Ultra-low Permeability Reservoirs Research Articles

Study on Sedimentary Facies and Reservoir in Taiyuan Formation in Qingshimao area

Recent exploration results show that there is an industrial airflow in Taiyuan Formation in Qingshimao area of Ordos Basin. The Marine quartz sandstone reservoir developed in Taiyuan Formation is the target reservoir after He 8 and Shan 1 Members in Qingshimao area. In order to study the sedimentary facies characteristics of Taiyuan Formation in Qingshimao area, this paper analyzed the well logging, single well facies and connected well facies on the basis of core observation. In addition, using the data of casting thin section, scanning electron microscope and cathode luminescence, the response relationship between sedimentary facies and well logging facies is established, thus the sedimentary facies in the study area is divided and the reservoir characteristic is studied. The results show that the Taiyuan Formation mainly developed barrier coastal sedimentary facies, which can be subdivided into four sub-facies: marsh, tidal flat, barrier island and lagoon. Lithic quartz sandstone is mainly developed in Taiyuan Formation, followed by quartz sandstone and lithic sandstone. The reservoir space types include intergranular pores, dissolved pores, intergranular pores and micro-fractures. Extra-ultra-low porosity and ultra-low permeability reservoir is developed in Taiyuan Formation in study area.

Dramatically Enhancing Oil Recovery via High-Efficient Re-Fracturing Horizontal Wells in Ultra-Low Permeability Reservoirs: A Case Study in HQ Oilfield, Ordos Basin, China

The ultra-low permeability oil reservoir in the HQ oilfield within the Ordos Basin exemplifies a classic “three-low” oil reservoir characterized by low pressure, low permeability, and low abundance. Upon the commencement of oil well production, substantial initial production decline and inadequate pressure maintenance levels are encountered. Consequently, these wells commonly face persistent low production issues resulting from ineffective water injection. Currently, the available technical approaches for repeated stimulation of such wells to enhance production and efficiency are limited, thereby restricting the effective utilization of the remaining oil reserves. In response to this challenge, this article presents an innovative technology tailored for high-efficiency re-fracturing to improve oil recovery in ultra-low permeability reservoirs. Grounded in the theory of multiple flow couplings and volume development, this technology introduces a novel integrated process encompassing seepage field reconstruction, fracturing, and oil displacement. This comprehensive approach culminates in an integrated energy replenishment methodology applicable throughout the entire reservoir’s life cycle. The proposed technology materializes a novel development method for ultra-low permeability reservoirs, centered on the principles of “seepage field reconstruction, integration of fracturing and oil displacement, multi-mode energy replenishment, and all-round displacement”. This integrated strategy ensures the efficient development of ultra-low permeability reservoirs. The successful implementation of this technology in the HQ oilfield is a notable achievement. Notably, the daily oil production of directional wells and horizontal wells significantly increased from 0.5 tons and 1.8 tons to 2.4 tons and more than 10 tons, respectively. Furthermore, the estimated ultimate recovery rate witnessed a substantial improvement from 5.2% to 17.3%. These compelling results underscore the potential of this technology in revitalizing the production of low-yield wells in ultra-low permeability reservoirs.

Optimization of Gas-Flooding Fracturing Development in Ultra-Low Permeability Reservoirs

Optimization of Gas-Flooding Fracturing Development in Ultra-Low Permeability Reservoirs

Pulse power plasma stimulation: A technique for waterless fracturing, enhancing the near wellbore permeability, and increasing the EUR of unconventional reservoirs

The inherent characteristic of unconventional and ultra-low permeability reservoirs is a small drainage area that negatively affects the production rate and ultimate recovery (UR). Drilling horizontal wells, coupled with a stimulation process such as hydraulic fracturing, are applied to wells in these reservoirs to enhance well productivity. Although hydraulic fracturing has been the most famous stimulation technique in these reservoirs and has contributed to the increased US oil and gas production during the last several years, other stimulation techniques may be competitive with (or complementary to) hydraulic fracturing. This is because the main contribution to production in these reservoirs would be from complex fracture networks (often micro-cracks) combined with enhanced formation permeability rather than the classical two-wing fractures. Hence, a near-wellbore stimulation technique for improving the permeability of these reservoirs by activating the existing natural fractures and creating secondary microfractures would be highly desired. This paper investigates the pulse plasma stimulation technique to investigate such an approach of waterless stimulation/fracturing that creates multiple fractures and is also a permeability enhancement method. In this method, plasma is generated by discharging a high voltage and high current electrical energy in a very short time into two electrodes submerged in a wellbore filled with aqueous fluid. This study is divided into two sections. The first part presents experimental and numerical examples of stimulation/fracturing induced by pulse plasma in different rocks. Several parameters, including the effect of discharge with and without wire, input energy, confining stress, and rock type, on the induced fractures are studied. The second part uses the insights and results from the first part to numerically investigate pulse plasma's effects on production. Measurement of the formation permeability around the generated fractures indicated that the shock wave generated multiple fractures and increased the rock permeability by more than one or two orders of magnitude. The second part of the numerical section discusses the increased estimated rate and ultimate recovery (EUR) of horizontal wellbores due to fracturing and modified permeability resulting from pulse plasma. We present a sensitivity analysis on the magnitude and extent of the improved permeability region and its impact on EUR.

Preparation of carbon-based active nanofluids with temperature and salt resistance for enhanced oil recovery

The abundant hydrophilic surface groups endow carbon-based nanoparticles (CDs) with intrinsic great dispersibility, however, the strong hydrophilicity limits the oil–water interface activity, restraining the performance in enhanced oil recovery. Developing CDs with simultaneously ultra-small sizes, high temperature and salt tolerance, as well as superior interfacial activity is of great significance. In this work, CDs with the size of 3.3 nm and excellent temperature and salt resistance were prepared by hydrothermal reaction, using citric acid (CA) and ethylenediamine (EDA) as precursors. Carboxyl ether carboxylate-6Na (APEC-6Na) was selected as the compound agent to construct carbon-based active nanofluids (CANs) with excellent oil–water and oil-solid interfacial activities. CANs can reduce the oil–water interfacial tension to 8.9 × 10-4 mN m−1, withstand a temperature up to 90°C and a salinity up to 6.3 × 104 mg·L-1. Even at the highest tolerant salinity, the underwater oil contact angle of 155° can be achieved, demonstrating excellent wettability control capability, which could be attributed to the synergistic effect of the compound CANs system. The increase of the contact angle of underwater oil droplets facilitates the coalescence of oil film on the lipophilic surface to form oil droplets. The electrostatic repulsion generated by the adsorption of CDs and APEC-6Na at the oil–water interface and rock surface makes the coalesced oil droplets more easily detached from the rock surface, and the oil film reduction rate exceeds 97.7 % within 24 h. The excellent oil–water and oil-solid interface properties and the structural separation pressure endows CANs with remarkable performance in core displacement experiments. Compared with simulated formation water, CANs can improve the recovery rate by 26.3 %, exhibiting important application value for improving the recovery rate of ultra-low permeability reservoirs.

Experimental study of the influencing factors and mechanisms of the pressure-reduction and augmented injection effect by nanoparticles in ultra-low permeability reservoirs

Nanoparticles (NPs) have gained significant attention as a functional material due to their ability to effectively enhance pressure reduction in injection processes in ultra-low permeability reservoirs. NPs are typically studied in controlled laboratory conditions, and their behavior in real-world, complex environments such as ultra-low permeability reservoirs, is not well understood due to the limited scope of their applications. This study investigates the efficacy and underlying mechanisms of NPs in decreasing injection pressure under various injection conditions (25–85 °C, 10–25 MPa). The results reveal that under optimal injection conditions, NPs effectively reduce injection pressure by a maximum of 22.77% in core experiment. The pressure reduction rate is found to be positively correlated with oil saturation and permeability, and negatively correlated with temperature and salinity. Furthermore, particle image velocimetry (PIV) experiments (25 °C, atmospheric pressure) indicate that the pressure reduction is achieved by NPs through the reduction of wall shear resistance and wettability change. This work has important implications for the design of water injection strategies in ultra-low permeability reservoirs.

Establishing a water baseline for the unconventional gas industry: A multiple environmental isotopes assessment (18O, 2H, 3H, 13C, and 14C) of surface and groundwater in the São Francisco Basin, Brazil

Unconventional hydrocarbon production has become the target of an intensive environmental debate due to the risks it poses to water resources. Fracking, while enabling the extraction of oil and gas from ultra-low permeability reservoirs, also possesses the risk of polluting water systems through failures from hydraulic fracturing and its associated procedures. The need to foster national industrial development with a transitional energy matrix has led Brazil to discuss the environmental suitability before producing its large unconventional reserves. Many studies have highlighted the need for a robust environmental characterization before the development of the unconventional industry. In this sense, multiple environmental isotopes may work as a proxy for identifying water contamination right from the early stages. Environmental isotopes may also be applied to enhance the understanding of the natural geochemical processes intrinsic to a given area. This study presents an environmental isotopes baseline for the groundwater and riverine water systems within the São Francisco Basin, a proven tight gas reservoir in Brazil, in a pre-operational context. δ18O, δ2H, 3H, δ13C, and Δ14C were evaluated in three different seasons in groundwater and surface water samples, along with other auxiliary parameters such as physical-chemical parameters (in situ), major ions, and d-excess. The δ2H and δ18O in surface water shows an upstream → downstream enrichment trend, with some variations suggesting baseflow interactions in the surface water systems. An evaporation line for the study area was defined as δ2H = 4.6903 δ18O + 10.362. δ13C indicates a mutual dissolution of silicates and carbonates in the groundwater system and suggests a group of samples highly related to the recharge areas. Groundwater dating denotes the Serra da Saudade Formation as a modern fractured aquifer with a strong recharge capacity. These findings support stakeholders in environmental monitoring and management of the unconventional gas industry.

Study on Green Nanofluid Profile Control and Displacement of Oil in a Low Permeability Reservoir.

Low permeability reservoirs are characterized by low permeability, small pore throat, strong heterogeneity, and poor injection-production ability. High shale content of the reservoir, strong pressure sensitivity, micropore undersaturation, and significant water-lock effect in water injection development lead to increased fluid seepage resistance. There is an urgent need to adopt physical and chemical methods to supplement energy and improve infiltration efficiency, thereby forming effective methods for increasing the production and efficiency. Aiming at the characteristics of ultralow permeability reservoirs, in this paper, a green and environmental friendly biobased profile control and displacement agent (Bio Nano30) has been developed using noncovalent supramolecular interaction. Physical simulation experiments illustrate the profile control and displacement mechanism of Bio-Nano30. Laboratory experiments and field applications show that good results have been achieved in oil well plugging removal, water well pressure reduction and injection increase, and well group profile control and oil displacement. This research has good application prospects in low permeability heterogeneous reservoirs.

Nanoemulsions stabilized by nonionic surfactants to promote spontaneous imbibition in ultra-low permeability reservoirs: performance evaluation and mechanism study

Nano-emulsions stabilized by nonionic surfactants have the characteristics of ultra-low interfacial tension (IFT) and altered wettability in ultra-low permeability reservoirs. Thus, in this work, a new nanoemulsion is proposed to enhance spontaneous imbibition recovery in ultra-low permeability reservoirs. The nanoemulsion is prepared using n-dodecane, Tween-20, and coconut oil acid diethanolamine n-amyl alcohol. The effects of temperature and salinity on particle size, IFT, and wettability alteration performance of the nanoemulsions were systematically studied. Experimental results show that the particle size of nanoemulsions increases with salinity, and the highest level is up to 100 nm, while an increase in temperature is beneficial to the formation of smaller nanoemulsions. The IFT of the nanoemulsion system can be reduced to an ultra-low level (10–3 mN/m) when the salinity is lower than 50,000 mg/L. As for the wettability alteration property of a nanoemulsion system, an increase in temperature can improve its performance, but variations in salinity seldom have any effects. At 56 °C and 30,000 mg/L salinity, the spontaneous imbibition recovery of 1.00 wt% nanoemulsion can reach 53.8% under the synergistic effect of three mechanisms: extremely small droplet size, excellent wettability alteration performance, and ultra-low IFT. These three mechanisms work together to significantly improve the displacement efficiency of ultra-low-permeability reservoirs.

Research on Refracturing Technology of Ultra-low Permeability Fractured Oilfield

The development of ultra-low permeability reservoir in Daqingzi area, Qian an. With a long period of mining, the number of refractured wells is increasing year by year, but there is no benefit after fracturing. There is an urgent need for low-cost fracturing techniques to make refracturing more cost-effective. In this paper, on the basis of fully understanding reservoir physical properties, in-depth analysis of the major problems facing the refracturing of Daqingzi oilfield, and analysis of refracturing potential. Through field experiment, post-frac analysis and effect evaluation, the refracturing technology route suitable for this area is gradually explored. In this field experiment, the problem of underinjection was solved through the analysis and targeted transformation of injection wells. The average daily injection capacity of a single well was increased, injection pressure was reduced, the formation pressure of surrounding producing wells was restored to the original formation pressure, and the refracturing time of producing wells was reached, and the individual refracturing design of producing wells was carried out. In addition, post-frac analysis and effect evaluation were carried out. The results show that the injection-production relationship of the well group is improved obviously after the measures, the effect of increasing fluid and oil is remarkable, and the average fracturing cost per well is reduced. The new technology of holistic fracturing of injection and producing wells centered on injection well is defined. It provides technical support for increasing production and controlling cost of ultra-low permeability reservoir.

A novel numerical simulation of CO2 immiscible flooding coupled with viscosity and starting pressure gradient modeling in ultra-low permeability reservoir

A novel numerical simulation of CO2 immiscible flooding coupled with viscosity and starting pressure gradient modeling in ultra-low permeability reservoir

Natural fracture mapping and discrete fracture network modeling of Wolfcamp formation in hydraulic fracturing test site phase 1 area, Midland Basin: Fractures from 3D seismic data, image log, and core

Fractures control fluid flow in ultra-low permeability reservoirs due to their much higher permeability. Recognition, mapping, and characterization of both natural and hydraulic fractures at multiple scales are critical to predicting hydrocarbon production in tight rocks, including mudrock. However, this determination is very challenging due to data scarcity, varying data resolutions, and uncertainties in interpretations. In this research, we combined core-identified fractures, image log-identified fractures, and 3D seismic data to analyze natural fracture features of, and construct a discrete fracture network (DFN) model for, the Wolfcamp Formation in the Hydraulic Fracturing Test Site Phase 1 (HFTS-1) project area in the central Midland Basin of the United States. An azimuth-guided, ant-track seismic attribute called VarAntAntPas was developed to recognize natural fractures and extract their seismic discrete planes (SDP) at multiple dip azimuth ranges. The extracted SDPs were then employed to calculate the fracture length, height, and elongation, as well as the dip angle and dip azimuth. This process revealed a limitation of recognizing natural fractures shorter than 600 ft by 3D seismic data due to its resolution. To model fractures shorter than 600 ft, we calculated fracture intensity at different dip azimuths from the VarAntAntPas attributes and combined this variable with fracture dip angle derived from well data and the extracted SDPs. The extracted SDPs for larger fractures (length >600 ft) and the modeled smaller fractures (length <600 ft) were combined to build a DFN model of the Wolfcamp Formation in the HFTS-1 project area. Clearly, the DFN model was built with different ways for two different-size fracture groups. Meanwhile, the discrete fractures in different orientations were built independently and then combined together in the DFN model. Natural fractures predicted by the DFN model were then validated by comparison to fractures identified from core and image logs from two horizonal wells and one slant well in the HFTS-1 project area.

Evaluation of Foam Gel Compound Profile Control and Flooding Technology in Low-Permeability Reservoirs

In the waterflooding development of fractured ultra-low permeability reservoirs, the heterogeneity is becoming increasingly serious. The development of large fracture channels leads to serious water channelling and low recovery, and the effect of conventional profile control is not ideal. This paper proposed gel foam composite profile control and flooding technology to solve the above problems. Herein, the new intelligent gel and foaming agent systems were optimized through laboratory experiments, and their performance was evaluated. The new intelligent gel system has the characteristics of low viscosity, easy preparation, good injection, slow cross-linking, high strength, and long-term effectiveness. The injection parameters were optimized, and the indoor injection scheme was formulated, that is, the optimal injection volumes of gel and foam slugs were 0.3 and 0.6 PV, respectively. The injection sequence of composite slugs was to inject gel slugs first, then foam slugs. The injection mode of air foam slugs was multiple rounds of small slug injection. The final recovery rate in the indoor dual tube oil displacement experiment reached 35.01%, increasing by 23.69%. Furthermore, an oil output increase of 899 t and an average water cut decrease of 5% were acquired in the oil field test. It shows that the injection scheme can effectively improve oil recovery. The gel foam compound profile control and flooding technology herein has good adaptability in similar reservoirs and has good promotion prospects.

DEVELOPMENT OF LOW PERMEABLE RESERVOIRS AT THE PRIOBSKOYE FIELD (WESTERN SIBERIA)

The main problem in the development of the Priobskoye field is the search and implementation of technological solutions for the most efficient development of layers of ultra-low permeable reservoirs. A factor complicating the hydrocarbon production for such facilities is the low impact of flooding. These restrictions lead to high rates of decline in oil production, therefore, the most urgent issue is the search for an up-to-date technological solution aimed at improving the efficiency of field development.&#x0D; This article is devoted to improving the efficiency of the development system in areas with low filtration and capacitance properties. It presents the results of research on the study of the construction of horizontal wells longitudinally and transversely to regional stress, followed by multi-stage hydraulic fracturing in the conditions of one of the largest fields in Western Siberia. The results of the research made it possible to determine an effective strategy for designing development systems in future areas.&#x0D; The relevance of this work: the demand for the extraction of hard-to-recover reserves from reservoirs characterized by low permeability.

Characterization of Extra Low-Permeability Conglomerate Reservoir and Analysis of Three-Phase Seepage Law

The micro distribution of residual oil in low-permeability sandstone reservoirs is closely related to pore structure, and the differences in pore structure often determine the reservoir’s productivity and development effectiveness from a macro perspective. On the basis of in-depth research, this paper analyzes the distribution law of the remaining microscopic oil, establishes the digital core multi-stage pore network modeling of the strongly sorted heterogeneous conglomerate reservoir in the Lower Wuerhe Formation of Block 8 of the Karamay Oilfield, the three-phase seepage simulation method considering the release of dissolved gas, and the three-phase permeability curve test. The research results are as follows: (1) Conventional physical property analysis shows that the permeability of core samples exhibits an inverse rhythmic distribution with layer depth. (2) CT core analysis and mercury injection experiments indicate that the area with porosity ranging from 9% to 21% accounts for 79% and is the main seepage channel area. Larger pores play an important role in seepage. (3) Through comparative experiments on cores with different permeability, it was found that the degassing phenomenon of low-permeability rock samples is more severe. In the actual process of reservoir development, it is necessary to reasonably handle the impact of water injection on development effectiveness, select appropriate water injection methods and cycles, and avoid premature water breakthrough in ultra low-permeability reservoirs.

Quantifying the influence of fracture parameters on flow behavior and pressure propagation in complex networks of discrete fractures within low-permeability reservoirs

Fractures in low and ultra-low permeability reservoirs create a complex network, affecting fluid flow patterns and pressure propagation. However, limited research exists on fluid flow patterns and the impact of fracture properties on pressure within these networks. To address this, we introduce fracture shadow area and fracture penetration ratio concepts derived from studying single fracture reservoirs. Using a sophisticated model of a complex fracture network, we analyze how various fracture properties influence fluid flow patterns and reservoir pressure. Fractures are classified into five categories based on the development level. Through orthogonal experiments and multiple regression methods, we derive a formula that quantifies the pressure influence. We find that longer and denser cracks enhance fluid exchange and pressure propagation capacity. Moreover, increasing crack opening expands the area of pressure drop. Notably, fractures aligned with pressure propagation significantly decrease reservoir pressure. The hierarchical sequence of crack traits with the greatest influence is identified as crack length, crack opening, crack density, and crack angle. Our findings shed light on the intricate relationship between fracture properties and pressure dynamics.

Characteristics and controlling factors of petroliferous reservoirs in the Permian Lower Urho Formation, western Mahu Slope, Junggar Basin, Northwest China

Numerous hydrocarbon discoveries in the lower Urho Formation of the western Mahu Slope, China indicate that potential petroliferous reservoirs may exist in that region. However, issues concerning the reservoir characteristics and associated controlling factors remain unclear. To determine the characteristics and associated controlling factors of these reservoirs, we conducted integrated analysis of the 3D seismic volume, wireline logs, mud logs, cores, thin sections, porosity, and permeability data. Several lithologic types were identified from the core, casting thin section, and mud-log data (including mudstone, sandstone, gravity flow-derived glutenite, transitional glutenite, and traction flow-derived glutenite). The contact relationship was determined from the casting thin section data, and it included point contact and lineal contact, followed by concavo-convex contact and suture contact. We found the dominant pore types were found to be intergranular pores, followed by intragranular pores, intramatrix pores, and cracks. The porosity and permeability data reveal that sandstone and traction flow-derived glutenite commonly form low-porosity and low-permeability reservoirs, whereas transitional glutenite commonly forms low-porosity and ultralow-permeability reservoirs and gravity flow-derived glutenite generally forms low-porosity and ultralow-permeability reservoirs. This integrated analysis finds that tectonic movements and a sedimentary environment control the physical properties of the reservoirs. The tectonic movements control reservoir characteristics through thrust fault systems and large-scale provenance, and the sedimentary environment controls reservoir characteristics via facies distribution and lacustrine fluctuation. The insights gained from this study can provide knowledge about the characteristics and associated controlling factors of the reservoirs in the Permian Lower Urho Formation within the western Junggar Basin. These insights can also benefit petroleum reserve and hydrocarbon production exploration in the study area and further petroleum exploration in other areas with similar sedimentary/tectonic settings.

High pressure air injection in ultra-low permeability reservoirs: Effects of physical and chemical reactions on oil recovery

This research aims to investigate the effects of physical and chemical reactions on oil recovery during high-pressure air injection (HPAI) in ultra-low permeability reservoirs. The oxidation reaction characteristics of dead oil were investigated using thermal analysis experiments and oxidation tube experiments. Additionally, pressure-volume-temperature (PVT) analysis was employed to simulate the physical and chemical reactions between air and live oil under formation conditions. The results indicated that the fuel deposition (FD) stage exhibited less prominence in light oil due to its lower content of resins and asphaltenes. Additionally, the presence of cuttings impeded the volatilization of lighter components during low-temperature oxidation (LTO) stage, effectively storing fuel required for subsequent high-temperature oxidation (HTO) stage, consequently facilitating a direct transition from LTO to HTO. Notably, the debris derived from the ultra-low permeability reservoirs possesses an enlarged specific surface area, facilitating enhanced contact between the oil and oxygen. This heightened contact effectively reduces the activation energy required for the LTO stage by an appreciable 22.9 kJ/mol. Furthermore, the PVT experiments reveals a quadratic relationship between pressure and viscosity, while a cubic relationship exists between pressure and the expansion rate of crude oil. Moreover, the thermal effects of oxidation reactions and the dissolution of the gas phase have been found to exert a more substantial influence on reducing oil viscosity, in contrast to the oxygen addition reaction and the extraction of lighter components, which have a minor influence on increasing oil viscosity. Lastly, in the context of developing HPAI techniques for ultra-low permeability reservoirs, optimizing the gas injection rate emerges as a viable strategy to effectively enhance oil recovery, provided that the occurrence of gas channeling is effectively mitigated.

Experimental study on stress-dependent multiphase flow in ultra-low permeability sandstone during CO2 flooding based on LF-NMR

Oil production performance in the unconventional reservoirs is significantly affected by the flooding agent and occurrence environment. In this study, the in-situ stress and displacement pressure effects are considered, the response of CO2/Oil and pore structure was monitored by online low field nuclear magnetic resonance (LF-NMR). The results show that the pore structure was composed of adsorption pore (AP＜3 m s), percolation pore (3 m s＜PP＜30 m s), and migration pore (30 m s＜MP). The stress sensitivity of adsorption pore is more obvious than that of percolation pore and gradually weakened responding to the increase of in-situ stress. The increased in-situ stress narrowed and closured pore throats and limited the migration of CO2/Oil, and the pore transformed from gas-channeling type into homogeneous type and the hydraulic conductivity of CO2 and oil decreased non-linearly responding to the pore shrinkage. The percolation pore and migration pore dominate the oil recovery, and the decreased MP resulted in the non-linearly and dynamic reduction of oil recovery. The higher relative permeability was presented and the end-point oil saturation non-linearly increased with the increasing in-situ stress. The increased displacement pressure effectively improved the oil recovery and dynamic gas channeling, and the incremental oil recovery was primarily contributed by the PP and MP due to the increased CO2 swept area. The positive effect of displacement pressure on oil recovery gradually reduced with the increase of in-situ stress. The findings provide a significant insight on the application of CO2-EOR in ultra-low permeability reservoirs.

Preparation and application of modified carbon black nanofluid as a novel flooding system in ultralow permeability reservoirs

Conventional flooding systems have very low recovery rates in ultralow permeability reservoirs in virtue of the characteristics of high injection pressure, low permeability and small pores in such reservoirs. In this study, a novel surface-modified carbon black (MCB) nanofluid was prepared as a flooding system to resolve this problem. The preparation process of MCB nanoparticles was divided into three stages: (1) oxidation of carbon black (CB) nanoparticles, (2) acyl chlorination of oxidized carbon black (OCB) nanoparticles and (3) grafting of active groups onto the surface of acyl chloride carbon black (ACB) nanoparticles, and the main synthesis conditions, such as modifier concentration and grafting temperature, were optimized. X-ray photoelectron spectroscopy (XPS) and X-ray diffraction (XRD) analysis indicated that the factional groups were successfully introduced onto the surface of CB nanoparticles, and the crystallinity of CB nanoparticles decreased gradually during the reaction process. Additionally, the dispersed stability, temperature resistance, salinity tolerance, wettability alteration and oil stripping ability were evaluated so as to obtain the performance of the MCB nanofluid. The results show that the average size of the MCB nanoparticles is approximately 72.3 nm, and the dispersed stability of the MCB nanofluid is much better than that of the CB nanofluid. Compared with the carbon black (CB) nanofluid, the MCB nanofluid shows stronger wettability alteration and oil stripping ability, and can also withstand the high temperature and high salt environment of oil reservoirs. 1 PV of MCB nanofluid can enhance oil recovery by 28.9%. Furthermore, the enhanced oil recovery (EOR) mechanisms for the MCB nanofluid are revealed through analysis of low oil–water IFT (IFT), wettability alteration and Wasan’s theory of structural disjoining pressure. This new type of environment-friendly flooding system injects vitality into the development of ultralow permeability reservoirs.