Reservoir Characterization and Modelling Supported by Expert Knowledge Systems

The development of major oil fields requires considerable primary resources consumptions. Vast use of land, water and energy, negative technogenic impact influence considerably on natural environment in local and regional aspects. Implementation of improved oil recovery (IOR) methods demands additional use of energy, expensive oil displacement agents, skilled personnel, specialised equipment etc. Multicriteria analysis of oil recovery processes by use of primary resources allows to estimate the complex efficiency and rate of natural environmental impact. To achive the solution of multipurpose problem of. rational resources consumption in course of oil fields development procedure of optimization and compromise programming is carried out. The significance of used natural resources in different geographical regions is determined by environment protection expert analysis. Natural environment systems in such regions as the North of the West Suberia and the Kaspean lowland are very sensitive to the processes of oil and gas fields development. The permafrost conditions and easy spoiled land fertile cover, the danger of earth subsidence and possible technogenic seismicity demand thorouth analysis of oil recovery projects applicability and their environmental safety. Complex efficiency assessment and multicriterion optimization of primary resources consumption have been done for the design versions of development of large oil fields Russkoe and Tengiz. Analysis of verious IOR methods on the basis of primary and energy resources consumption allows a better choice of natural environment saving technology and shows the direction and necessity of their further improvement. Study of possible technogenic effects caused by oil field development is of prime importence for timely prevention from negative consequences for nature in the region.

Gas and water flooding are known as improved oil recovery method. Implementation of these IOR for volatile oil reservoir is essential to oil recovery and project economic. Different IOR schemes provide different mechanisms of flooding and pressure maintenance for volatile oil reservoirs. Hence, understanding of volatile oil behavior and each IOR performance will lead to a proper scheme selection. Compositional simulation study is performed in order to find the optimum way to recover volatile oil. Simulation of natural depletion, waterflooding, gasflooding, and water alternating gas are investigated and compared in aspect of oil recovery performance and project economic. From simulation results, we found that gravity segregation of solution gas is the most influential drive mechanism to volatile oil recovery of natural depletion. Hence, enhancement of this drive mechanism is the key to production optimization and completion design. For water and gas flooding, starting maintaining the reservoir pressure above the bubble point pressure and before free exists in the reservoir will maximize the recovery. For waterflooding, if free gas exists, displacement efficiency is reduced due to gas blockage effect. For gasflooding, existing of free gas is lower capability in miscibility condition achievement because the intermediate components in oil phase already flash to gas phase and cannot be used to develop miscible flood front. And when compared all studied production schemes, waterflooding can recover oil less than gasflooding, but can yield similar net profit due to lower investment cost required. While water alternating gas yields the highest total oil recovery and net profit because it combines the advantages of both water and gas flooding.

Primary production mechanisms do not recover an appreciable fraction of the hydrocarbon initially in place (HIIP). Practical knowledge has shown that, at the point when the natural energy in a heavy oil reservoir is nearly or altogether depleted, the recovery factor does not exceed about 20%. Some heavy oil reservoirs do not produce at all by natural drive mechanisms. This often necessitates adopting a production improvement strategy to augment recovery. Prior to implementing an improved oil recovery method (either secondary or tertiary) in the field, it is very important to investigate its potential for success. Reservoir simulation is part of a continuous learning process used to gain insight into the feasibility and applicability of improved oil recovery methods. In this project, GEM compositional reservoir simulator has been used to study the efficiencies of different improved oil recovery strategies, ranging from waterflooding to solvent injection. The drainage volume investigated is a hypothetical box-shaped heavy oil reservoir composed of three distinct permeable layers.

The enhanced oil recovery (EOR) is important to be implemented, in matured unconsolidated sandstone reservoir. It is to ensure oil production with optimum recovery from the reservoir. It requires an integration multi disciplines rock and fluid properties evaluation. In this EOR study with water injection, gas injection, water alternating gas and ongoing alkaline surfactant polymer (ASP) have been used for EOR displacement analysis, it has used engineering of gas injection in advanced PVT analysis to properly understand the injection reservoir fluid phase behavior and the EOR displacements in core flooding. The PVT study has been performed, initially on the gas miscibility and phase behavior that consists swelling test, minimum miscibility pressure (MMP), vapour liquid equilibrium (VLE), multi-contact evaluation and flow assurance studies. The oil and water from the particular reservoir conditions have been used in the analysis. Then it continued with reservoir characterization, water injection, gas injection, water alternating gas (WAG) and ongoing ASP for hybrid EOR displacements analysis. It has involved an in-house integrated petrophysical, geological, reservoir characterization and model in the EOR study. A 3D computed tomography (CT) image and the available RRT-SHM model have been used for core plugs selection of the EOR study. The unconsolidated core samples have been plugged successfully by liquid nitrogen and cleaned, then injection high to low water salinity and the wettability restoration a steady-state relative permeability with the selected fluids. The steady-state floods (water-oil, gas- oil and gas-water) have been designed to obtain relative permeability on plugs representing selected reservoir rock types at reservoir conditions. A digital rock analysis with steady state floods on the same rock types is validated, then digital rock analysis is used to obtain relative permeability data on all remaining rock types for fast time and effective cost. The saturation is determined by in situ saturation monitoring (ISSM) with X-Ray attenuation. Injection continues until the pressure drop across the core sample and the measured saturation are stable. The oil and gas are injected into a sample initially at initial water saturation to maximum gas injection and at residual oil saturation. The optimum conditions for EOR and related parameters controlled by the core properties on the EOR displacement analysis are defined. The innovative integrated approach of reservoir characterization and EOR have provided the reliable technical basis and assurance for the development of unconsolidated sandstone reservoirs. The oil recovery with recent reservoir conditions range has been measured. It has benefits to maximize oil recovery from current main producing reservoir with utilizing the available gas, fluids, core, logs, production and reservoir data which is important for a successful field development plan.

It is widely recognized by oil industry that reservoir characteristics such as natural heterogeneity, spatial variability of permeability, net pay, porosity and spatial distribution of oil and water saturations control the fluid flow in porous media, reservoir performance, development strategies and the economics returns of investments of field development plan implementations. Nonetheless, most of the time few data are available for projects and fast evaluation of reservoir performance is needed for decision making. Understand the impact of reservoir parameters variability over pressures and saturations history match require multiple realizations of numerical simulations. Managers tend to avoid costs and production losses related to data acquisition. Pressure and rate transient analyses (PTA&RTA), along extended production time, allows the reservoir characterization (drive mechanisms, boundaries conditions) and understand near wellbore characteristics, however, PTA&RTA alone does not provide pressure and fluid distribution prediction beyond the wellbore, it requires the integration with reservoir simulation. This paper provides an integrated reservoir characterization workflow which allows reservoir engineers to identify production/reservoir uncertainties and constraints to evaluate different field development strategies to maximize the ultimate oil recovery in a short period of time. Pressure Transient Analysis (PTA) address near wellbore effects and help to identify gas cap or aquifer strength, reservoir boundaries as well as recognizing sealing/non-sealing faults. For this project, static pressure was not available to perform history matching, but real time Pump Intake Pressure (PIP) was measured from Electric Submersible Pump sensors. Vertical lift performance curve was determined by using well completion data at the mid-point of perforation extrapolating PIP to bottomhole pressure (Pwf). Rate Transient Analysis (RTA) utilizes continuous production and flowing pressure data to characterize the reservoir and completion and it was key to understand reservoir performance, and provide insights for rapid and reliable history matching. This workflow was successfully applied in South America reservoir. To accomplish goals, it was necessary to perform a quick reservoir characterization and analysis - reservoir compartmentalization, PVT property distributions, rock properties distribution, and well performance history – to understand reservoir pressure and production behavior. Unstructured refined grid principles (Voronoi Grid) were applied to build a relatively small and simple model that considers all the required physics of the problem. The estimated reservoir properties from petrophysical analysis were validated against PTA&RTA thus honoring the near wellbore effects. The resulting model permitted the generation of key field development strategies considering additional well placement and completion technologies and best production operational practices, as well as the characterization of major uncertainties related with the reservoir-well system. Once model was initialized under a satisfactory level of tolerance (difference between the original oil in place determined by numerical reservoir model and the static model less than 2%) the history matching process began. Henceforth, a history matching workflow was generated to optimize the number of sensitivities and prioritize variable of greater significance. The history matching process improved pressure and production match and reduced CPU time approximately by 80% and 60% respectively. Aquifer strength for each formation was determined as a result of these analyses. The reservoir and production uncertainties allowed generation of a new surveillance plan to improve reservoir characterization and performance in the short term. Finally, a base case scenario was generated as a starting point to determine the recovery factor and identify new opportunities to develop oil and gas recoverable reserves of the field. An optimum scenario was generated to reduce water production and increase oil recovery for each formation resulting in 17.6 % reduction of produced water, with a simultaneous 13 % increase in overall oil recovery and 8 % project profitability. Additionally a series of recommendations were also derived regarding to: 1. Guidelines to generate a more reliable, consistent, and economically profitable field development plan, 2. Data acquisition plan to minimize impact of uncertainties in the field development plan, and 3. Visualization of improved oil recovery opportunities by carrying out gas, water, and EOR processes like polymer injection.

This paper presents an enhanced oil recovery (EOR) evaluation for two heavy-oil fields in Africa. The objective of the evaluation is to identify the technically and economically viable EOR techniques for the fields. A total of thirteen established and emerging EOR techniques were evaluated in this study. The study included the first degree approximation of the oil recovery for the viable EOR techniques and the stand-alone project economics estimation. The data required for the study include: 1) fluids and rock properties; 2) driving mechanism; 3) production data; 4) OOIP and recoverable reserves; and 5) relative permeability curves. Various EOR technique screening criteria, consisting of a list of reservoir parameters and their ranges which are likely to lead to a success, were applied to match the parameters of the study fields. The oil recovery predictions were estimated utilizing general reservoir parameters and developed correlations1. The economic feasibility of the potential EOR techniques was then evaluated based on the stand-alone project economics that accounted for the revenue from the incremental oil and the associated operating and capital costs. The evaluation results showed that the thermal EOR techniques: steam flooding and in-situ combustion are technically the most viable EOR techniques for the fields. It was then followed by the chemical EOR techniques. The performances of steam flooding and in-situ combustion are both very promising, with oil recovery of up to 49% OOIP. Comparing to the oil recovery of water flooding, a significant incremental oil recovery of 24% OOIP was obtained. However, the in-situ combustion process is able to accelerate the oil production, which significantly impacts the economic viability assessment, rendering the in-situ combustion process as the most technically, and economically feasible EOR process for the fields. Based on the EOR evaluation, the oil recovery predictions and economic assessments of the thirteen EOR techniques, including the chemical, gas, thermal and microbial EOR techniques, served as a guideline to develop the long term corporate strategy regarding the EOR potential of the fields.

A Storage-Driven CO2 EOR for a Net-Zero Emission Target

Critical review on microscopic differences of rock characteristics and flow behaviour for tight sandstone reservoirs in Ordos Basin, China

This paper assesses the pore- and field-scale enhanced oil recovery (EOR) mechanisms by gas injection for low permeability shale reservoirs. We performed compression-decompression laboratory experiments in ultratight outcrop cores of the Permian Basin as well as in ceramic cores using n-dodecane for oil. The EOR assessment strategy involved determining the quantity of oil produced after injection of helium (He), nitrogen (N2), methane (CH4), and methane/carbon dioxide (CH4/CO2) gas mixtures into unfractured and fractured cores followed by depressurization. Using the oil recovery volumes from cores with different number of fractures, we quantified the effect of fractures on oil recovery—both for Wolfcamp outcrop cores and several ceramic cores. We observed that the amount of oil recovered was significantly affected by the pore-network complexity and pore-size distribution. We conducted laboratory EOR tests at pore pressure of 1500 psia and temperature of 160°F using a unique coreflooding apparatus capable of measuring small volumes of the effluent oil less than 1 cm3. The laboratory procedure consisted of (1) injecting pure n-dodecane (n-C12H26) into a vessel containing a core which had been moistened hygroscopically and vacuumed, and raising and maintaining pressure at 1500 psia for several days or weeks to saturate the core with n-dodecane; (2) dropping the vessel pressure and temperature to laboratory ambient conditions to determine how much oil had entered the core; (3) injecting gas into the n-dodecane saturated core at 1500 psia for several days or weeks; (4) shutting in the core flooding system for several days or weeks to allow gas in the fractures to interact with the matrix oil; (5) finally, producing the EOR oil by depressurization to room pressure and temperature. Thus, the gas injection EOR is a ‘huff-and-puff’ process. The primary expansion-drive oil production with no dissolved gas from fractured Wolfcamp cores was 5% of the initial oil in place (IOIP) and 3.6% of IOIP in stacked synthetic cores. After injecting CH4/CO2 gas mixtures, the EOR oil recovery by expansion-drive in Wolfcamp core was 12% of IOIP and 8.2% of IOIP in stacked synthetic cores. It is to be noted that the volume of the produced oil from Wolfcamp cores was 0.27 cm3 while it was 6.98 cm3 in stacked synthetic cores. Thus, while synthetic cores do not necessarily represent shale reservoir cores under expansion drive and gas-injection EOR, these experiments provide a means to quantify the oil recovery mechanism of expansion-drive in shale reservoirs. The gas injection EOR oil recovery in Wolfcamp cores with no fractures yielded 7.1% of IOIP compared to the case of one fracture and two fractures which produced 11.9% and 17.6% of OIP, respectively. Furthermore, in the no-fracture, one-fracture, and two-fracture cores, more EOR oil was produced by increasing the CO2fraction in the injection gas mixture. This research provides a basis for interpreting core flooding oil recovery results under expansion drive and gas injection EOR—both in presence and absence of interconnected micro- and macro-fractures in the flow path. Finally, the CO2 injection results quantify the CCUS efficacy in regard to the amount of sequestered CO2 from pore trapping in the early reservoir life. For the long-term CO2 trapping, one needs to include the chemical interaction of CO2 with the formation brine and rock matrix.

A considerable amount of hydrocarbon resource is estimated to remain in the ground even after primary and secondary recoveries in the fields. As of 2003, the estimated oil-in-place from the forty-seven producing fields in Malaysia stand at about 20.1 BSTB, with a cumulative production of 4.9 BSTB and reserves of 2.5 BSTB1. This translates to an averaged recovery factor of only 36.8 percent for producing fields in Malaysia. For this reason, the remaining oil-in-place of 12.7 BSTB i.e. 63.2% of STOIIP will be the prime target for Enhanced Oil Recovery (EOR) projects. On top of the value that could be gained through EOR applications, most of the fields are already entering maturing stage for primary and/or secondary depletion with declining oil rates and increasing water-cut and GOR trend. This situation will further merit the application of EOR processes. However, to date, there has been no full-field application of EOR in Malaysia, with the exception of a pilot WAG project in Dulang field2,3 and MEOR stimulation project in Bokor field4–6. In 2000, a screening study on seventy-two (72) reservoirs in Malaysia has identified almost a billion barrels of additional reserves that can be achieved through EOR. Majority of these potentials resides in a few major reservoirs, which carries about 60% of the total EOR potential7. The screening study has also identified several key EOR technologies that are most applicable in Malaysia, namely gas injection, chemical injection, and microbial. Thermal processes were investigated but have been ruled out due to the operational, properties of reservoir fluid, safety and commercial limitation of the methods for Malaysian offshore applications. However, transforming those potentials into real projects may face some challenges and change of operating philosophy. Factors such as facilities condition, sources of injection gas, reservoir characterization, technology applicability, and commercial aspects will play an important role in planning for an EOR projects in Malaysia. This paper presents the possible opportunities that could be realized by EOR applications, and discusses issues and challenges including change of mindsets required in making EOR a reality in Malaysia.

Analytical assessment of horizontal well efficiency with reference to improved oil recovery of the South-East Dragon oil field southern offshore of Vietnam

Summary A considerable portion of the world's hydrocarbon endowment is in carbonate reservoirs. Carbonate reservoirs usually exhibit low porosity and may be fractured. These two characteristics along with oil-to-mixed wet rock properties usually result in lowered hydrocarbon recovery rates. When enhanced oil recovery (EOR) strategies are pursued, the injected fluids will likely flow through the fracture network and bypass the oil in the rock matrix. The high permeability in the fracture network and the low equivalent porous volume result in early breakthrough of the injected fluids. Infill drilling programs and well conformance strategies—mostly gas and water shutoff—have been effectively used to mitigate the early breakthrough and increase oil recovery. In most cases, however, 40 to 50% of the original oil in place (OOIP) is not produced. A large number of EOR field projects in carbonate reservoirs have been referenced in the literature since the early 1970s. These field projects demonstrate the technical feasibility of various EOR methods in carbonate reservoirs. However, because of the collapse in oil prices, most of the aforementioned project plans have been abandoned. This paper presents a comprehensive compilation of EOR (Gas, Chemical, and Thermal methods) field experiences in carbonate reservoirs within the US, as an attempt to identify key variables and project design parameters for future evaluation and revitalization of mature carbonate reservoirs. Carbon dioxide flooding [continuous or water-alternating gas (WAG)] is the dominant EOR process used in the US This is because of the high availability of low-cost CO2. CO2 EOR in particular represents the logical first step towards viable geologic carbon storage and sequestration. EOR chemical methods in carbonate reservoirs, especially polymer flooding, have been widely tested in US carbonate reservoirs. However, EOR chemical methods have made a marginal contribution, relatively, in terms of total oil recovered. Our study includes a brief overview of current laboratory (e.g. wettability changes and novel chemical additives) and field (e.g. injectivity enhancement) experiences in EOR chemical methods in carbonate formations. A brief discussion surrounding the screening methods used to identify viable EOR opportunities in carbonate fields based on past and present experiences is also included. Introduction Carbonate reservoirs are naturally-fractured geologic formations characterized by heterogeneous porosity and permeability distributions. In the case of low porosity and low permeability carbonate rocks (more specifically rock matrices), the fluid flow in the reservoir can be completely dependent on the fracture network while the matrix only plays a source role (analogous to tight sand formations and natural gas flow). In the case of porous carbonate rocks, fracture networks can cause uneven sweeping of the reservoir, leading to early breakthrough of injected fluids in the producing wells and resulting in low recovery factors. The abundance of carbonate reservoirs has been the subject of numerous studies attempting to characterize their heterogeneities, classify different types of fractured reservoirs, and determine how rock and fluid properties have an impact on ultimate recovery (Roehl et al. 1985; Allan and Qing Sun 2003; Carr et al. 2001; Grave et al. 2000; Benson et al. 1998; Wardlaw 1996). The TORIS database (maintained by the US Department of Energy) indicates 22% of the OOIP in the US is contained in shallow-shelf carbonate reservoirs. Currently in the US, these types of reservoirs exist in more than 14 states with over 70% of the OOIP located in reservoirs in Texas and New Mexico, mostly concentrated in the Permian Basin (Nuckols 1992, Xie et al. 2005). Over the last three decades, primary production, waterflooding, and CO2 floods, combined with infill drilling programs, have been the most widely used recovery methods. However, other EOR strategies have been tested in the past and there are currently several active research programs seeking alternatives to increase the recovery factor of these mostly light crude-oil reservoirs economically. Although the Permian Basin (west Texas and southeast New Mexico) can be considered mature, its potential for improved oil recovery is still very high. A recent study reports that there is an estimated 30 billion barrels of mobile oil in the Permian Basin, reiterating the strategic importance of EOR technologies for carbonate reservoirs and their impact on US oil production (Nuckols 1992; Xie et al. 2005; Seethepalli et al. 2004; Moritis 2004; Cole 2003; Moritis 2003; Dutton et al. 2004).

Sequestration of carbon dioxide (CO2) in depleted or partially depleted oil reservoirs is an immediate, cost-effective option to reduce CO2 emissions into the atmosphere. Carbon dioxide has been injected into oil reservoirs for the purpose of enhancing oil recovery (EOR). With EOR, the goal is to maximize the oil production by minimizing the use of CO2 while with sequestration, the goal is to maximize the storage of the CO2. During EOR, a significant amount of CO2 may be sequestered in the reservoir. If CO2 emissions are regulated, the EOR process may therefore be able to earn sequestration credits in addition to oil revenues. We develop a theoretical framework that analyzes the co-optimization of oil extraction and CO2 sequestration. The economic analysis takes into account factors such as capture, transportation and recycling costs. This paper discusses the effects of several injection strategies and injection timing on optimization of oil recovery - CO2 storage capacity for a synthetic, three dimensional, heterogeneous reservoir model. A simulation study is completed using a 3-D compositional simulator " ECLIPSE 300?? and an optimization algorithm in order to optimize the net present value of oil recovery and CO2 storage. A number of simulations are studied to achieve comprehensive understanding of the financial performance of coupled CO2 sequestration and EOR projects. The simulations have showed that the projects would be unprofitable for immiscible cases when using costs typical of current CO2 capture from power plants unless there is some form of credit for storage. In contrast, in miscible cases, the projects may be profitable even without considering any CO2 credits and their profitability is further enhanced with possible carbon credits. The results show that innovative reservoir engineering techniques are required for co-optimizing CO2 storage and oil recovery. 1. Introduction CO2 concentration in the atmosphere has drastically increased over the past 250 years from 280 to 380 ppm (Bryant 1997). The major cause of increasing CO2 emissions into the air has been recognized as the dramatic increase in the fossil fuel consumption for energy production. Increasing concentrations of CO2 leads to climate change via enhancing the natural greenhouse effect. Several measures have been suggested to control the problem of increasing CO2 emissions in the air. One of such measures is to decrease carbon intensity of energy production, which means less CO2 per specified amount of produced energy (Forooghi, Hamouda and Eilertsen 2009). CO2 emissions can also be reduced by increasing the share of renewable energies in the energy consumption portfolio. The most promising, immediate option for reducing a large amount of CO2 is, however, the long-term sequestration of CO2 in geological formations. Depleted or mature oil and gas reservoirs, deep saline formations, and unminable coalbeds are usually considered as the most applicable CO2 sequestration formations (Bachu 2003). Geological CO2 storage as the effective option to mitigate atmospheric CO2 emissions has been considered since the 1990's and has been implemented at a large scale for the first time in Norway (Moritis 2002). Oil and gas reservoirs are good candidates for sequestration because industrial experiences already exist for CO2 injection. Regarding economic aspects of the sequestration process, coupled enhanced oil recovery (EOR) and sequestration processes have advantages since the increased oil recovery will offset some of the costs of CO2 sequestration process. The Weyburn CO2 sequestration and EOR project is an example of commercial coupled CO2 EOR and sequestration process, which has shown a great success in terms of both objectives of the project (Malik and Islam 2000). In this project, carbon dioxide is transported from the North Dakota coalgasification plant through pipelines and is injected into the Weyburn oil field.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200316, “Joint Optimization of Well Completions and Controls for CO2 Enhanced Oil Recovery and Storage,” by Bailian Chen, SPE, and Rajesh Pawar, Los Alamos National Laboratory, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa 18–22 April. The paper has not been peer reviewed. Carbon dioxide (CO2) storage through CO2 enhanced oil recovery (EOR) has been considered an option for larger-scale deployment of CO2 storage because of the economic benefits of oil recovery, 45Q tax credits, and the use of existing infrastructure. The complete paper investigates how optimal reservoir management and operation strategies can be used to optimize both CO2 storage and oil recovery. Results of the authors’ study showed that joint optimization of well completions and well controls can achieve a higher final net present value (NPV) than that obtained from the optimization of well controls only. Introduction In CO2 EOR associated with storage processes, poorly designed well-operating conditions or completions can lead to low oil recovery factors and suboptimal CO2 storage. Co-optimization of oil production and CO2 storage has been recognized as a feasible technique to maximize benefit in terms of oil production and CO2 storage tax credit. To the best of the authors’ knowledge, settings for well completions have not been considered as optimization variables in a CO2 EOR and storage co-optimization process. The objective of this study is to conduct joint optimization of well completions and controls [well rates or bottomhole pressures (BHP)] that maximize life-cycle NPV in CO2 EOR and storage processes and demonstrate the superiority of joint optimization over well-control-only optimization. Optimization Problem In this study, the optimization problem considered is the joint optimization of well completions and well controls for a CO2 EOR and storage process. The mathematical process behind this determination is detailed in the complete paper. The optimization problem was focused on jointly estimating the well completions (i.e., fraction of injection/production well perforations in each reservoir layer) and CO2 injection and oil-production controls that maximize NPV in a CO2 EOR and storage operation. The authors used a newly developed stochastic simplex approximate gradient algorithm to solve the optimization problem. The performance of the joint optimization approach was compared with the performance of the well-control-only optimization approach. In addition, the performance of the co-optimization of CO2 storage and oil-recovery approach was compared with that of the maximization of only-CO2-storage and only-oil-recovery approaches.

Improved oil recovery methods are essential to fulfill the world’s energy needs and maximize oil recovery from older oilfields. In order to boost the viscosity of injection water and enhance sweep efficiency, high molecular weight polymers, such as partially hydrolyzed polyacrylamides (HPAMs) are injected in a technique known as polymer flooding, which is a potential EOR technique. However, obstacles like excessive salinity and high temperatures can make polymer flooding less successful. In order to increase viscosity, thermal stability, and oil recovery results, recent research has concentrated on improving this approach by introducing nanoparticles, especially multi-walled carbon nanotubes (MWCNTs). In order to investigate possible EOR applications, this work examines the rheological characteristics and chemical interactions of an HPAM-MWCNT polymer nanofluid system. According to rheological experiments, the nanofluid shows non-Newtonian, shear-thinning behavior, with viscosity rising with increasing MWCNT concentration because of network stability effects and physical entanglement. The effective functionalization of MWCNTs with carboxyl groups and their interaction with HPAM polymer chains, which resulted in the creation of new chemical bonds and the observed increase in viscosity, are confirmed by Fourier-transform infrared (FTIR) spectroscopy. These results imply that MWCNT nanoparticles might physically entangle polymer chains to limit their mobility, hence limiting polymer breakdown at high temperatures. Viscosity and thermal stability improvements that have been found suggest that MWCNT-polymer nanofluids may be able to increase oil recovery rates and get around some of the drawbacks of conventional polymer flooding techniques. MWCNTs are attractive options for viscosity modification and temperature stabilization in EOR applications because of their special qualities, which include a large surface area and robust interaction capabilities.