) better matching of commercially produced surfactants to the reservoir and crude oil properties to improve oil recovery efficiency, and b) minimizing or eliminating the use of co-solvents to reduce formulation and logistics costs. In addition, the study demonstrates how binary blends from a few core surfactants can match formulations across regionally different crude oils thereby simplifying formulation selection, and reducing uncertainty and cost.
Field Scale Application of the SOS-FR (Steam-Over-Solvent Injection in Fractured Reservoirs) Method: Optimal Operating Conditions
Authors: Naderi K. , Babadagli T. 
Published: April 2012

Abstract
Heavy oil reserves are considered to be the upcoming hydrocarbon resource. Yet, more efficient methods are needed as there are substantial economical and environmental drawbacks to sole injection of steam and solvents. A combined application of these yielded promising results in the laboratory experiments. But, optimal application conditions and cost lowering options need to be determined.
Steam-over-solvent injection in fractured reservoirs (SOS-FR) is a recently proposed method which consists of an alternate injection of steam and hydrocarbon solvents to improve oil recovery over steam injection and accelerate the solvent retrieval rate. The initial tests were done for hot-water conditions instead of steam and liquid solvents for simplicity (Al-Bahlani and Babadagli, 2008; 2009a-b; 2011b). In our modification to this method, we introduced CO2 as an alternative to hydrocarbon solvents for only one pressure and temperature condition (Naderi and Babadagli, 2012). Initial results out of this study showed a moderate recovery of 50% OOIP in average for unfavorable matrix conditions (oil wet).
In the present study, the SOS-FR applications with CO2 were tested at various conditions numerically and with different timings to improve the recovery. First, the effect of different parameters was studied to obtain the best match between the simulation and experimental results. This exercise not only provided data for field scale simulations (relative permeability and diffusion coefficients) but also clarify the impact of different rock and fluid properties on the mechanics of the proposed EOR technique.
Finally, an optimization scheme was suggested for field scale applications. In this exercise, a field scale numerical model of experiments was performed based on experimentally validated core scale model and the optimal conditions (solvent type, application pressure and temperature, duration of cycles) were determined to maximize the recovery.
A New Formulation For Decoupling of Large and Small Scale Heterogeneities in Multi Layered Reservoirs
Authors: Moghanloo Rouzbeh Ghanbarnezhad 
Published: April 2012

Abstract
This paper examines decoupling of the small-scale heterogeneity and permeability variation in multi-layered reservoirs. Here, the growth of vertically averaged concentration is formulated through incorporating dispersivity and the permeability variation; hence, unrealistic large dispersivity values, needed otherwise, are avoided to match the concentration distribution in time-distance domain.
A simulation approach is used to verify the analytical solution derived in this study. The simulation models consist of a vertical injection well and a producer located at the ends of two-dimensional (2D) heterogeneous reservoirs. The vertically averaged concentration from simulation is compared with the average concentration obtained from the analytical solution. The simulation results match the analytical solution.
It is concluded that scale-dependent dispersivity in the field-scale represents the lack of knowledge about the heterogeneity involved in the system. The results suggest that the effects of permeability heterogeneity that are ignored while using the one-dimensional (1D) solution of the convection-diffusion (CD) equation manifest themselves as an apparent scale-dependent dispersivity. Furthermore, the impact of heterogeneity and dispersivity on the length of the mixing zone within each layer of 2D reservoirs is evaluated in this study. From that, I determine the fraction of layers in which the mixing zone grows faster than that 1D dispersive flow as a function of the Koval factor and input dispersivity. The transition between channeling and dispersive flow regimes is clearly shown in the examples studied here.
Evaluation of a Vietnam Offshore CO2 Huff "n" Puff Test
Authors: Uchiyama Tadao , Fujita Yusuke , Ueda Yoshiaki , Nishizaki Aiko , Okabe Hiroshi , Takagi Sunao , Mitsuishi Hiroshi , Kawahara Yohei , Huy Le , Trung Phan Ngoc , Trung Nguyen Huu , Van Toan Nguyen , Hoan Nguyen Ngoc 
Published: April 2012

Abstract
First CO2-EOR application to the offshore oil field in Vietnam has been investigated through an international joint study scheme between Japan and Vietnam since 2007 and a preliminary study outcome indicated feasibility to some extent. To reduce and mitigate uncertainties/risks in the field scale EOR implementation, a CO2-EOR pilot test was executed in Vietnam offshore oil field in 2011.
The test was conducted as a single-well Huff ‘n’ Puff. CO2 was injected into the well and the well was flowed after soaking. In order to confirm the CO2-EOR effect the following items were monitored during the test: 1)CO2 Injection Performance2)Real Time Bottom-hole Pressure/Temperature3)Oil/Gas/Water/CO2 Production Performance4)Fluids' Saturation Change before and after CO2 Injection5)Produced Fluid Property & Composition on-site
Over 100 tons of CO2 were successfully injected into the well. Bottom-hole pressure was kept higher than MMP (Minimum Miscibility Pressure) during the injection period, thus miscible condition was considered to be achieved in the reservoir at least near the wellbore. The vertical contrast of CO2 injectivity and oil saturation change in the reservoir were confirmed by saturation logs and production logs. Clear increment of oil rate, reduction of water cut and oil composition change were observed after CO2 injection. Simulation study for matching pilot test performance was carried out and its result was in good agreement with the monitored data.
Towards a New Theory for Improved Oil Recovery from Sandstone Reservoirs
Authors: Sunde E. , Lillebø B.-L. , Torsvik T. 
Published: April 2012

Abstract
As discoveries of large new oilfields become a thing of the past, the residual oil in old oilfields becomes an increasingly important oil resource. Significant research and development efforts on increasing recovery have however yielded low results. We believe that the main reason for this is that the current models for how residual oil is trapped and mobilized are wrong. Several field observations have shown that mobilized residual oil moves more rapidly through the reservoir than the injected water assumed to be pushing it. This is not possible within the framework of current reservoir simulation models. We here present a new theory for the behaviour of residual oil in sandstone reservoirs.
Based on field cases and a laboratory study we argue that the residual oil is collected in continuous oil strands extending from injector to producer and blocked only by water in a pore close to the producer. The blocking water of that pore throat can be removed by applying a pressure pulse to the oil strand or by reducing the capillary force that makes the water adhere to the wall of the pore throat.
In a flooding experiment where the flow rate of oil and water was followed with oil and water soluble tracers, the results showed that oil moved 1000 times faster than the injection water through the core. Field observations involved oil fields, where analysis of H2S concentration at the producers showed that H2S had been transported with the oil and moved faster than the water through the reservoir. In an MEOR pilot increased oil production ceased almost immediately after the microbial activity was stopped, showing a continuous oil phase from injector to producer even under residual oil concentration.
Applying this new knowledge can considerably increase the recovery from most oil fields.
Advanced Screening Technologies for the Selection of Dense CO2 Foaming Surfactants
Authors: Chabert M. , Morvan M. , Nabzar L. 
Published: April 2012

Abstract
Injection of dense supercritical CO2 (sc-CO2) represents today more than half of the EOR projects carried out in USA. While sc-CO2 flooding is very effective in mobilizing trapped oil at the microscopic (pore-scale) level, this technology is usually limited by unfavorable mobility ratio and gravity segregation issues. In that context, use of dense CO2 foams (emulsions) may be one of the most robust methods for improving sc-CO2 flooding efficiency and maximizing oil recovery at reservoir scale. However, surfactant screening for dense CO2 foams has until now been extremely time consuming and limited to a few products due to strong technical constraints (high pressure equipments). Here, we report an original set of high throughput screening for optimizing dense CO2 foams formulations. The formulation yielding the best results is further characterized in corefloods experiments.
We use a proprietary high pressure jet-drop transition technique to screen interfacial properties of molecules at the dense CO2 / brine interface. The surfactants showing significant interfacial activities between aqueous solution and sc-CO2 are selected for the next steps. We use an autoclave to generate highly sheared foam with low cell sizes and study generated foam stability in a high pressure variable volume view cell. Structure/properties relationships are extracted from our numerous screening experiments and complement existing design rules for dense CO2 foam formulations.
A surfactant formulation yielding superior sc-CO2 foam stability is tested for mobility reduction in low-permeability carbonate cores. Using a CO2/aqueous solution co-injection scheme, we observe various flow regimes for different fractional flows. We confront these first results to the existing theories of foam flooding in porous media.
Experimental and Numerical Investigation on the Performance of Gas Oil Gravity Drainage at Different Miscibility Conditions
Authors: Ghasrodashti A. Ameri , Farajzadeh R. , Verlaan M. , Suicmez V. S. , Bruining J. 
Published: April 2012

Abstract
Gas oil gravity drainage is an effective oil recovery process, which has been proven in the field. Under favorable conditions the displacement is stable and for the right surface tension combinations the residual oil saturation is low. In the absence of gas dissolution, the recovery after gas injection is usually low as a large amount of oil remains capillary trapped in the matrix blocks. However, when the main gas constitutes is soluble in the oil, the dissolution leads to mixing and interfacial tension (IFT) reduction, which cause gravity enhanced transfer between matrix and fracture. Therefore, a study of the mechanisms that control the interactions between fracture and matrix (e.g. capillarity, gravity, phase behavior and flow behavior) can help to optimize recovery. This paper concerns an experimental study to investigate whether gravity drainage is also an effective recovery process in fractured reservoirs. In this study, we describe six gas injection experiments conducted at different miscibility conditions, i.e., immiscible, developed miscible and first contact miscible (FCM), using CO2, nitrogen and flue gas. In addition, the impact of switching from an immiscible (Nitrogen, Flue gas) injection gas to non-equilibrium and fully miscible CO2 injection is investigated. In one of the experiments, we study the effect of a permeability barrier on the recovery efficiency from the matrix block when CO2 is injected in the fracture at immiscible and miscible conditions. Accurate modeling for the transfer between fracture and matrix is also essential for accurate recovery predictions. In this study, a numerical model is developed to perform compositional simulations of gas injection for different miscibility scenarios. Results revealed that ultimate oil recovery increases considerably once miscibility is reached. Miscibility can usually be achieved at high pressures only. High pressure gas injection has two disadvantages, viz., (1) one may need a larger mass of gas to fill the pore space from where the oil is recovered and (2) the density of injected gas increases significantly, which reduces the density difference between the gas and oil. This leads to less effective gravity mediated recovery. Even if the impermeable layer impairs the performance of the gas oil gravity drainage (GOGD) process for immiscible gas injection, it improves the recoveries for first contact miscible gas injection.
Optimization of a Mature CO2 Flood — From Continuous Injection to WAG
Authors: Zhou Dengen , Yan Meisong , Calvin Wm. Marc 
Published: April 2012

Abstract
Although CO2 EOR is a well-accepted technology with 30+ years' field history, the optimization in its design and operation is historically constrained by the oil price – trying to minimize the cost especially when oil price is low. When we enter a high oil price regime, CO2 becomes a valuable commodity and its supply starts to limit the flood operation and design.
This paper will first review the industrial practice of CO2 design and optimization and the current status of CO2 projects within Chevron. We then focus on a case study to demonstrate the impact of reservoir heterogeneity on flood design. The field was originally designed as crestal gravity stable CO2 injection based on the excellent water flood performance. Good initial oil response was observed but followed by high gas recycling and complicated operational issues. The simulation study suggests that the existence of high permeability, vertical conduits causes the CO2 flow rates in the reservoir significantly higher than the critical gravity-stable flow rate resulting in high gas recycling. Therefore balancing recovery efficiency and project economics is a challenge for gravity stable injection design. A tapered WAG design is proposed to improve operational flexibility and recovery efficiency in this mature field. The case study also demonstrates that it is critical to include proper characterization of flow barriers and channels for a successful CO2 flood design.
Oil Recovery by Sequential Waterflooding: the Effects of Aging at Residual Oil and Initial Water Saturation
Authors: Loahardjo Nina , Xie Xina (Sheena) , Winoto Winoto , Buckley Jill , Morrow Norman R. 
Published: April 2012

Abstract
Sequential waterflooding refers to cycles of flooding for which initial water saturation is re-established after a waterflood by flow of crude oil followed by further waterflooding. In previously reported examples of sequential waterflooding, cores were neither cleaned nor re-aged at high crude oil saturation between floods. Numerous core floods with different rock types showed significant decrease in residual oil saturation from one flood to the next (Loahardjo et al. 2010a). Systematic decrease in residual oil saturation by sequential waterflooding was confirmed by nuclear magnetic resonance imaging measurements of in-situ saturations (Loahardjo et al. 2010b).
In this work, sequential waterflooding has been demonstrated for outcrop Berea sandstones of medium and low permeability: both showed reduction in residual oil saturation with each sequential flood. The tests have been extended to include aging periods at either residual oil saturation or initial water saturation. Aging at residual oil saturation (high water saturation) resulted in an increase in oil recovery for the subsequent flood, with larger increases observed for extended aging times. After an extended period of aging at initial water saturation (high oil saturation), decreased oil recovery was observed. The variations in oil recovery are consistent with changes in wettability that depend on oil saturation during displacement and subsequent aging conditions.
Fundamental investigations into wettability and low salinity flooding by parameter isolation
Authors: Suijkerbuijk B. M. , Hofman J. P. , Ligthelm D. J. , Romanuka J. , Brussee N. , van derLinde H. A. , Marcelis A. H. 
Published: April 2012

Abstract
Improved oil recovery by low salinity waterflooding (LSF) represents an attractive emerging oil recovery technology, as it is relatively easy to implement and low-cost compared to other Improved and Enhanced Oil Recovery (IOR and EOR, respectively) processes. Even though LSF leads to extra oil recovery in most laboratory experiments and some promising data from the field have been presented, the mechanism underlying LSF is still unclear. Therefore it is difficult to predict a favorable performance of LSF in one field a priori, while dismissing others.
This paper describes a series of spontaneous imbibition experiments on Berea outcrop core plugs, and some reservoir rock core plugs, that were designed to determine the impact of formation water, imbibing water and crude oil composition on wettability and on wettability modification by LSF. The data presented in this paper lead us to conclude that: Spontaneous imbibition experiments with formation brine and low salinity brine executed on Berea outcrop material aged with a crude oil show excellent reproducibility;An increasing concentration of divalent cations in the formation brine makes a Crude Oil/Brine/Rock system more oil-wet;The extent of wettability modification towards more oil-wet upon aging also depends on the types of cations in the formation brine;Improved oil recovery by exposure of the aged plugs to NaCl brines occurred when the imbibing phase was either higher or lower in salinity than the formation brine;Aging of the same brine/rock system with different crudes having diverse physico-chemical properties led to:○A spread in wettabilities after aging○A crude oil-dependent low salinity effect
These results are discussed within the context of several mechanisms that have been put forward previously as an explanation for the low salinity effect.
Secondary and Tertiary Recovery of Crude Oil from Outcrop and Reservoir Rocks by Low Salinity Waterflooding
Authors: Winoto Winoto , Loahardjo Nina , Xie Xina (Sheena) , Yin Peigui , Morrow Norman R. 
Published: April 2012

Abstract
A wide range of outcrop sandstones and carbonates have been tested for waterflood response to one twentieth dilution of synthetic seawater, using a single crude oil that gave high response to low salinity flooding for a reservoir rock. The tested outcrop rocks included 17 sandstones and 6 carbonates. Gas permeabilities ranged from 1.49 to 7,187 mD and porosities from 10 to 39%. The average reduction in residual oil for tertiary response was only 1.5% OOIP with the highest being 5.8% OOIP; some rocks showed no response. After testing, three of the outcrop rocks that responded to injection of low salinity brine were restored by cleaning and re-aging with crude oil using procedures comparable to those commonly used in restoration of reservoir cores. When re-tested, the response to low salinity flooding was eliminated for two of the cores and significantly reduced for the third core. Companion plugs for 6 of the sandstones and 3 carbonates were tested for increased oil recovery using low salinity connate and injected brine; this data provided comparison with the measurements for high salinity connate and injection brine. Six of the plugs showed increase in recovery for the low salinity waterfloods, and three showed decrease. Results are also summarized for the effects of reduction in salinity for 11 sandstone cores taken from five reservoirs and 8 carbonate cores all taken from the same reservoir. Comparison between results for outcrop and reservoir cores, including literature data, indicates that overall response to low salinity flooding is significantly higher for the reservoir cores.