Enhanced Oil Recovery Research Articles

Zwiększenie wydajności urządzeń do frezowania i oczyszczania odwiertów z resztek po frezowaniu poprzez zastosowanie kawitacji w strefie frezowania

Technological leadership on a global scale is closely linked to advancements in novel technologies and materials. Increasing the operating temperature of composite materials is a critical objective in the development of innovative materials and products derived from them. Advances in technology have demonstrated that extensive alloying, combined with optimal heat treatment and advanced material processing methods, enhances their heat resistance. High-temperature materials based on composites with an elevated temperature threshold fulfill this requirement. In the current stage of oil and gas industry development, methods to increase oil and gas production include the introduction of effective technological processes aimed at enhancing oil recovery, maintaining production wells, and implementing preventive measures. Particularly important are efforts to accelerate emergency maintenance of production and drilling wells. In this context, the introduction of new, highly efficient repair equipment designs and the improvement of existing tools and devices used in the field play a crucial role. The primary well maintenance activities include fishing and milling. Tools and devices used in these operations are classified into gripping, cutting, and auxiliary categories. One of the most versatile tools in well repair are cutting devices, designed for continuous milling of pipes, preparing the deformed ends of emergency pipes for fishing, opening casings, and cutting out drilling columns. Restoring damaged wells by milling is one of the most complex types of repairs. The productivity of wellbore milling is characterized by the life of the tool, the rate of metal penetration, and durability.

Dynamic properties of microspheres at the nanoscale and mechanisms for their application in enhanced oil recovery

Dynamic properties of microspheres at the nanoscale and mechanisms for their application in enhanced oil recovery

Elucidating Wettability Alteration on Clay Surface Contacting Mixed Electrolyte Solution: Implications to Low-Salinity Waterflooding

Summary Many mechanisms have been proposed in the literature to explain wettability alteration at low-salinity waterflooding (LSWF). Some of these mechanisms include electrical double layer (EDL) expansion, multi-ion exchange, and cation hydration. However, no consensus has been reached on which one is the key mechanism in low-salinity enhanced oil recovery (EOR). Moreover, the mechanisms by which low-salinity flooding can enhance oil recovery are poorly understood. Parameters such as salinity, electrolyte type, oil components, and presence of clay minerals are often associated with the degree to which the injection of low-salinity water increases oil production. Therefore, an investigation of the geochemistry of the clay/fluid interface is crucial to understand the role of petrophysical properties such as wettability on oil production. We use molecular dynamics (MD) to (i) quantify the impacts of different types of oil components, electrolytes, and its mixture at varying ionic strengths on interfacial properties and (ii) investigate wettability alteration by means of water adsorption quantification. We investigate the brine/clay and oil/brine/clay interfacial interactions involved in the adsorption of ions and water molecules onto the clay surface. Clay is represented by illite, and brine is composed of water molecules and different electrolyte types such as NaCl, CaCl2, and their mixtures at varied concentrations. The oil components investigated in this work include decane (C10H22), decanoic acid (CH₃(CH₂)₈COOH), and sodium decanoate (C10H19NaO2). These components were selected to represent the range of oil molecules typically found in reservoirs, which include nonpolar, polar, and charged polar molecules. Initially, we set up systems composed of different ion composition and salinity to investigate the effect of these parameters on EDL structure and water adsorption. Then, we created systems composed of mixed electrolyte and different oil components to verify the impacts of these molecules on the oil/brine/clay interface. Finally, we increased the NaCl concentration in the system containing sodium decanoate to investigate the role of Na in wettability alteration. MD simulations were performed at 330 K, and particle density profiles of water, hydrocarbon, and ions inside the illite nanopores were computed. We observed that the ion composition and salt concentration of the systems composed of clay minerals and brine do not result in significant changes in the adsorption planes of cations. For the same systems, we also computed the number of water molecules per unit cell in each hydration layer. We observed that the change in the thickness of these hydration layers is also very small. The results showed that nonpolar-charged hydrocarbon molecules have the lowest mobility, suggesting that this component has a more intense interaction with the illite surface compared with other hydrocarbons. Additionally, snapshots of the simulation indicate that calcium preferentially forms bridges with sodium decanoate molecules compared with other organic components. Despite being widely known as an efficient method for achieving EOR, the underpinning mechanism for wettability alteration at LSWF is still not fully understood. The outcomes of this work improve our understanding of the key parameters affecting interactions at the oil/rock/brine interface during LSWF.

Bacillus subtilis-mediated synthesis of ZnO and Ag-ZnO nanoparticles for eco-friendly displacement agents: Enhancing oil recovery in middle/low permeability reservoirs with nanofluid

Microorganisms, known for their widespread distribution and nonpolluting nature, are extensively used as raw materials. In this study, ZnO nanoparticles (ZnO NPs) and Ag-ZnO nanoparticles (Ag-ZnO NPs) were synthesized using Bacillus subtilis, and their efficacy as nano-displacement agents for enhancing oil recovery in medium and low permeability reservoirs was investigated. The morphology, structure, and properties of these nanomaterials were analyzed using various characterization methods. The results indicated that ZnO NPs are irregularly blocky with an average particle size of 44.7 nm, while Ag-ZnO NPs are approximately spherical with an average particle size of 35.5 nm, both exhibiting high purity and stability. These two nanoparticles can effectively reduce oil–water interfacial tension and improve rock wettability, with Ag-ZnO NPs showing superior performance. In core displacement tests at 60 °C, the recovery rates for intermediate permeability cores (30–40 mD) were 12.43% for ZnO nanofluids and 14.10% for Ag-ZnO nanofluids. For low-permeability cores (<10 mD), the recovery rates were 8.63% and 10.26%, respectively. Microscopic oil displacement experiments revealed that the mechanism of oil displacement by nano-displacement agents includes altering rock surface wettability, penetrating narrow pores, emulsifying crude oil, and exerting viscoelastic effects. In summary, these two nanomaterials significantly improve oil recovery in reservoirs, offering an important reference for their application in the oilfield and pointing toward a new direction for developing green and efficient alternatives to chemical flooding agents.

The interplay of plasticity and elasticity in elastoviscoplastic flows in wavy channels

Elastoviscoplastic (EVP) fluids, which exhibit both solid-like and liquid-like behaviors depending on the applied stress, are critical in industrial processes involving complex geometries such as porous media and wavy channels. In this study, we investigate how flow characteristics and channel design affect EVP fluid flow through a wavy channel, using numerical simulations supported by microfluidic experiments. Our results reveal that elasticity significantly influences flow dynamics, reducing pressure drops and expanding unyielded regions. Notably, we find that even minimal elasticity can shift the flow from steady to time-dependent regimes, a transition less pronounced in viscoelastic fluids. Additionally, we show that the development of stagnation regions can be prevented when using a modified EVP fluid with enhanced elasticity, thus providing a full global yielding of the material. This study elucidates the role of elasticity in modifying flow patterns and stress distribution within EVP fluids, offering insights into the optimization of industrial applications, such as the displacement of yield stress fluids in enhanced oil recovery, gas extraction, cementing, and other processes where flow efficiency is critical.

Technology Focus: Flow Assurance (November 2024)

This year’s Flow Assurance Technology Focus provides a trio of papers, selected by ChampionX’s Celestina Kissi, concerning the use of advanced techniques in detection, mitigation, and risk calculation. SPE technical conferences and meetings remain a critical conduit for the transfer of forward-thinking research and insight to both project developers and field practitioners who make certain that production is optimized and that goals are met. Paper SPE 216216 investigates asphaltene risks inherent in the gas-injection enhanced oil recovery (EOR) process. The authors’ research identifies what they term “stealth” asphaltenes, referring to asphaltenes detectable only by laser-light-scattering techniques and not by traditional microscopy. These asphaltenes are still flowable and can still pose risks to flow assurance. In the second selection, SPE 218101, the authors delve into the risks posed by hydrate formation in water-alternating-gas EOR operations, particularly during changeover operations, an area in need of further research in the literature. Additionally, the authors explore the effect of natural gas composition on these phenomena. Finally, paper SPE 218700 describes an operator’s development and deployment of a suite of cloud-based digital-twin tools designed to provide online, real-time calculation of scale risk and barrier health on a well-by-well basis. The complete paper includes four diverse case studies in which the described toolkit proved its value. As the technology used in the field sharpens, it will simultaneously overcome long-standing obstacles and discover entirely new ones, such as the challenge posed in the first presented paper. SPE technical conferences will continue to ensure that the flow of innovation reaches the page and the field with equal effect.

A 3D printing approach to microfluidic devices for enhanced oil recovery research: An updated perspective

A 3D printing approach to microfluidic devices for enhanced oil recovery research: An updated perspective

Critical Thresholds for CO2 Foam Generation in Homogeneous Porous Media

Summary Long-distance propagation of foam is one key to deep gas mobility control for enhanced oil recovery and CO2 sequestration. It depends on two processes—convection of bubbles and foam generation at the displacement front. Prior studies with N2 foam show the existence of a critical threshold for foam generation in terms of a minimum pressure gradient ∇pgenmin or minimum total interstitial velocity vt,genmin, beyond which strong-foam generation is triggered. The same mechanism controls foam propagation. There are few data for ∇pgenmin or vt,genmin for CO2 foam. We extend previous studies to quantify ∇pgenmin and vt,genmin for CO2 foam generation and, for the first time, relate ∇pgenmin and vt,genmin to factors including injected quality (gas volume fraction in the fluids injected) fg, surfactant concentration Cs, and permeability K. In each experiment, steady pressure gradient ∇p is measured at fixed injection rate and quality, with total interstitial velocity vt increasing and then decreasing in a series of steps. The trigger for strong-foam generation features an abrupt jump in ∇p upon an increase in vt. In most cases, the data for ∇p as a function of vt identify three regimes, which are coarse foam with low ∇p, an abrupt jump in ∇p, and strong foam with high ∇p. The abrupt jump in ∇p upon foam generation confirms the existence of ∇pgenmin and vt,genmin for CO2 foam. We further show how ∇pgenmin and vt,genmin scale with fg, Cs, and K. Conditions that stabilize lamellae reduce the values of the thresholds: Both ∇pgenmin and vt,genmin increase with fg and decrease with increasing Cs or K. Specifically, ∇pgenmin scales with fg as (fg)2 and vt,genmin scales as (fg)4, and both ∇pgenmin and vt,genmin scale with Cs as (Cs)−0.4. The effect of K on the thresholds for foam generation is greater than the effects of fg and Cs. Our data in artificial consolidated cores show that ∇pgenmin scales with K as K−2 for CO2 foam, in comparison with K−1 for N2 foam in unconsolidated sand/bead packs. More data are needed to verify these correlations. It is encouraging that ∇pgenmin in the cores with K = 270 md or greater is less than 0.17 bar/m (~0.75 psi/ft), two to three orders of magnitude less than for N2 foam. Such low ∇pgenmin can be easily attainable throughout a formation. This suggests that limited ∇p deep in formations is much less of a restriction for long-distance propagation of CO2 foam than for N2 foam. Foam propagation could still be challenging in low-K reservoirs (∇pgenmin ~10 bar/m for K = 27 md). Nevertheless, formation heterogeneity and alternating slug injection of gas and liquid help foam generation and can reduce the values of ∇pgenmin. More research is needed to predict long-distance propagation of foam at low ∇p and vt.

Experimental investigation of hybrid enhanced oil recovery techniques for Ugnu Heavy Oil on Alaska North Slope

The Alaska North Slope (ANS) is endowed with a substantial reservoir of heavy oil, estimated at 12–18 billion barrels, primarily concentrated within the Ugnu reservoirs. These deposits, situated at depths ranging from 2,000 to 4,000 feet, lie in close proximity to the permafrost and have undergone biodegradation, resulting in in-situ viscosities reaching thousands of centipoise. Following the success in recovering the somewhat less heavy, viscous oils through polymer injection, the deposits in Ugnu Formation are garnering significant interest. Although thermal recovery methods are commonplace for heavy oils, applying these methods on ANS is impractical, given the adjacency to continuous permafrost. Therefore, non-thermal hybrid enhanced oil recovery (cEOR) methods, such as solvent (e.g., CO2) and low salinity water (LSW) based, or LSW and polymer-based techniques, emerge as the primarily feasible options for recovering these vast heavy oil resources. This study experimentally investigates, via systematically carried out fluid property and phase behavior tests and a series of sand-pack coreflood experiments, the potential to enhance the recovery of Ugnu heavy oils. The coreflood experiments reveal the synergistic effect of combining liquid-CO2 with LSW to be the most promising approach in this study as a water alternating gas (WAG) process results in the cumulative recovery factor of 83.5%, doubling the recovery obtained by continuous low salinity waterflood. Additionally, the liquid-CO2-LSW WAG process demonstrated an additional benefit for CO2 storage, with about 25% of the pore volume of the liquid-CO2 injected being sequestered at the end of the injection process. This significant recovery improvement is attributed to a substantial reduction of oil viscosity upon contact with the liquid CO2 during the soaking period, with a reduction of up to 95% of the original oil viscosity. Meanwhile, in-situ emulsion generation was observed in the oil produced from the continuous LSW flooding. This was also evident by the increased differential pressure across the sand-pack compared to that of the liquid-CO2 alternating LSW process. The promising results of this study indicate significant potential for liquid-CO2 alternating LSW injection as an effective cEOR technique for Ugnu heavy oils.

Low-carbon and high-efficiency nanosheet-enhanced CO2 huff-n-puff (HnP) for heavy oil recovery

CO2 huff-n-puff (CO2-HnP) process is a promising technique for enhanced heavy oil recovery. The huff stage of this process involves the formation of foamy oil flow, characterized by dispersed CO2 bubbles within heavy oil, which plays a pivotal role in both oil recovery and CO2 sequestration. Maintaining the stability of foamy oil is crucial for the efficient implementation of CO2-HnP processes. Herein, ultrathin plate-shaped nanosheets are employed as stabilizers for foamy oil. Carboxyl-alkyl composite Janus nanosheets (SANs) are synthesized using a bottom-up approach. Comprehensive characterizations illustrate that SANs, owing to their amphiphilic and Janus nature, efficiently adsorb at the CO2-oil interface, thereby modifying interfacial properties and enhancing foamy oil stability even at low concentration (0.005 wt%). The incorporation of SANs extends the duration of foamy oil effect, resulting in a substantial enhancement of oil recovery efficiency from 30.7% to 39.4%, and an increase in CO2 storage factor from 6.5% to 7.8%, compared to conventional CO2-HnP processes. Micromodel experiments and molecular dynamics simulations show that SANs strengthen foamy oil stability by increasing interfacial activity and reducing CO2 diffusion rate. Overall, the multifunctional capabilities of SANs in interfacial modification offer promising prospects for enhanced oil recovery and optimizing CCUS efficiency.

Study on the differences in microscopic oil displacement effects and action mechanisms of different rhamnolipid systems

Rhamnolipids are a class of anionic glycolipid surfactants produced through microbial metabolism. As a widely researched biosurfactant, rhamnolipids possess several advantages over traditional chemical surfactants, including non-toxicity, eco-friendliness, biodegradability, and biocompatibility, particularly in the context of microbial oil recovery applications. This class of surfactants enhances oil recovery by reducing the interfacial tension between oil and water, emulsifying residual oil, and modifying the wettability of rock surfaces. Furthermore, rhamnolipids maintain stability in high-temperature and high-salinity environments. However, rhamnolipids derived from different fermentation substrates exhibit variations in structure, composition, and properties, resulting in distinct displacement effects and mechanisms of action. This study focuses on two types of rhamnolipids: typical rhamnolipid and high-yield rhamnolipid, which are fermented using glycerol and rapeseed oil, respectively. Based on the characteristics of the target heavy oil reservoir, micromodels were designed and manufactured to conduct microfluidic experiments. The results obtained from imaging and video recording were analyzed qualitatively and quantitatively to explore the differences in effects and mechanisms between the two rhamnolipid systems. Results indicate that typical rhamnolipid increased recovery by 4.41% through delayed mechanisms involving wettability modification and residual oil emulsification. Conversely, high-yield rhamnolipid demonstrates an immediate effect by reducing interfacial tension, resulting in a recovery increase in 5.68%. According to the observed experimental phenomena and analytical trends, the conclusions evaluate the production increase, clarify the differences in mechanisms of action, and enhance the microscopic understanding of these surfactants. These findings provide directions for future investigations and serve as a reference for the design of related schemes.

Movement of oil droplets against salt concentration gradients in thin capillaries

Mobilization of residual oil droplets is the key process for enhanced oil recovery. Visualization of the droplet movement at a pore level provides insights on the underlying physical mechanisms. We couple a microfluidic droplet generator and a thin glass capillary to study the movement of oil droplets under salinity gradients with visualization of individual droplet movements. The driving forces that affect the movement of the droplets are discussed. We demonstrate experimentally that oil droplets in micro-confined channels can be mobilized and move against pressure under the concentration gradients of dissolved salts. The gradient-driven movement can be strong enough to drive a droplet through a narrow constriction in the middle of the capillary channel. The droplet movement can be understood by combining a Marangoni stress due to surfactant redistribution, electrostatic interaction and diffusiophoresis. This suggests that the abrupt change of salinity may be one of the physical mechanisms of smart waterflooding.

Dynamics of impure CO2 and composite oil in mineral nanopores: Implications for shale oil recovery and gas storage performance

Evaluating the application effectiveness of impure CO2 in shale reservoirs is a prerequisite for reducing CO2 purification costs. Therefore, molecular dynamics simulations were applied to study the influential mechanisms of impurity gases, mineral types and oil components on impure CO2 enhanced oil recovery (impure CO2-EOR) and gas storage (GS). The orientation force between H2S and polar oil components and the strong adsorption of H2S on mineral walls improve the solubility and diffusivity of impure CO2 in shale oil. Moreover, the induction force between H2S and CO2 carry additional CO2 to walls, and the hydrogen bonds formed between H2S and walls further enhance oil–gas competitive adsorption, resulting in more adsorbed oil being stripped and more H2S/CO2 being sequestered. N2 hinders the dissolution of H2S/CO2 into shale oil and the diffusion of desorbed oil towards the center of nanopores. Therefore, the EOR and GS performances in nanopores are positively and negatively correlated with the proportion of H2S and N2 in impure CO2, respectively. Both EOR and GS performances of impure CO2 decrease sequentially in illite, quartz, and kerogen nanopores, because the strong adsorption of shale oil on kerogen walls causes oil molecules to arrange tightly and dissolve in kerogen. It weakens the solubility and diffusivity of impure CO2 in shale oil, and also increases the resistance of impure CO2 to displace adsorbed and dissolved oil. By contrast, illite walls have the weakest adsorption on shale oil and the largest number of hydrogen bonds formed with H2S. The increase of heavy component content further enhances the interaction between oil molecules and the adsorption of shale oil on wall, thereby weakening the effects of various impure CO2-EOR mechanisms.

Study Investigates Hydrate Formation Risk in WAG Changeover Operations

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 218101, “Investigating the Effect of Carbon Dioxide Concentration on Hydrate Formation Risk From Water-Alternating-Gas (WAG) Changeover Operations,” by Farzan Sahari Moghaddam, SPE, Majid Abedinzadegan Abdi, SPE, and Lesley A. James, SPE, Memorial University of Newfoundland. The paper has not been peer reviewed. _ Hydrate formation is a flow-assurance challenge for offshore oil and gas operations with subsea pipelines, wells, and tiebacks. In water-alternating-gas (WAG) operations, hydrates can form within the injection wells when switching from water to gas and vice versa. This study investigates hydrate formation in a WAG injection well under water-to-gas and gas-to-water changeover operations. Introduction Few previous studies have focused on hydrate formation in gas injection and production wells. Hydrate formation in a gas well under particular enhanced oil recovery techniques requires more attention. This study aims to investigate the changeover operations of water-to-gas and gas-to-water (well depth: 4096 m) and the effects of gas composition changes in terms of CO2 content (5–44 wt%) and thermodynamic inhibition (5 m3 methanol) after water injection. In terms of flow rates, injection rates of 2300–3800 m3/d for water and 1 million std m3/d for gas, which are applicable for offshore Newfoundland and Labrador (NL), are studied. The complete paper includes a discussion of past studies on hydrate formation in production and injection-gas systems. Methodology Two scenarios were simulated: water-to-gas changeover and gas-to-water changeover over a range of CO2 concentrations of 5–44 wt%. For operational parameters, up to 3 days of shut-in period was considered for the changeover operations. The water injection rate of 2300 m3/d and gas injection rate of 1 million std m3/d were considered. The rate was increased to find the injection rate that could provide full displacement of the water phase within less than 1 hour from a water-to-gas changeover operation. The same injection rate is maintained for other natural-gas cases with increased CO2 content by changing the compressor injection pressure. After modeling the fluid with an appropriate cubic equation of state, the fluid model file was imported to the dynamic multiphase flow simulator. A sample WAG well from offshore NL where hydrate formation was experienced was considered for the simulations. After finalizing the setup of the well, the simulation scenario was finalized according to the changeover operation and the operating conditions. A sensitivity analysis was conducted on various concentrations of CO2 (5–44 wt%) followed by conducting both water-to-gas and gas-to-water changeover operations in the transient multiphase simulator. Finally, hydrate formation in presence of methanol was simulated, and the resulting profiles of hydrate formation temperature minus fluid temperature, known as DTHYD, were compared. The well depth is 4096 m from the seabed, and tubing internal diameter is 0.16 m. The seabed depth is 124 m below mean sea level. The bottomhole is known as the zero depth on the DTHYD, holdup, density, and pressure profiles, and the wellhead is considered to be 4096 m above the bottomhole depth in these profiles. A methanol slug was injected directly into the well under a sea temperature of 3°C at the end of water injection and before the shut-in duration.

Analytical procedure for tracing acrylamide and sulfonated co-polymers in groundwater affected by chemical enhanced oil recovery activities

Analytical procedure for tracing acrylamide and sulfonated co-polymers in groundwater affected by chemical enhanced oil recovery activities

Data Science Enables Management of Stealth Asphaltene Flow-Assurance Risk

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216216, “Managing Stealth Asphaltene Flow-Assurance Potential Risk in Gas-Injection Field Based on Data Science Using Over 20-Year Accumulated Data Set,” by Hideharu Yonebayashi, SPE, and Takeshi Hiraiwa, SPE, Japan Oil Development, and Khuloud T. Al Khlaifi, SPE, ADNOC, et al. The paper has not been peer reviewed. _ Gas injection is recognized generally not only to improve oil recovery but also to increase the risk of asphaltene destabilization. The recent discovery of asphaltene deposits in a subject field motivated the operator to launch an immediate investigation to evaluate what critical risks might exist and consider appropriate mitigation. It was found that precipitated but invisible asphaltenes still can be flowable. This stealth asphaltene behavior could explain a possible mechanism of the first asphaltene observation in the upper reservoir. Introduction The subject giant offshore field in the Arabian Gulf has not experienced asphaltene-induced production deterioration during long-term lean hydrocarbon gas injection. The gas has been injected into the crestal area of two reservoirs (upper and lower) with peripheral powered seawater injection. Both reservoir fluids contain a small amount of asphaltenes (0.1–1.5 wt%) distributed at higher concentration at deeper locations. In May 2022, the first discovery of asphaltene deposits from the historical no-issued area in the upper reservoir motivated an immediate investigation for risk assessment and mitigation. A resulting study captured stealth asphaltenes, which were detected by a laser-light-scattering technique while high-pressure microscopy detected no visible asphaltene solid particles. Historical Asphaltene Data Accumulation The permeability range and pore-throat size of the subject field are relatively low in the lower reservoir compared with the upper. Both reservoirs are under highly unstable asphaltene-stability conditions. The reservoir pressure-maintenance scheme, consisting of dump-floodwater injection followed by peripheral powered seawater injection and crestal gas injection, however, has maintained asphaltene-free production except for the gas-injection pilot (GIP) during 2005–2009. No asphaltenes have been observed in the crestal gas-injection area; however, asphaltene deposits were observed in the GIP area in 2007. The injected gas was enriched gradually by a vaporizing gas-drive process. The previous studies involving numerical modeling analysis and laboratory experiments reported that enriched hydrocarbon gas can more easily allow asphaltene precipitation compared with lean hydrocarbon gas. GIP Asphaltene Risk Analysis (Upper Reservoir). In 2009, an asphaltene flow-assurance risk evaluation was conducted using the single-phase bottomhole sample collected from Well 6, which is 90 ft shallower that the GIP area and far from the crestal gas-injection area. Therefore, the Well 6 reservoir fluid was not affected by injection gas. The bottomhole condition of the GIP production well was entered into the asphaltene precipitation envelope (APE) that was expanded by injection-gas enrichment but never covered by the APE without an enrichment process. Latest Laboratory Analysis (Lower Reservoir). In 2022, an asphaltene flow-assurance risk evaluation was conducted. After the location was narrowed to a depth range, Well 1 was selected by taking an asphaltene gradient into account.

Microscopic Remaining Oil Classification Method and Utilization Based on Kinetic Mechanism

In reality, the remaining oil in the ultra-high water cut period is highly dispersed, so a thorough investigation is required to understand the microscopic remaining oil. This will directly influence the technological direction and allow for countermeasures such as enhanced oil recovery (EOR). Therefore, this study aims to investigate the state, classification method and utilization mechanism of the microscopic remaining oil in the late period of the ultra-high water cut. To achieve this, the classification of microscopic remaining oil based on mechanical mechanism was developed using displacement CT scan and micro-scale flow simulation methods. Three carefully selected mechanical characterization parameters were used: oil–water connectivity, oil–mass specific surface and oil–water area ratio. These give five types of microscopic remaining oil, which are as follows: A (capillary and viscous oil cluster type), B (capillary and viscous oil drop type), C (viscous oil film type), D (capillary force control throat type), and E (viscous control blind end type). The state of the microscopic remaining oil in classified oil reservoirs was defined after high-expansion water erosion. Based on micro-flow simulation and analysis of different forces during the displacement process, the main microscopic remaining oil recognized is in class-I, class-II and class-III reservoirs. Within the Eastern sandstone oilfields in China, the ultra-high water-cut stage is a good indicator that the class-I oil layer is dominated by capillary and viscous oil drop types distributed in large connected holes. The class-II oil layer has capillary and viscous force-controlled clusters distributed in small and medium pores with high connectivity. In the case of the class-III oil layer, it enjoys the support of capillary force control throats that are mainly distributed in small holes with high connectivity. Integrating mechanisms of different types of micro-remaining oil indicates that, enhancing utilization conditions requires increasing pressure gradient and shear force while reducing capillary resistance. An effective way to improve the remaining oil utilization is to increase the pressure gradient and change the flow direction during the water-drive development process. Hence, this forms a theoretical basis and a guide for the potential exploitation of remaining oil. Likewise, it provides a strategy for optimizing enhanced oil recovery in the ultra-high water-cut stage of mid-high permeability oil reservoirs worldwide.

Quantitative Characterization of Surfactant Displacement Efficiency by NMR—Take the Tight Oil of Chang 8 Member of Yanchang Formation in Fuxian Area, Ordos Basin, as an Example

Surfactant flooding is a pivotal technique for enhancing oil recovery efficiency. The Chang 8 member of the Yanchang Formation in the Ordos Basin exemplifies a quintessential tight oil reservoir. Specifically, 47.9% of wells yield less than 0.1 t/d, 27.0% produce between 0.1 and 0.2 t/d, and 18.8% generate outputs ranging from 0.2 to 0.3 t/d, while only a mere 6.3% exceed production rates of over 0.3 t/d, indicating minimal efficacy of water flooding development in this context. In this study, we conducted an extensive investigation into the geological characteristics of the Yanchang 8 reservoir within the Ordos Basin, leading to the identification and evaluation of three surfactants based on their interfacial tension properties. The optimal injection concentration was determined through on-line displacement nuclear magnetic resonance imaging analysis that refined surface activity conducive to developing the Chang 8 member, ultimately resulting in increased spread volume and enhanced crude oil production from individual wells. The results indicate the following: (1) The interfacial tension of NP-10, FSD-952, and GPHQ-1 at concentrations of 0.05%, 0.1%, 0.2%, 0.3%, 0.4%, and 0.5% exhibited a pattern of initial decrease followed by an increase. The mass concentration corresponding to the minimum interfacial tension for NP-10 is identified as 0.1%, which is also the case for GPHQ-1; however, for FSD-952, this occurs at a concentration of 0.4%. Among the surface-active agents NP-10, GPHQ-1, and FSD-952, GPHQ-1 demonstrated the lowest interfacial tension value at an impressive measurement of 0.0762 mN/m. (2) When the displacement of the 0.1% GPHQ-1 surfactant reaches 10 PV, the displacement efficiency improves from 69.69% to 76.36%, representing an increase of 6.67%. The minimum pore size observed during GPHQ-1 surfactant displacement is 0.01 μm. In contrast, when the displacement of the NP-10 surfactant at a concentration of 0.1% reaches 10 PV, the efficiency rises from 68.32% to 72.02%, indicating an enhancement of 3.7%. The corresponding minimum pore size for NP-10 surfactant displacement is recorded at 0.02 μm. Furthermore, when the displacement of the FSD-952 surfactant at a concentration of 0.4% achieves 10 PV, its efficiency increases from 69.93% to 74.77%, reflecting an improvement of 4.81%. The minimum pore size associated with the activated portion of FSD-952 is noted as being approximately 0.03 μm.

Characterization of Stages of CO2-Enhanced Oil Recovery Process in Low-Permeability Oil Reservoirs Based on Core Flooding Experiments

Understanding the CO2 displacement mechanism in ultra-low-permeability reservoirs is essential for improving oil recovery. In this research, a series of displacement experiments were conducted on sandstone core samples from the Chang 6 reservoir in the Huaziping area using a multifunctional core displacement apparatus and Nuclear Magnetic Resonance (NMR) technology. The experiments were designed under conditions of constant pressure, variable pressure, and constant effective confining stress to simulate various reservoir scenarios. The results indicated that the distribution characteristics of the pore structure in the rock samples significantly influenced the CO2 displacement efficiency. Specifically, under identical conditions, rock cores with a higher macropore ratio exhibited a significantly enhanced recovery rate, reaching 68.21%, which represents a maximum increase of 31.97% compared to cores with a lower macropore ratio. Though fractures can facilitate CO2 flowing through pores, the confining pressure applied during displacement caused a partial closure of fractures, resulting in reduced rock permeability. Based on the oil-to-gas ratio and oil recovery in the outlet section of the fractured rock samples, the CO2 displacement process exhibited five stages of no gas, a small amount of gas, gas breakthrough, large gas channeling, and gas fluctuation. Although the displacement stage of different cores varies, the breakthrough stage consistently occurs within the range of 2 PV. These insights not only enhance our understanding of CO2 displacement mechanisms in low-permeability reservoirs but also provide actionable data to inform the development of more effective CO2-EOR strategies, significantly impacting industrial practices.

The characteristics of steam chamber expanding and the EOR mechanisms of tridimensional steam flooding (TSF) in thick heavy oil reservoirs

Aiming at the shortcoming of conventional steam flooding (CSF), tridimensional steam flooding (TSF) was proposed to expand the limited steam chamber and to enhance the low oil recovery in thick heavy oil reservoirs. In this paper, based on mechanisms of thermal recovery, two 3D experimental models were designed to investigate the evolution of steam chambers and production performance. A new method was proposed to utilize inflection point temperature and remaining oil saturation to identify utilizable ranges, hot water zones, and steam chambers. Then, based on the parameters of the indoor experiments, three numerical models were built to further study advantages of TSF. The results show that: i) Compared to CSF, TSF possesses a plumper steam chamber, a higher steam quality and a more stable displacement front; ii) The oil recovery of TSF can reach 52.85%, while it is only 43.31% for CSF at the same time; iii) At the end of TSF, the volume of steam chamber, low oil saturation zone, low pressure zone, and low viscosity zone is 3.08 times, 3.31 times, 1.61 times, and 1.55 times, respectively, compared to CSF, which demonstrates that TSF is effective. As a result, TSF can effectively expand steam chamber and enhance oil recovery in thick heavy oil reservoirs.