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Foam injection contributes to improved oil recovery through flow diversion, reduction of interfacial tension (IFT), and wettability alteration of the rock while its stability is an issue. In this article, nitrogen‐foam was optimally formulated using fluorocarbon tubiguard protect (FTP) surfactant stabilized with sodium dodecyl sulfate (SDS) co‐surfactant that was later experimentally considered for oil recovery in a fractured carbonate rock taken from an oil field in the Middle East. The results showed that the 5:1 volume ratio of fluorocarbon surfactant and SDS (FS51) generates a stable foaming agent with ability of changing the wettability of the carbonate rock surfaces to an intermediate gas‐wet state. A series of core‐flood experiments at HPHT conditions were also carried out and designed to properly represent matrix‐fracture media using both a horizontally and vertically oriented setup. The oil saturated cores were flooded with nitrogen gas first followed by foam injection. It was concluded that foam can divert the gas to flow from fractures to the matrix blocks and result in a significant oil recovery. The contact angle tests that performed after core‐flood experiments revealed the wettability changes of fracture surfaces from an oil‐wet to a gas‐wet state. This allows gas to be imbibed into the matrix blocks by capillary force and results in enhancement of ultimate oil recovery. This study revealed that trapped oil in matrixes blocks that had not been drained during the gas injection process could be produced by designing a stable foam that sustainably diverts injected fluid from fractures to matrix zone. [ABSTRACT FROM AUTHOR]

Enhanced oil recovery (EOR) technology has gained a lot of attention during last decades. Declining oil production from brown fields is a major concern for oil companies. One of these mature fields is the X field, a carbonate oilfield in the Middle East, discovered in 1908. In this study, in addition to considering an EOR plan for the X field, it is aimed to investigate the effect of rock wettability on recovery process by means of two reported wettability data sets of the X field. Results of EORgui software show a sensitive dependence of oil recovery on initial rock wettability. Results of a laboratory chemical coreflooding experiment on the field core samples have been also included in the study. [ABSTRACT FROM AUTHOR]

Most oil fields today are mature, and the majority of the reservoirs in the Middle East are carbonate rocks characterized by high temperature high salinity (HTHS), heterogeneous mineral composition, and natural fractures. Enhanced oil recovery (EOR) methods are used for boosting oil recovery from the aged reservoirs beyond primary and secondary recovery stages. Nevertheless, it can be a challenging task to employ EOR techniques in these aged carbonate reservoirs. This is because carbonate reservoirs have mixed-to-oil-wet wettability with temperatures exceeding 85 °C and salinity of over 100,000 ppm, which renders secondary EOR-methods such as waterflooding ineffective. Therefore, even though carbonate reservoirs contain 60–65% of world's remaining oil, with immense intrinsic economic prospects, the oil recovery process from carbonate reservoirs remains a considerable challenge. Chemical-EOR (cEOR) techniques, like SP based cEOR, have shown marked promise in improved oil recovery, mainly from clastic reservoirs with medium temperature and salinity, unlike carbonate reservoirs. During SP-floodings, the surfactants get adsorbed due to the mineral composition of the carbonate rocks, and polymer degradation occurs due to HTHS conditions. Consequently, new surfactants and polymers have been structurally conformed and tested to improve their robustness and related recovery efficacy. For instance, Guerbet alkoxy-carboxylate surfactants demonstrated good stability at temperatures over 100 °C and salinities up-to 275,000 ppm, yielding tertiary recovery of 94.5% and low adsorption of 0.086 mg/g of rock. The cationic Gemini surfactants, zwitterionic or amphoteric class of surfactants are also suitable for HTHS carbonates. Besides, effective biosurfactants sourced from plant such as, soy, corn, etc., are non-toxic and readily biodegradable. The hydrophobically associating polyacrylamide (HAPAM) and its modified nanocomposite derivative can act as replacement surfactants, due to their wettability altering and robust characteristics. Novel polymers viz., NVP-based, novel smart thermoviscosifying polymers (TVP), soft microgel, and sulfonated polymers, are also relevant to HTHS carbonate applications. Xanthan gum, scleroglucan, and schizophyllan biopolymers have been noted to resist HTHS and low permeability conditions, requiring lower concentration and having low adsorption. Recent surfactant-polymer (SP) formulations also can be applicable for HTHS carbonates with excellent ternary recoveries (93.6%) and minimal retention (0.083 μg/g of rock). Such low retention values suggest low surfactants cost with minimal environmental impact. Moreover, several successful field applications in carbonates were conducted in preceding years; however, the performance of some novel surfactants under HTHS carbonates is yet to be fully understood. Hence, this comprehensive review aims to provide renewed perspectives on surfactant and polymer optimizations for field applications in HTHS carbonates. A list of recommendations is presented as guidelines for efficient SP-flooding designs. This critical literature appraisal furnishes an array of potential manifestations for successful field application of SP-flooding in HTHS carbonates, which holds both economic and environmental feasibility. [Display omitted] [ABSTRACT FROM AUTHOR]

Most oil fields today are mature, and the majority of the reservoirs in the Middle East are carbonate rocks characterized by high temperature high salinity (HTHS), heterogeneous mineral composition, and natural fractures. Enhanced oil recovery (EOR) methods are used for boosting oil recovery from the aged reservoirs beyond primary and secondary recovery stages. Nevertheless, it can be a challenging task to employ EOR techniques in these aged carbonate reservoirs. This is because carbonate reservoirs have mixed-to-oil-wet wettability with temperatures exceeding 85 °C and salinity of over 100,000 ppm, which renders secondary EOR-methods such as waterflooding ineffective. Therefore, even though carbonate reservoirs contain 60–65% of world's remaining oil, with immense intrinsic economic prospects, the oil recovery process from carbonate reservoirs remains a considerable challenge. Chemical-EOR (cEOR) techniques, like SP based cEOR, have shown marked promise in improved oil recovery, mainly from clastic reservoirs with medium temperature and salinity, unlike carbonate reservoirs. During SP-floodings, the surfactants get adsorbed due to the mineral composition of the carbonate rocks, and polymer degradation occurs due to HTHS conditions. Consequently, new surfactants and polymers have been structurally conformed and tested to improve their robustness and related recovery efficacy. For instance, Guerbet alkoxy-carboxylate surfactants demonstrated good stability at temperatures over 100 °C and salinities up-to 275,000 ppm, yielding tertiary recovery of 94.5% and low adsorption of 0.086 mg/g of rock. The cationic Gemini surfactants, zwitterionic or amphoteric class of surfactants are also suitable for HTHS carbonates. Besides, effective biosurfactants sourced from plant such as, soy, corn, etc., are non-toxic and readily biodegradable. The hydrophobically associating polyacrylamide (HAPAM) and its modified nanocomposite derivative can act as replacement surfactants, due to their wettability altering and robust characteristics. Novel polymers viz., NVP-based, novel smart thermoviscosifying polymers (TVP), soft microgel, and sulfonated polymers, are also relevant to HTHS carbonate applications. Xanthan gum, scleroglucan, and schizophyllan biopolymers have been noted to resist HTHS and low permeability conditions, requiring lower concentration and having low adsorption. Recent surfactant-polymer (SP) formulations also can be applicable for HTHS carbonates with excellent ternary recoveries (93.6%) and minimal retention (0.083 μg/g of rock). Such low retention values suggest low surfactants cost with minimal environmental impact. Moreover, several successful field applications in carbonates were conducted in preceding years; however, the performance of some novel surfactants under HTHS carbonates is yet to be fully understood. Hence, this comprehensive review aims to provide renewed perspectives on surfactant and polymer optimizations for field applications in HTHS carbonates. A list of recommendations is presented as guidelines for efficient SP-flooding designs. This critical literature appraisal furnishes an array of potential manifestations for successful field application of SP-flooding in HTHS carbonates, which holds both economic and environmental feasibility. [Display omitted] [ABSTRACT FROM AUTHOR]

[Display omitted] • Hybrid low salinity surfactant flooding is studied as a chemical EOR method. • Oil/brine and rock/brine interfaces and the role of salinity are investigated. • Contact angle, zeta potentials of both interfaces, pH and IFT were mesured. • Micromodel tests were performed in oil-wet fractured porous media. • There exists an optimum value of salinity for the best surfactant performance. Wettability alteration of the porous medium from oil-wet (OW) to neutral-wet or even water-wet (WW) is proposed as one of the main mechanisms behind the enhanced oil recovery (EOR) by the Low Salinity Water Flooding (LSWF). However, our recent studies for a specific crude-oil/brine/rock of the oil reservoir in the Middle East, shows that LSW (diluted sea water) is not that much effective, neither to change the wettability of the surface nor to significantly increase the oil recovery factor. This obstacle becomes more challenging when we deal with fractured formations, where the imbibition of injected fluid from fracture into matrix and its propagation within the matrix, is the main macroscopic mechanism of the EOR. Chemical EOR, in which the chemical additive is added to the injecting brine, is one of the hybrid techniques which can boost oil recovery in such cases. In this study, CTAB as a cationic surfactant was added to brine solutions with different ionic strengths (i.e., sea water (SW), 10 times diluted sea water (10dSW) and 2 times concentrated sea water (2cSW)). Contact angle, zeta potential of both fluid/fluid and fluid/rock surfaces, and IFT tests were conducted to shed insight on interactions in crude oil/brine and rock/brine interfaces and the role of ionic strength. Finally, dynamic micromodel tests were performed in oil-wet fractured porous media to observe the impact of the added surfactant along with different ionic strength on displacement mechanisms and oil recovery. Experimental results show that neither electrical double layer expansion nor multiple ion exchange mechanisms cannot justify the observed detachment of oil droplets from the oil-wet substrates in the presence of the CTAB. Surfactant are absorbed on the oil/brine interface by the embedment of their hydrophobic tails in oil. Both surfactant molecules and the non-polar oil components (that are attracted to hydrophobic tail of surfactant molecules), are attracted to the solution via the hydrophilic parts of the surfactants. The effectiveness of this mechanism is dependent on both the concentration of the surfactant and concentration of the ions in brine. In the case that the aforementioned mechanism is adequately dominant and effective, the small droplets of oil will be detached from continuous oil bulk, resulting in oil to be broken to smaller droplets which enhances the detachment of the oil bulk from oil-wet substrates. This fluid/fluid interaction mechanism also promotes the imbibition of the aqueous phase into the matrix and also its propagation within the matrix. [ABSTRACT FROM AUTHOR]

The remaining oil distribution plays an important role in enhanced oil recovery (EOR), which directly guides the development of an oil reservoir in the middle and later stages. However, it is still challenging to accurately and efficiently characterize the distribution of remaining oil due to the complex reservoir geology. We propose a data-driven physics-informed interpolation evolution algorithm combining historical-predicted knowledge (DPIE-HPK) for the prediction of remaining oil distribution totally based on reservoir monitoring data. As a key step towards the remaining oil distribution, the production rates can be predicted as well. A physics-informed data supplement (PIDS) process is also presented to assist the DPIE-HPK algorithm. Both historical physics information and future information are used in the DPIE-HPK framework. The historical physical information is preprocessed by the PIDS, and future information is predicted by Long Short-Term Memory (LSTM) deep learning models. As a crucial interpolation evolution method, the Kriging method is also integrated into the framework to evolve the unknown spatial information. We test the DPIE-HPK framework for the prediction of the remaining oil distribution of a typical tight carbonate oil reservoir located in the Middle East. It is concluded that the DPIE-HPK framework is a fast, accurate and efficient intelligence tool for predicting the remaining oil distribution. • We establish a PIDS process to supplement the missing reservoir data including historical remaining oil distribution. • We develop a DPIE-HPK framework to predict the remaining oil distribution totally based on reservoir monitoring data. • The PIDS and DPIE-HPK are successfully applied to a typical tight carbonate oil reservoir. [ABSTRACT FROM AUTHOR]

An integrated full-field reservoir simulation study has been performed to determine the reservoir management and production strategies in a mature sandstone reservoir. The reservoir is a candidate for an enhanced oil recovery process or otherwise subject to abandonment. Based on its charateristics, the reservoir was found to be most suited for a surfactant/polymer (SP) flood. The study started with a large data gathering and the building of a full-field three-dimensional geological model. Subsequently, a full field simulation model was built and used to history match the water flood. The history match of the water flood emphasizes the areas with remaining high oil saturations, establishes the initial condition of the reservoir for an SP flood, and generates a forecast of reserves for continued water flood operations. A sector model was constructed from the full field model and then used to study different design parameters to maximize the project profitability from the SP flood. An economic model, based on the estimated recovery, residual oil in-place, oil price, and operating costs, has been implemented in order to optimize the project profitability. The study resulted in the selection of surfactant and polymer concentrations and slug size that yielded the best economic returns when applied in this reservoir. The study shows that, in today's oil prices, surfactant/polymer flood when applied in this reservoir has increased the ultimate oil recovery and provide a significant financial returns. [ABSTRACT FROM AUTHOR]

Fractured moderate oil-wet carbonate reservoirs are the main productive formations in the Middle East. The change in wettability state toward water wetness beside interfacial tension (IFT) reduction is one of the potential scenarios for more oil recovery process. Smart water and natural surfactant injection into the porous media will alter the rock wettability and reduce IFT which consequently results in more oil sweep from untouched pores. In this paper, a novel natural surfactant (Alfalfa species) is introduced for EOR applications. IFT and contact angle tests were carried out between the oil phase, rock surface, Alfalfa natural surfactant, and surfactant—ion hybrid aqueous solutions. The results of Alfalfa natural surfactant showed a 29.29 mN/m reduction of IFT (63.39% IFT optimization) at the concentration of 4 wt% as the critical micelle concentration (CMC). Also, after addition of Alfalfa the wettability of rock tends to be more water-wet from the initial oil-wet state by application of Alfalfa because of 86.84° reduction of contact angle (49.91% wettability alteration). Solutions of calcium, magnesium, and sulfate ions were prepared as modified synthetic seawater at CMC of Alfalfa natural surfactant to investigate their synergistic influences on intensifying the optimizations of IFT and wettability alteration as hybrid solutions. IFT measurements of the hybrids demonstrated that among mentioned ions calcium brings the best results as it showed good synergistic effects with mentioned non-ionic natural surfactant in advancing the optimization of IFT reduction from 63.39 (surfactant solution) to 71.0 (surfactant—ion hybrid solution) percent. Also, contact angle measurements of the hybrids demonstrated that calcium ions gain the best results and advance the contact angle optimization from 49.91 (surfactant solution) to 61.8 (surfactant—ion hybrid solution) percent. Therefore, the solution of 3 times Ca concentrated seawater + CMC of surfactant selected to conduct imbibition tests as a displacement experiment based on the hybrid results and the candidate solution caused a 19.2% increase in oil recovery factor regarding seawater flooding and a total oil recovery factor of 62%. • Optimization of IFT and wettability conditions by application of Alfalfa species as a natural surfactant for chemical EOR • Enhancement of the mentioned optimizations by addition of smart ions to natural surfactant solutions • Synergistic effects of Alfalfa natural surfactant and Smart water • Improvement of oil recovery factor by introducing the optimum hybrid solution at reservoir temperature [ABSTRACT FROM AUTHOR]

Oil recovery from carbonate reservoirs is low because of their complex nature which is characterized by the presence of high permeability streaks/fractures, broad pore size distribution and oil-wet/mixed wet state. The presence of high permeability streaks/fractures causes the injected fluid to bypass the low permeability pores that contain a high percentage of producible oil. One of the most effective and promising methods to control the fluid bypass is fluid diversion using chemical agents where a chemical agent is placed in the high permeability zone to block the path for the subsequent fluid, which ultimately diverts the injected fluids to the less permeable and oil-containing region. In this work, we investigate the potential use of cellulosic nanocrystals (CNC) for fluid diversion applications. Upon contact with brine, the nanosized CNC particles agglomerate to form micron size flocs showing a viscosity increment of an order at reservoir shear rates. In our core flooding experiments, the permeability of carbonate core decreased from 2827 mD to 127 mD when a CNC dispersion of 3000 ppm was injected. Injection of pre-equilibrated de-ionized water following CNC injection showed that the permeability reduction is permanent signifying the stability of CNC agglomerates in high temperature-high salinity environments. The blocking of high permeability zones due to the agglomeration of CNC particles results in fluid diversion. This improves the sweep efficiency and allows the injected fluid to come in contact with the oil. This is the first application of CNC in the area of fluid diversion for high temperature and high salinity fractured carbonate reservoirs which are present in the Middle East. [ABSTRACT FROM AUTHOR]