Primary Recovery Research Articles

DETERMINATION OF OIL RECOVERY FACTOR BY USING WATER INJECTION-LABORATORY TEST METHOD

Oil production limit that is usually followed by decrease of oil productivity in old fields is a major problem and can't be avoided. This case happened when cumulative oil production has approached primary recovery method. Decrease of the action of native reservoir energy is followed by drastically increase of production of water (saturation almost 100 %). In relation to this, a method is needed to obtain the additional oil recovery. Water injection method is one of the solutions to solve oil production problem that happened in old fields. It is expected that by using water injection method, productivity and oil recovery in old fields can be improved. Water that is used as the fluid injected into reservoir to improve oil recovery is sea water. How far oil recovery can be improved by using water injection method, is determined by a laboratory research. Before carrying out water injection laboratory test; one has to know what the main points that play important role in determining the optimal oil recovery by water injection method. These are: firstly, reservoir data, secondly, formation water and sea water analysis, thirdly, determination of physical fluid and rock properties, next, the displacement of water injection process to obtain the additional oil recovery and standard operational procedure. The main focus of this paper is "Determination of Oil Recovery Factor By Using Water Injection-Laboratory Test Method ". Hopefully, the contents of this paper give extremely valuable and useful information not only for LEMIGAS as Research and Development Centre for Oil and Gas Technology, but also for the oil industry or the Department of Petroleum Engineering of the universities in Indonesia.

It’s what you say and what you buy: A holistic evaluation of the corporate credit facilities

We evaluate the impact of the Federal Reserve corporate credit facilities (PMCCF and SMCCF) on corporate bond markets. Conditions in primary markets improve once the facilities are announced, particularly for issuers that need to refinance before 2022. Issuance accelerates before spreads normalize. The secondary market points to a causal role for the facilities, with a differential impact on eligible issues and a significant effect of direct bond purchases, but less so for purchases through ETFs. We find evidence that dealers link the primary and secondary market recovery, with facilities affecting dealer willing to underwrite issuances and intermediate in secondary markets.

Parameter Optimization of Asynchronous Cyclic Waterflooding for Horizontal-Vertical Well Patterns in Tight Oil Reservoirs.

Tight oil resources in China are mainly exploited by staged-fractured horizontal wells; horizontal wells face the problems of the rapid decline rate and low primary oil recovery. Pilot tests on the asynchronous cyclic waterflooding for the horizontal–vertical well pattern were carried out in recent years and achieved good performance. However, there are few studies on the influencing factors and parameter optimization of asynchronous cyclic waterflooding, which limits its wide application. This work took the tight oil reservoir in Yanchang formation, Fuxian area, Ordos Basin as its object, and the oil recovery mechanisms of asynchronous cyclic waterflooding for the horizontal–vertical well pattern were analyzed first. Then, the operation parameters of asynchronous cyclic waterflooding were optimized by the numerical simulation method. Among them, the injection proportion was optimized by the fuzzy synthetic evaluation method. Finally, the oilfield test was carried out based on the optimized parameters. The results showed that pressure disturbance and streamline deviation are the main oil recovery mechanisms of asynchronous cyclic waterflooding. The asynchronous mode of the diagonal well row is better than other asynchronous modes. For the injection time interval, injection–production ratio, and the injection and shut-in time, the cumulative oil production all show the trend of increasing first and then decreasing with the increase in these parameters. The optimal injection time interval and injection–production ratio are 0.5 T and 1, respectively. The optimal injection and shut-in time can be calculated by empirical formulas. Ultimately, the fuzzy synthetic evaluation model was established to optimize the injection proportion. Field practices showed that the average daily oil production of horizontal wells was increased from 1.7 to 3.0 m3 with the optimized parameters, which further verified the accuracy of the optimized parameters. This research can provide theoretical support for the effective development of tight oil reservoirs.

Production data-based facies analysis for well placement in thin-layered reservoir

The exploitation of a thin-layered reservoir with thickness less than 5 m (16 ft) needs to rely upon sedimentary facies analysis, due to the low resolution of seismic data and sparse well data. However, the ambiguity of facies interpretation creates uncertainty in facies and reservoir mapping. The study aims to better define facies distribution, predict sand-body architecture, and consequently reduce risks in planning development wells, by integrating production data (dynamic) with conceptual geological models (static). An example is shown from the M1 Member of the Napo Formation in the B and G Oilfields (Block J), Oriente Basin, Ecuador. The M1 reservoir is a thin-layered sandstone reservoir below seismic resolution. Core and well-log facies interpretation indicates depositional facies of a tide-dominated estuary. Production data during the water injection phase of field development can delineate the detailed geometry of the sand bodies. The injector-producer rate responses can determine the connectivity of sand bodies. Well performance during primary recovery can capture the scale of single reservoirs because the initial production rates and the cumulative oil production of individual wells are generally proportional to the size of sand bodies. A facies model was thereby generated. Two step-out wells were planned using this model and drilled successfully. The results demonstrate that the integration of dynamic and static data is critical to understanding reservoir facies distribution.

Reservoir Simulator For Improved Recovery Of Coalbed Methane (Icbm) Part Ii : Effect Of Coal Matrix Swelling And Shrinkage

Sequestration of CO2 in deep unmined coal seams is currently under development for improved recovery of coalbed methane (ICBM) as well as permanent storage of CO2. Recent studies have shown that CO2 displaces methane by adsorbing more readily onto the coal matrix compared to other greenhouse gases, and could therefore contribute towards reducing global warming. In order to carry out a more accurate assessment of the potential of ICBM and CO2 sequestration, field based numerical simulations are required. Existing simulators for primary CBM (coalbed methane) recovery cannot be applied since the process of CO2 injection in partially desorbed coalbeds is highly complex and not fully understood. The principal challenges encountered in numerical modelling of ICBM/CO2 sequestration processes which need to be solved include: (1) two-phase flow, (2) multiple gas components, (3) impact of coal matrix swelling and shrinkage on permeability, and (4) mixed gas sorption. This part II of this two-part paper series describes the development of a compositional simulator with the impact of matrix shrinkage/swelling on the production performance on primary and echanced recovery of coalbed methane. The numerical results for enhanced recovery indicate that matrix swelling associated with CO2 injection could results in more than an order of magnitude reduction in formation permeability around the injection well, hence prompt decline in well injectivity. The model prediction of the decline in well injectivity is consistent with the reported field observations in San Juan Basin USA. Also, a parametric study is conducted using this simulator to investigate the effects of coal properties on the enhancement of methane production efficiency based on published data.

Numerical Evaluation of a Novel Slot-Drill Enhanced Oil Recovery Technology for Tight Rocks

Summary Enhanced oil recovery (EOR) is essential in shale/tight formations because primary recovery typically produces less than 10% of the original hydrocarbon in place. This work presents a novel “slot-drill” EOR (SDEOR) technology, which involves injecting gas through a horizontal fracture that is cut into the formation near the top of the reservoir (using a tensioned abrasive cable mounted to the drillstring) and producing oil from a second slot-drilled horizontal fracture near the bottom of the reservoir. A robust 3D projection-based embedded discrete fracture model (pEDFM; EDFM) is used to model the natural fractures in these slot-drilled unconventional oil reservoirs accurately and efficiently. Connectivity and uncertainty analyses are performed to determine the percolation threshold, where natural fractures influence hydrocarbon production appreciably. The results of this work indicate that the proposed technology can yield over a threefold increase in oil recovery relative to the cyclic gas EOR (CGEOR) method. This simulated recovery is high regardless of the presence of natural fractures or the type of gas/solvent injected (such as CH4, N2, CO2, and flue gas). The simulation results also indicate that the continuous gas injection, higher relative oil permeability, and the role of gravity-drainage are the main reasons why the oil recovery from the SDEOR is three times that from the CGEOR method. In conclusion, this is the first presentation and numerical simulation study of applying pairs of parallel slot-drilled fractures to enhance the recovery from challenging unconventional reservoirs (such as the Bakken shale) that have not been successfully enhanced using the CGEOR method. The dramatic increase in recovery from SDEOR, coupled with its applicability regardless of the stress state or formation brittleness, could change how unconventional reservoirs are completed and produced in the future.

Preliminary Carbon Untilization And Storage Screening Of Oil Fields In South Sumatra Basin

Carbon utilization in oil fi elds as EOR project has becomes main issue nowdays. Therefore preliminary CO2-EOR screening has been done for the oil fi elds laid on South Sumatra Basin, where CO2 emission arise from a number different sources of activities in South Sumatra area. Around 103 oil fi elds and consisting 581 reservoirs have been analysis to select which of those fi elds fulfi ll CO2 injection criteria. The criteria applied of the selection are based on EOR Screening Criteria Revisited papers introducing by J.J Taber at. All. 1977. The results of the screening are categorized as miscible, immiscible and failed for CO2 injection. Afterward, CO2 storage and incremental oil recovery due to CO2 injection were calculated using equation normally used in the oil industries. The incremental oil recovery due to CO2-EOR has been assumed as high as 12% of OOIP at miscible process and only 5% for immiscible displacement. The calculation of CO2 storage is based on the ultimate primary recovery for each fi eld in addition of the additional recovery due to CO2-EOR. Both primary and tertiary recovery have been used as the basic of calculating the CO2 storage. The results of the screening whether reservoir categories in immiscible, miscible injection and failed to fulfi ll EOR-CO2 injection criteria can be summarized as follow: 18 fi elds immiscible, 77 miscible, and 7 failed. Total incremental oil recovery estimate from CO2-EOR is approximately 480.5 MMSTB. While the total CO2 storages estimate are about 70 MMton for voidage replacement due to production at ultimate recovery and 22 MMton at EOR-recovery, so the total CO2 storage is approximately 92 MMton.

Triceps to teres minor motor nerve transfer to restore glenohumeral external rotation after neonatal brachial plexus injury.

Attaining active glenohumeral external rotation (aGHER), whether via primary reconstruction or spontaneous recovery, is infrequent in patients with neonatal brachial plexus palsy (NBPI). We evaluated the effectiveness of triceps-to-teres minor motor branch transfers to restore this function, both performed primarily (i.e., in conjunction with microsurgical plexus reconstruction) or secondarily (after primary surgery has failed to restore aGHER). This was a retrospective study of 12 children with NBPI undergoing triceps-to-teres minor motor branch transfer via an axillary approach, six undergoing primary surgery and six secondary. The primary outcome was post-operative restoration of aGHER in abduction. The primary-surgery group consisted of six children of mean age 8 months (range 5-11) with partial injuries ranging from C5-C6 to C5-C8. The secondary-surgery group included six patients with C5-C6 injuries of mean age 43 months (range 23-120), undergoing re-operation a mean 40 months (range 18-116) after their primary surgery. No complications occurred after surgery. At a mean follow-up of 22 months (range 14-30), aGHER in abduction only was restored in one patient in the primary group while in the secondary group, aGHER in abduction was restored in all patients to a mean 73° (range 70-80) after a mean follow-up of 16 months (range 6-26). Triceps-to-teres minor motor branch transfer is not indicated as primary surgery for NBPI. However, they can be effective in children in whom primary surgery has failed to restore aGHER, even if the spinal accessory nerve is unavailable for transfer to the infraspinatus motor branch.

Effect of compaction and imbibition on benefits of drawdown management in shale oil production: Uncertainty in recovery driving mechanisms

Economic production from shale oil reservoirs relies on the longevity of conductive fractures. Choke or drawdown management is believed to better preserve the fracture conductivity during the early life of the wells, which thus potentially leads to higher ultimate oil recovery. However, there is no strong consensus among the previous literature as to whether choke management can offer incremental oil recovery in the long term. Even if it can, the mechanism is not well understood, and the economic benefit can be challenged, because the choke management slows down the early oil production, which is worth the most in terms of Net Present Value (NPV). In this study, a series of coupled flow-geomechanical numerical simulations is performed to examine the effect of choke management on the ultimate oil recovery and NPV. We built multiple reservoir realization models, each of which is validated based on the same field production data from Middle Bakken shale-oil reservoirs to perform probabilistic production forecasts. The different reservoir realization models are built to assess the uncertainty in the Stimulated Reservoir Volume parameters, including natural fracture spacing, water saturation in the matrix and fracture, and formation compressibility. The different reservoir parameters lead to each model having different primary recovery driving mechanisms of oil recovery, including imbibition and compaction drive. This study quantitatively demonstrates that the choke management seems to increase both the ultimate oil recovery and NPV if the oil recovery is strongly driven by imbibition. A mechanistic discussion for this claim is presented.

STUDY OF ENHANCED OIL RECOVERY WITH ALKALINE SURFACTANT POLYMER INJECTION METHOD BY USING LABORATORY TEST

One effort to improve oil recovery in oil reservoirs after primary and secondary recovery period is to apply the method of Enhanced Oil Recovery (EOR). Screening of EOR on the characteristics of the reservoir rock and Àuid 'N' indicates that the suitable method is the injection of alkali surfactant polymer (ASP). This paper presents the results of laboratory tests to increase the oil recovery in the reservoir 'N' with ASP injection. The purpose of the laboratory testing was to determine the additional oil recovery by injecting a solution of ASP in the reservoir rock 'N'. Based on the results of compatibility, interfacial tension, rheology, thermal stability, filtration and static adsorption test on an ASP Àuid injection, the optimum concentration of each of the injection Àuid is obtained. Referring to the optimum concentration of the ASP, then the core Àooding test design based on a predetermined Àuid injection. The main result of the Àooding test cores showed an increase in oil recovery as much as 21.84% OOIP. When the results of the laboratory test was applied to the field scale by injecting Àuid into the reservoir ASP 'N', then the estimated potential increase in oil production as much as 11.457 million bbl.

Development of artificial neural network models to calculate the areal sweep efficiency for direct line, staggered line drive, five-spot, and nine-spot injection patterns

The overall efficiency of the oil displacement processes, and the amount of oil produced after the primary recovery depend on areal (EA), vertical (EV), and displacement (ED) sweep efficiency. There are many correlations and graphical charts that are used to calculate EA, EV, and ED with variable degrees of deviation. This research focuses on calculating the areal sweep efficiency (EA) at and after water breakthrough for direct and staggered line drive patterns, also for five and nine-spot injection patterns by using artificial neural network models (ANN) and comparing them with the previous techniques. In addition to establishing a new ANN model for calculating EA for the nine–spot injection pattern, as there is no current model to calculate it. The results showed that the four proposed models achieve high coefficients of determination (R2) of (0.9995, 0.9996, 0.9996, and 0.997) and low root mean square error (RMSE) of (0.0038, 0.0023, 0.0026, and 0.0034) for a direct line drive, staggered line drive, five-spot, and nine-spot injection patterns respectively. These new models are presented to provide a more accurate calculation of the amount of oil produced by waterflooding.

Experimental investigation on the influence factors of primary production performance of tight oil

The effects of permeability, initial fluid pressure, effective stress, gas-oil ratio, pressure depletion rate, and oil viscosity on the primary production oil recovery were investigated in detail. The results show that the permeability of tight core is the most significant influence factor. When the permeability decreases from 3.0 × 10−3 µm2 to 0.0021 × 10−3 µm2, the oil and gas recoveries decrease from 45% and 90% to 10% and 20%. Furthermore, the initial fluid pressure also has great influence and the oil recovery linearly increases with the fluid pressure as well as the decrease of effective stress. When the initial fluid pressure increases from 6 MPa to 15 MPa, the oil and gas recoveries can be enhanced about 10% and 22%. Gas-oil ratio is another important parameter. When the gas-oil ratio is 26 m3⋅m−3, the oil recovery can reach approximately 30% compared to 2.7% at the gas-oil ratio of 0. The pressure depletion rate has a more obvious influence on the ultimate oil recovery for the cores with a low permeability, while with a low depletion rate after bubble point can enhance the oil recovery. The work can provide useful information for the choosing of key parameter and development method in tight oil production.

Lithium chloride-induced primary cilia recovery enhances biosynthetic response of chondrocytes to mechanical stimulation

Mechanical stimulation is commonly used in cartilage tissue engineering for enhancing tissue formation and improving the mechanical properties of resulting engineered tissues. However, expanded chondrocytes tend to dedifferentiate and lose expression of their primary cilia, which is necessary for chondrocyte mechanotransduction. As treatment with lithium chloride (LiCl) can restore passaged chondrocytes in monolayer, in this study, we investigated whether this approach would be effective in 3D culture and restore chondrocyte mechanosensitivity. Chondrocytes at different passages (P0 to P2) were treated with 0-50mM LiCl for 24h, with different pre-culture durations (0 to 4days). The primary cilia incidence and length were measured in α-tubulin-stained images. Treated chondrocytes were cultured with or without dynamic compression to evaluate the effect of LiCl-induced primary cilia expression on matrix synthesis by mechanically stimulated chondrocytes. LiCl treatment of chondrocytes in 3D agarose culture increased primary cilia incidence and length, with significant increases in incidence and length using 50mM LiCl compared to other concentrations (P < 0.05). This effect was further optimized by including a 4-day pre-culture prior to the 24-h 50mM LiCl treatment. Importantly, LiCl-induced primary cilia expression increased chondrocyte mechanosensitivity. When stimulated with dynamic compression, LiCl-treated P1 chondrocytes increased collagen (1.4-fold, P < 0.1) and proteoglycan (1.5-fold, P < 0.05) synthesis compared to untreated, unstimulated cells. The LiCl treatment method described here can be used to restore primary cilia in passaged chondrocytes, transforming them into a mechanosensitive cell source for cartilage tissue engineering.

Review of Marginal Oil Resources in Highly Depleted Reservoirs

The term “marginal oil resource” refers to an oil reservoir that has hydrocarbon resource preservation but cannot meet the criteria of resources under the U.S Securities and Exchange Commission (SEC) standards. When oilfields step into their late life, most of their economic petroleum reserves have been well developed, and their focuses need to be switched to their intact marginal resources. In this paper, reservoir characteristics and key petrophysical properties of marginal oil resources are introduced to classify marginal oil resources into four types for identifying potential development opportunities. Primary recovery and its following development strategy are applied to fully utilizing their economic returns. Waterflooding, low salinity waterflooding (LSW) and enhanced oil recovery processes are reviewed to illustrate its potential uplift on oil production and application challenges such as higher clay content in marginal resources than in commercial reservoirs. An oilfield is presented as a case study to demonstrate the classification of marginal resources and illustrate successful economic development including learnings and challenges. This paper highlights the development potential of marginal resources and proposes a clear guidance for policy makers on how to tailor a development strategy supporting their economic development. This review could increase certainty on forecasting performance of marginal resources.

Effect of supercritical CO2 flooding on the produced water quality and performance of the scale inhibitors in a typical tight sandstone oilfield

In order to enhance oil recovery, supercritical CO2 (scCO2) flooding has been applied in many oilfields to extract oil and gas post primary recovery. However, it causes serious scaling problems in the reservoir, oil well and production tubing. In this article, the produced water quality before and after scCO2 flooding in carbonate reservoirs are analyzed. The scaling trend of produced water before and after scCO2 flooding was calculated by using the Davis-stiff saturation index and Ryznar stability index methods. Static experiments and scanning electron microscope (SEM) are used to study the scale inhibition performance and mechanism of HEDP, ATMP, MA-AA, and PAA on CaCO3 in produced water before and after scCO2 flooding. The results show that after scCO2 flooding, the quality of produced water changes obviously, thus the scaling trend of produced water increases, the growth of CaCO3 crystal is affected and the scale inhibition efficiency of conventional scale inhibitors decreases.

Movement behavior of residual oil droplets and CO2: insights from molecular dynamics simulations

After primary and secondary recovery of tight reservoirs, it becomes increasingly challenging to recover the remaining oil. Therefore, improving the recovery of the remaining oil is of great importance. Herein, molecular dynamics simulation (MD) of residual oil droplet movement behavior under CO2 displacement was conducted in a silica nanopores model. In this research, the movement behavior of CO2 in contact with residual oil droplets under different temperatures was analyzed, and the distribution of molecules number of CO2 and residual oil droplets was investigated. Then, the changes in pressure, kinetic energy, potential energy, van der Waals' force, Coulomb energy, long-range Coulomb potential, bond energy, and angular energy with time in the system after the contact between CO2 and residual oil droplets were studied. At last, the g(r) distribution of CO2–CO2, CO2-oil molecules, and oil molecules-oil molecules at different temperatures was deliberated. According to the results, the diffusion of CO2 can destroy residual oil droplets formed by the n-nonane and simultaneously peel off the n-nonane molecules that attach to SiO2 and graphene nanosheets (GN). The cutoff radius r of the CO2–CO2 is approximately 0.255 nm and that of the C–CO2 is 0.285 nm. The atomic force between CO2 and CO2 is relatively stronger. There is little effect caused by changing temperature on the radius where the maximum peak occurs in the radial distribution function (RDF)-g(r) of CO2–CO2 and C–CO2. The maximum peak of g(r) distribution of the CO2–CO2 in the system declines first and then rises with increasing temperature, while that of g(r) distribution of C–CO2 changes in the opposite way. At different temperatures, after the peak of g(r), its curve decreases with the increase in radius. The coordination number around C9H20 decreases, and the distribution of C9H20 becomes loose.

Steam-Propane Injection Simulation for Heavy Oil

This research is about Steam-Propane Injection Simulation for Heavy Oil with the aim of simulating steam-propane EOR to increase oil recovery, then knowing the effect of different injection rates and being able to describe the best scenario of each different injection. The method used is reservoir modeling using CMG STARS software. The results show that for production that only relies on natural depletion (primary recovery) for 10 years of production, only 7% recovery from OOIP is obtained and when steam-propane injection is added, oil recovery is 60-70%. For the use of different injection rates, it is known that the higher the injection rate, the faster it will reach peak production and an increase in oil recovery. The best recovery method in this case is scenario case 4 with steam-propane injection with horizontal production wells. The advantage of using additional propane injection is to accelerate peak production and increase the recovery factor.

Simulation Studies on Comparative Evaluation of Waterflooding and Gas Injection in Niger Delta Thin-Bed Reservoir

There is a need to increase ultimate recovery from petroleum reservoirs. In order to guarantee efficient resource extraction from reservoirs, primary recovery methods cannot be relied on throughout the life of a well. There is a time in the life of a reservoir when the primary energy will not be sufficient to ensure economic recovery. Complete abandonment of the reservoir at this point may not be a sound engineering decision given the huge investments in developing the asset. Secondary recovery methods present potentials for the recovery of the other trapped resources. The choice of the secondary recovery means depends on the reservoir and geologic conditions and should be determined by modeling and simulation. In this work, a simulation study is conducted for Niger Delta Field ABX2 to determine the performance of water-flooding and gas injection in the recovery of the asset after the primary recovery stage. ECLIPSE Blackoil simulator was used for the modeling and simulation. An equal reservoir rectangular grid block was designed for both the waterflooding and water injection comprising a total of 750 grid cells. Water and gas were injected in both cases at an injection rate of 11,000 stb/d and 300,000 scf/d for waterflooding and gas injection respectively. From the results of the simulation, it was realized that waterflooding gave a higher total oil recovery than gas injection. The difference in oil recovery from water-flooding and gas injection amounted to 0.08 MMstb/d. The Field Oil Recovery Efficiency (FOE) for waterflooding and gas injection was 38% and 16% respectively giving a difference of 22%. The waterflooding method was troubled with excessive water cuts due to water breakthroughs. Waterflooding was chosen against gas injection to be applied to Field ABX2 to improve recovery after primary production ceased.

Blind Dual Watermarking Scheme Using Stucki Kernel and SPIHT for Image Self-Recovery

In this paper we propose a blind dual watermarking scheme using Set Partitioning in Hierarchical Trees (SPIHT) and Stucki Kernel halftone technique for the tamper detection and image self-recovery. The watermark consists of authentication bits for tampering area location and recovery bits for image restoration. We generate two recovery bits to ensure the high-quality recovery of the tampered image. The primary recovery bit is generated by the SPIHT encoding, and the secondary recovery bit is generated by the Stucki Kernel halftone technique. Then the authentication bit is generated based on the recovery bits. Before embedding the watermark, we shuffle the watermark bits through Arnold cat mapping and diagonal mapping to improve the security and quality of the restored image. LSB-based watermarking technique is used to embed the watermark into the original image to ensure the invisibility of the watermarked image. Experiments have been conducted on two datasets, BOW2 and USC-SIPI, and results show that the proposed scheme can achieve high restoration quality. Comparison with the existing works demonstrate the good performance and superiority of the proposed scheme.

Polymeric surfactants for enhanced oil recovery: A review of recent progress

Chemical enhanced oil recovery (CEOR) is a well-recognized technique for exploiting the original oil in place (OOIP) left behind in subsurface petroleum reservoirs after primary and secondary recovery processes. However, CEOR is not practiced or implemented widely because of project cost, operational and technical complexity, and environmental risks. Polymeric surfactants have emerged as a viable alternative to conventional chemical methods. They offer multifunctional mechanisms such as viscosity increment and interfacial tension (IFT) reduction. Thus, they are thought to be more versatile in enhancing recovery due to mobility control and wettability-induced fluid redistribution. This review presents a summary of recent studies in the literature that provides new insights into the properties, mechanisms, and applications of polymeric surfactants related to improved hydrocarbon recovery. From the published studies, fluid-fluid interactions influencing rheology and IFT, and fluid-rock interactions dictating wettability alteration and adsorption tendencies, are systematically evaluated. Implications of these mechanisms on enhanced hydrocarbon recovery by the polymeric surfactants are analyzed. Recent advances and knowledge gaps are highlighted, and possible directions to improve research methodology are suggested. • Most polymeric surfactants exhibit more remarkable rheological and emulsifying properties than conventional polymers. • The superior tolerances to harsh external conditions by polymeric surfactants are derived from associating properties. • The principal mechanisms of recovery during polymeric surfactant flooding is not yet explicit. • Polymeric surfactants change the wetting properties of rock surfaces mainly via adsorption mechanisms. • Polymeric surfactants of slightly lower weight have better mobility control and recovery potentials than conventional polymers.