Small Pore Throats Research Articles

Experimental study on the dynamic threshold pressure gradient of high water-bearing tight sandstone gas reservoir

Tight sandstone water-bearing gas reservoirs typically exhibit low porosity and low permeability, with reservoir rocks characterized by complex pore structures, often featuring micron-scale or smaller pore throats. This intricate reservoir structure significantly restricts fluid flow within the reservoir, necessitating a certain threshold pressure gradient (TPG) to be overcome before flow can commence. This study focuses on the Ordos Basin and explores the influence of high water content tight sandstone gas reservoirs on TPG under different water saturation and formation pressure conditions through experiments. A mathematical model of TPG is established using multiple linear regression method. The results show that TPG is primarily affected by water saturation, followed by formation pressure. As the water saturation increases, the TPG of the core decreases, and the change becomes more pronounced when the water saturation exceeds 50%. As formation pressure increases, the weakening of the slippage effect in gas molecules leads to TPG stabilization, especially when local pressure exceeds 25.0 MPa. The research also shows that low-permeability cores exhibit greater TPG variation with pressure changes, while high-permeability cores remain more stable. A mathematical model was developed and validated to predict TPG based on permeability, water saturation, and formation pressure. These findings highlight the need to monitor formation water content during tight sandstone gas reservoir development to optimize production strategies, providing valuable insights for improving reservoir management and guiding future research.

Preparation and performance evaluation of a low‐damage fracturing fluid for unconventional reservoirs

AbstractThe characteristics of tight matrix, underdeveloped natural fractures, small pore throat radius, poor pore connectivity, and abundant clay minerals result in a high potential for damage to the tight sandstone reservoirs of the Shaximiao Formation in the Qiulin Block in the Sichuan Basin. In order to reduce the retention damage caused by fracturing fluid to the tight sandstone reservoir, a low damage fracturing fluid system applicable to the target reservoir is developed in this work, and the indoor performance meets the requirements of on‐site fracturing operation. A low‐damage, heat‐resistant, shear‐stable amphiphilic polyacrylamide (PAAD) was prepared by free radical polymerization in aqueous solution using acrylamide, acrylic acid, and methacryloyloyloxyethyl dimethyloctadecyl ammonium bromide (DM18) as the monomers. The amphoteric polyacrylamide was characterized by Fourier infrared spectroscopy, nuclear magnetic resonance spectroscopy (1H NMR), light scattering molecular weight determination, and thermogravimetric analysis. Fracturing fluids were formulated with the amphiphilic hydrophobic associative polymer PAAD as a drag‐reducing agent, the fluorine‐containing and nonionic complex surfactant FD1 as a clean‐up additive, CT10‐4B as a bactericide and CT1‐12 as an emulsion breaker. The fracturing fluid formulation was preferred, and the performance of the fracturing fluid was evaluated in terms of temperature resistance and shear resistance, drag reduction, anti‐expansion, and core damage. The fracturing fluid showed good temperature and shear resistance, with a viscosity retention of 58.4% at 120°C and 170 s−1 shear for 1 h. At a loading of 0.1%, the drag reduction rate reaches 72.3%, the anti‐expansion rate of the gel‐breaking fluid is 86.04%, and the damage rate to the tight sandstone core is 16.25%. The results show that the fracturing fluid has good heat resistance and shear stability, as well as low damage and good resistance reduction and anti‐expansion properties. This work can provide new strategies for designing polymeric fracturing fluids with low damage, good heat resistance and shear stability.

Study on the Contribution of Different Pore Throat Sizes to Oil Displacement Efficiency in Fracture-Pore Tight Sandstone Reservoir

The pore throat and fracture system of tight sandstone reservoir are complex, the reservoir is highly heterogeneous, and the production often decreases rapidly, the development degree is low, and the development effect of water injection is poor. CO2 injection is an important means to supplement formation energy and achieve efficient reservoir development in tight reservoirs. Based on nuclear magnetic resonance technology (NMR) and high temperature and high pressure physical flow simulation experiment system, the contribution of different scales of pore throat and fracture to the improvement of oil recovery in different phases of CO2 -crude oil system is studied. The results show that the contribution of mesopores, macropores and fractures to oil displacement efficiency in the supercritical CO2 displacement stage reaches 74.58%. In immiscible CO2 displacement stage, the contribution of micropores, small pores and medium pores to oil displacement efficiency reached 73.27%. In the miscible CO2 displacement stage, the contribution of micropores and small pores to oil displacement efficiency reached 52.32%. In the supercritical CO2 displacement stage, the contribution of oil displacement efficiency is mainly provided by macropore throats and fractures. The contribution of immiscible and miscible CO2 displacement stage to oil displacement efficiency mainly comes from small pore throat with smaller scale.

Fractal research on pores in oil and gas reservoirs - Inspirations from over 700 high pressure mercury injection experiments

Pore fractal has now become an important research method to study reservoir pore heterogeneity and complexity, and is widely used in unconventional reservoir research. However, its guiding significance for reservoir research and the relationship between fractal dimension and reservoir pore structure parameters are not yet clear. This undoubtedly hinders the further development of fractal in reservoir research. This time, comprehensive research, including pore fractals, was conducted on over 700 high-pressure mercury injection experiments, providing guidance for reservoir pore fractal research. The research results indicate that there are significant differences in the application of fractals in different oil fields. Generally, the curves of high-pressure mercury injection experiments present 1–4 segment fractals, among which the 2 and 3 segment fractals are the most common, and the 4 segment fractals are the least common. There is a correlation between the number of the fractal segments with permeability and pore throat sorting coefficient. The lower the permeability, the more obvious the multi-segment fractal features. The more fractal segments, the greater the fractal dimension corresponding to each segment. The number of fractal segments can characterize the distribution of reservoir pore size. The fractal dimension of large pore-throats is greater than that of small pore-throats. On the whole, there is a negative correlation between fractal dimension and permeability, porosity, and pore throat radius. But this correlation is unstable in different oilfields. And the average value of the overall correlation coefficient is only about 0.5. Different fractal segments in a multi-segment fractal represent different types of pores. The application of pore fractal dimension needs to be combined with pore types.

Effect of Anionic Surfactants on the Oil-Water-Rock Interactions by an Improved Washburn Method.

The complex and variable structure of subsurface oil reservoirs as well as the small pore throat size of reservoirs make it extremely important to investigate the effect of oil-water-rock interactions for enhancing oil recovery. In this paper, the powder wettability of oil sand with different polar solvents was investigated using the improved Washburn capillary rise method, and the surface free energy of oil sand was calculated in combination with the OWRK method. In addition, the wettability of anionic surfactants HABS and PS solutions on the surface of oil sand was determined, and it showed that their wetting rates showed different trends after CMC (critical micelle concentration). The C×cosθ value of HABS decreased significantly with increasing concentration, whereas PS showed little changes. This may be related to the aggregate structure formed by HABS on the oil sand surface. Meanwhile, the interfacial free energy between crude oil and oil sand was obtained by crude oil-to-oil sand wetting experiments, and found that the wetting rate of crude oil to oil sand was much lower than that of solvents and surfactants. In combination with the above results and the oil-water interfacial tension (IFT), the oil-water-rock three-phase contact angle and the work of adhesion between the crude oil and the solid were obtained by Young's equation. From the three-phase contact angle results, it can be found that the contact angle values of both HABS and PS are obviously higher than that of the simulated water, and both HABS and PS have the ability to significantly reduce the work of adhesion, which shows a strong ability to strip the oil film on the surface of the solid. The research results of this paper are helpful to understand the oil displacement mechanism of chemical flooding in reservoir pores, which is of great significance for improving oil recovery.

Influence of reservoir physical properties on guar gum fracturing fluid damage in unconventional tight reservoirs

Solid phase residue, fracturing fluid filtration, and incomplete backflow during hydraulic fracturing can easily cause damage to tight sandstone reservoir. Thus, it is necessary to explore the relationship between the physical properties of tight reservoirs and damage caused by fracturing fluids. Based on the identification of reservoir physical properties, the relationship between reservoir physical properties and fracturing fluid damage was studied by core displacement, computerized tomography, and nuclear magnetic resonance (NMR). The results show that the higher the clay mineral content is, the denser the formed core is, and the corresponding core porosity and permeability are lower. When the permeability and porosity of the rock core are relatively high, the overall radius of the pore throat in the rock core shifts to the left under the action of the gel breaking fracturing fluid, showing a decreasing trend. However, when the permeability and porosity of the rock core are relatively low, the frequency peak of the smaller size of the pore throat in the rock core under the action of the gel breaking fracturing fluid increases upwards. The corresponding core permeability decline rate of the two types of tight sandstone reservoirs is 9.91%–8.78% and 15.85%–14.74%. The porosity decline rates are 5.53%–5.84% and 10.40%–9.94%. According to NMR results, it is speculated that under the action of gel breaking fracturing fluid, the small pore throats in the rock core are blocked or even disappear, while the proportion of smaller pore throats increases and the proportion of larger pore throats decreases. The results of this study provide theoretical reference for reservoir protection during the fracturing process of tight sandstone reservoirs.

Effect of thermal maturation and organic matter content on oil shale fracturing

The Pabdeh Formation represents organic matter enrichment in some oil fields, which can be considered a source rock. This study is based on the Rock–Eval, Iatroscan, and electron microscopy imaging results before and after heating the samples. We discovered this immature shale that undergoes burial and diagenesis, in which organic matter is converted into hydrocarbons. Primary migration is the process that transports hydrocarbons in the source rock. We investigated this phenomenon by developing a model that simulates hydrocarbon generation and fluid pressure during kerogen-to-hydrocarbon conversion. Microfractures initially formed at the tip/edge of kerogen and were filled with hydrocarbons, but as catagenesis progressed, the pressure caused by the volume increase of kerogen decreased due to hydrocarbon release. The transformation of solid kerogen into low-density bitumen/oil increased the pressure, leading to the development of damage zones in the source rock. The Pabdeh Formation’s small porethroats hindered effective expulsion, causing an increase in pore fluid pressure inside the initial microfractures. The stress accumulated due to hydrocarbon production, reaching the rock’s fracture strength, further contributed to damage zone development. During the expansion process, microfractures preferentially grew in low-strength pathways such as lithology changes, laminae boundaries, and pre-existing microfractures. When the porous pressure created by each kerogen overlapped, individual microfractures interconnected, forming a network of microfractures within the source rock. This research sheds light on the complex interplay between temperature, hydrocarbon generation, and the development of expulsion fractures in the Pabdeh Formation, providing valuable insights for understanding and optimizing hydrocarbon extraction in similar geological settings.

Using X-ray computed tomography and pore-scale numerical modeling to study the role of heterogeneous rock surface wettability on hydrogen-brine two-phase flow in underground hydrogen storage

Underground hydrogen storage (UHS) is receiving increasing attention to address the challenges in hydrogen storage. A crucial aspect of UHS is understanding the transport of hydrogen in subsurface porous media. In this work, hydrogen core flooding experiments were conducted in a sandstone sample and then the pore-scale distribution of hydrogen and brine was visualized using high-resolution X-ray micro-computed tomography (micro-CT). After CT image processing, we measured the surface contact angles (CAs) on rock surfaces and found that the measured CAs followed a log-normal distribution. To investigate the influence of rock surface wettability on the transport properties in the hydrogen-brine-sandstone system, the lattice Boltzmann (LB) method was used to simulate two-phase flows with different surface CA distributions; hydrogen-brine relative permeability and capillary pressure curves through the primary drainage, imbibition, and secondary drainage processes were obtained by LB simulations. X-ray CT scanning showed that hydrogen resided in both large pores and small pores and pore throats after the primary drainage process (i.e., hydrogen displacing brine), whereas after the imbibition process (i.e., brine displacing hydrogen) hydrogen stayed primarily in large pores where the capillary pressure barriers were low. The LB two-phase flow modeling illustrated that water’s relative permeability increased whereas hydrogen’s relative permeability decreased when the core flooding moved from primary drainage to imbibition; in contrast, when the core flooding moved from imbibition to secondary drainage, water’s relative permeability decreased whereas hydrogen’s relative permeability increased. Decreasing the surface CA increased the capillary pressure and reduced the hydrogen residual rate, which indicates high hydrogen retrievability and thus is favorable for UHS practice. The change in CA’s standard deviation did not cause noticeable changes in water’s relative permeability curves, whereas it resulted in noticeable changes in hydrogen’s relative permeability curves. This work is the first study that utilizes X-ray micro-CT scanning and pore-scale multiphase flow modeling to quantitatively and comprehensively investigate hydrogen-brine two-phase flow properties under different rock surface wettability distributions. The research findings from this study will advance the understanding of hydrogen transport in an underground storage system and provide essential data for large-scale field studies in UHS.

Study on time-varying characteristics and flow behavior of microencapsulated polymer

Due to the challenges posed by high injection pressure and significant viscosity shear loss, conventional polymer flooding methods are unable to effectively meet the urgent demand for enhanced oil recovery in medium- and low-permeability reservoirs. Microencapsulated polymer flooding is a promising solution to address the aforementioned challenges due to its advantages of easy wellbore injection, shear resistance, and delayed thickening. However, there is a lack of research on the release behavior and time-dependent characteristics of microencapsulated polymer and its impact on flow behavior in reservoirs. To address this gap, we conducted a series of experiments, including thermal stability tests, microfluidic chip experiments, and micro-scale oil displacement experiments, to reveal the time-varying behavior generated by the triggered release of microencapsulated polymers. The results showed that microencapsulated polymer can be fully triggered after 8 days of aging at 85 °C, with a viscosity exceeding the initial viscosity by more than 25 times. The release mechanism of the polymer aligned with the Ritger-Peppas model, transitioning from super Case-II transport to anomalous transport, and finally to Fickian diffusion with increasing temperature. During the triggering process, the presence of particles stabilized shear and improved oil displacement, particularly in small pore throats. Higher triggering degrees of the solution resulted in greater flow resistance within the microchannel, effectively suppressing fluid fingering. The oil displacement effectiveness of fully triggered microencapsulated polymer was comparable to that of conventional polymers. This study provides insights into the flow behavior of microencapsulated polymer at a microscopic level, offering valuable references for its application in the field.

Utilizing Differences in Mercury Injection Capillary Pressure and Nuclear Magnetic Resonance Pore Size Distributions for Enhanced Rock Quality Evaluation: A Winland-Style Approach with Physical Meaning

Pore structure is a fundamental parameter in determining the hydrocarbon storage capacity and flow characteristics of a reservoir. Mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) are two commonly utilized techniques for characterizing rock pore structures. However, current studies indicate that disparities in testing methodologies due to distinct physical characteristics lead to a partial misalignment in pore size distributions. We conducted MICP (dynamic) and NMR (static) experiments on eight tight sandstone and eight shale samples and proposed a method to utilize information from the differences in MICP and NMR pore size distributions, aiming to enhance the accuracy of rock quality analysis. We observed that in rock cores where large pores are interconnected with smaller pore throats, MICP tends to overestimate the proportion of these smaller pores and underestimate the larger ones. Furthermore, we integrated information from both dynamic and static experimental processes based on physical significance and found that the fitting accuracy of the newly proposed method is superior to the Winland r35 equation. Compared to the Winland r35 equation, our new method significantly improves fitting accuracy, increasing the R-squared value from 0.46 to 0.93 in sandstones and from 0.80 to 0.87 in shales. This represents a potential high-precision, comprehensive tool for rock quality analysis, offering a new perspective for an in-depth understanding of rock properties.

A New Model for Predicting Permeability of Chang 7 Tight Sandstone Based on Fractal Characteristics from High-Pressure Mercury Injection

Accurately predicting permeability is important to elucidate the fluid mobility and development potential of tight reservoirs. However, for tight sandstones with the same porosity, permeability can change by nearly three orders of magnitude, which greatly increases the difficulty of permeability prediction. In this paper, we performed casting thin section, scanning electron microscopy and high-pressure mercury injection experiments to analyze the influence of pore structure parameters and fractal dimensions on the permeability of Chang 7 tight sandstones. Furthermore, the key parameters affecting the permeability were optimized, and a new permeability prediction model was established. The results show that the pore throat structure of Chang 7 tight sandstone exhibits three-stage fractal characteristics. Thus, the pore throat structure was divided into large pore throat, medium pore throat and small pore throat. The large pore throat reflects the microfracture system, whose fractal dimension was distributed above 2.99, indicating that the heterogeneity of the large pore throat was the strongest. The medium pore throat is dominated by the conventional pore throat system, and its fractal dimension ranged from 2.378 to 2.997. Small pore throats are mainly composed of the tree-shaped pore throat system, and its fractal dimension varied from 2.652 to 2.870. The medium pore throat volume and its fractal dimension were key factors affecting the permeability of Chang 7 tight sandstones. A new permeability prediction model was established based on the medium pore throat volume and its fractal dimension. Compared to other models, the prediction results of the new model are the best according to the analysis of root mean square value, average absolute percentage error and correlation coefficient. These results indicate that the permeability of tight sandstones can be accurately predicted using mesopore throat volume and fractal dimension.

Study the effect of cohesion on fine particle transportation through a pore doublet model: A CFD-DEM study

This research delves into the transportation of micro-sized particles within a doublet pore model featuring two distinct pore throat sizes. To simulate a two-phase particle-fluid suspension, the CFD-DEM method is employed, combining the Navier-Stokes equation with Newton's second law of particle motion. Cohesion forces between particles and pore throats are characterized using the Simplified Johnson-Kendall-Roberts (SJKR) contact model, which is applied in our simulation to identify locations of agglomerations. Results reveal that altering cohesive energy density, from 10,000 Jm3 to 100,000 Jm3, significantly increases the likelihood of agglomeration in the smaller pore throat. It becomes evident that areas in close proximity to the throats are the most prone to particle agglomerations, leading to pressure drops over time. The formation of particle clusters within the pore throats intensifies with both an increase in the number of particles and fluid velocity from 0.001ms to 0.01ms. Nevertheless, low flow rates (0.001ms) are insufficient to mitigate blockages.

Microscopic pore-throat classification and reservoir grading evaluation of the Fengcheng formation in shale oil reservoir

Different basins in China have proposed various reservoir grading standards for shale oil. Based on a comprehensive understanding of the basic characteristics of the shale oil reservoir in the Mahu Depression, this paper uses data from high-pressure mercury injection, physical properties, nuclear magnetic resonance, depletion development, and CO2 displacement development tests to analyze the microscopic pore structure features of the Fengcheng Formation shale oil reservoir. On this basis, the classification boundaries of the pore throats in the shale oil reservoir were analyzed, and a reservoir grading standard suitable for the Fengcheng Formation shale was proposed: large pore throats (greater than 1000 nm), medium pore throats(100∼1000 nm), small pore throats (20∼100 nm), and ultra-small pore throats (less than 20 nm). The medium pore throat is the lower limit for depletion development, the small pore throat is the lower limit under CO2 displacement conditions, and the ultra-small pore throat cannot be utilized under current conditions. The classification effect of the shale oil reservoir is verified using the production characteristics of Well MY1, the liquid production profile, and the results of geological "sweet spots" studies. The results show that the classification scheme for the microscopic pore throats of the Fengcheng Formation shale oil is reliable and feasible.

Effects of Trapped Gas in Fracture-Pore Carbonate Reservoirs

Abstract Fracture-pore carbonate reservoirs exhibit strong microscopic heterogeneity and complex seepage characteristics, resulting in suboptimal oil-drive efficiency and development outcomes. Moreover, water channeling is often a serious problem in the development of fractured porous carbonate rocks, and the blockage of degassed bubbles in the throat is one of the reasons that cannot be ignored. In order to reveal the degree of influence of bubbles on waterflood sweep, this paper employs microfluidic technology to design three distinct chips, namely fracture-type, composite-type, and cave-type, to visually illustrate the influence of the gas phase on three-phase flow. A quantification method is established to analyze the variation characteristics of pore diameter utilization ratio in different types of carbonate reservoirs. Compared with water flooding experiments without the gas phase, the recovery factor of water flooding with the presence of the gas phase decreases by 0.6%, 3.4%, and 15.3% for three distinct chips, respectively. In fracture-type reservoirs, the main focus is on sealing the primary fracture seepage channel and mitigating the shielding effect of the gas phase on matrix utilization. For composite-type reservoirs, the primary objective is to seal fractures and eliminate the shielding effect of the gas phase. In cave-type reservoirs, the primary goal is to eliminate the sealing effect caused by the discontinuous gas phase within small pore throats.

Experimental Study on SiO2 Nanoparticles-Assisted Alpha-Olefin Sulfonate Sodium (AOS) and Hydrolyzed Polyacrylamide (HPAM) Synergistically Enhanced Oil Recovery

The purpose of this study is to investigate the use of SiO2 nanoparticles in assisting with surfactants and polymers for tertiary oil recovery, with the aim of enhancing oil recovery. The article characterizes the performance of SiO2 nanoparticles, including particle size, dispersion stability, and zeta potential, evaluates the synergistic effects of nanoparticles with alpha-olefin sulfonate sodium (AOS) surfactants and hydrolyzed polyacrylamide (HPAM) on reducing interfacial tension and altering wettability, and conducts core flooding experiments in rock cores with varying permeabilities. The findings demonstrate that the particle size decreased from 191 nm to 125 nm upon the addition of SiO2 nanoparticles to AOS surfactant, but increased to 389 nm upon the addition of SiO2 nanoparticles to HPAM. The dispersibility experiment showed that the SiO2 nanoparticle solution did not precipitate over 10 days. After adding 0.05% SiO2 nanoparticles to AOS surfactant, the zeta potential was −40.2 mV, while adding 0.05% SiO2 nanoparticles to 0.1% HPAM resulted in a decrease in the zeta potential to −25.03. The addition of SiO2 nanoparticles to AOS surfactant further reduced the IFT value to 0.19 mN/m, altering the rock wettability from oil-wet to strongly water-wet, with the contact angle decreasing from 110° to 18°. In low-permeability rock core oil displacement experiments, the use of AOS surfactants and HPAM for enhanced oil recovery increased the recovery rate by 24.5% over water flooding. The recovery rate increased by 21.6% over water flooding in low-permeability rock core experiments after SiO2 nanoparticles were added and surfactants and polymers were utilized for oil displacement. This is because the nanoparticles blocked small pore throats, resulting in increased resistance and hindered free fluid flow. The main causes of this plugging are mutual interference and mechanical entrapment, which cause the pressure differential to rise quickly. In high-permeability rock core oil displacement experiments, the use of AOS surfactants and HPAM for oil recovery increased the recovery rate by 34.6% over water flooding. Additionally, the recovery rate increased by 39.4% over water flooding with the addition of SiO2 nanoparticles and the use of AOS surfactants and HPAM for oil displacement. Because SiO2 nanoparticles create wedge-shaped structures inside highly permeable rock cores, they create structural separation pressure, which drives crude oil forward and aids in diffusion. This results in a comparatively small increase in pressure differential. Simultaneously, the nanoparticles change the rock surfaces’ wettability, which lowers the amount of crude oil that adsorbs and improves oil recovery.

Cross-scale study of pore fractal characteristics and the pore structure of weathered granite

Weathering of granite leads to weakening of its crushing and mechanical properties, as well as changes in mineral composition. In order to investigate the correlation between the effects of weathering on granite and the characterization of the pore structure at the micro- and fine-scale, in this paper the pore structure of weathered granite is tested by the NMR technique. The pore distribution characteristics of weathered granite were explored in conjunction with T 2 spectral relaxation time and fractal theory. The microstructure of weathering-prone granite was monitored using scanning electron microscopy equipment. The results show that the pores can be classified into the three categories of small, medium and large pores based on their pore size distribution characteristics. Weathered granite has fractal features in the mesopores and macropores. Compared with unweathered granite, weathered granite has significantly more small pore throats and fewer medium and large pore throats, which expand into microfissures and micropores under conditions of weathering. The microstructure of weathered granite is mainly flaky and shell-like, with good connectivity, resulting in the poor overall structure of weathered granite.

Robust Scale Dissolver Mitigates Mixed-Scale Issue in South China Sea

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211187, “Tackling Mixed-Scales Issue in an Oil Field Using a Novel Robust Scale Dissolver,” by Nora Aida Ramly, Luky Hendraningrat, SPE, and Latief Riyanto, SPE, Petronas, et al. The paper has not been peer reviewed. _ The evaluation of a recently developed robust solid dissolver (RSD), from the laboratory phase through pilot deployment, is presented in the complete paper. Based on laboratory tests, the RSD can dissolve mixed scales completely in 24 hours at well temperatures while experiencing no incompatibility issues with production chemicals and all pumping and wireline components. The RSD was developed based on the total organic system that can prevent corrosion and is compatible with hydrocarbon. The RSD was piloted at oil Well 1 in Field PN and successfully removed mixed scales, allowing the well’s revival. Introduction Solid scale deposition is one of the most frequent flow-assurance issues both in subsurface and at the surface. The scale can be classified as organic (wax or asphaltenes), inorganic (calcites, sulphates, sulfides, halites, carbonates, and oxides), soap-related (naphthenates and carboxylates), gas-related (hydrates), or mixed scales. Scale occurrence, quantity, and severity mainly are determined by mineralogy, water chemistry, reservoir pressure and temperature, and the flow characteristics of the producing fluid in the well. Furthermore, scale formation is exacerbated by higher pH conditions and a higher water-cut environment, as would be expected in oil fields where water is to be injected for pressure maintenance. The most common type of scales found in Malaysian oil fields are organic and inorganic scales. The operator’s previously deployed scale-dissolving chemical in its fields only could cater to a single type of scale treatment at a time, which was ineffective for dissolving mixed scales simultaneously. Another method is the use of a mechanical solution using a coiled tubing unit (CTU). Removal mechanically by CTU in tubulars is a successful method in removing hard barite scales, but the cost is high and the method requires several days of production deferment. An improved and cheaper mixed-scale removal approach was needed to clean out mixed-scale issues in more-challenging brownfields. The RSD technology was developed for wellbore cleanout caused by mixed scale based on a stable microemulsion solution consisting of acid and solvent components. The solution was proposed to dissolve both organic and inorganic scales simultaneously in the near-wellbore area and tubing string of an oil well. The very small droplet size formed by the surfactant system and solvent is a significant advantage of using microemulsion and can allow penetration even in tight formations with small pore throats and promotes more-uniform surface coverage because of the increased interfacial area of the droplets. Previous studies have reported that the microemulsion can be pumped without causing a significant increase in pumping pressure.

Evaluation of the Effects of Nano-SiO2 Microemulsion on Decompression and Augmented Injection in the Eunan Tight Reservoir

The residual oil saturation of the matrix near the well zone of a tight reservoir is high due to the tight reservoir’s complex conditions, such as the small pore throat radius and low permeability of the matrix and the development of microfractures, which can result in serious water channeling, even after long-term water injection development. The aim of this paper is to improve the effects of depressurization and augmented injection for tight reservoir waterflooding development by reducing the tight matrix’s residual oil saturation, increasing and maintaining its water phase permeability near the well zone using a nano-SiO2 microemulsion system with a small particle size and high interfacial activity. Therefore, four nano-microemulsion systems were evaluated and screened for their temperature resistance, salt resistance, interfacial tension, solubilization, and dilution resistance. A microemulsion system of 13% A + 4% B + 4% C + 4% n-butanol + 6% oil phase + 69% NaCl solution (10%) + 1% OP-5 + 0.5% anti-temperature agent + 0.3% nanosilica material was preferred. According to the core displacement experiment, the depressurization rate can reach 28~60% when the injection concentration of the system is 1~10% and the injection volume is 2~5 PV. The results of the on-site test show that the water injection pressure dropped to 17.5 MPa, which was lower than the reservoir fracture re-opening pressure. The pressure reduction rate was approximately 20%. The validity period of the depressurization and augmented injection has reached 23 months to date.

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.

Study of pore-throat structure characteristics and fluid mobility of Chang 7 tight sandstone reservoir in Jiyuan area, Ordos Basin

Abstract Quantitative studies of the pore-throat structure (PTS) characteristics of tight sandstone reservoirs and their effects on fluid mobility were proposed to accurately evaluate reservoir quality and predict sweet spots for tight oil exploration. This study conducted high-pressure mercury injection (HPMI) and nuclear magnetic resonance (NMR) experiments on 14 tight sandstone samples from the Chang 7 member of the Yanchang Formation in the Jiyuan area of the Ordos Basin. The HPMI was combined with the piecewise fitting method to transform the NMR movable fluid transverse relaxation time (T 2) spectrum and quantitatively characterize the PTS characteristics and the full pore-throat size distribution (PSD). Then, movable fluid effective porosity (MFEP) was proposed to quantitatively evaluate the fluid mobility of tight sandstone reservoirs and systematically elucidate its main controlling factors. The results showed that the PTS could be divided into four types (I, II, III, and IV), which showed gradual decreases in average pore-throat radius (R a), continuous increases in the total fractal dimension (D t), and successive deterioration of reservoir fluid mobility and percolation capacity. Moreover, the full PSD (0.001–10 μm) showed unimodal and multi-fractal characteristics. According to the Swanson parameter (r apex), the reservoir space types can be divided into small and large pore-throat and the corresponding fractal dimension has a relationship where D 1 < D 2. Large pore-throat had higher permeability contribution and pore-throat heterogeneity but a lower development degree and MFEP than small pore-throat, which had a relatively uniform and regular PSD and represented the primary location of movable fluids. Moreover, the development degree and heterogeneity of small pore throat controlled the flowability of reservoir fluids. MFEP can overcome the constraints of tiny throats and clay minerals on movable fluid, quantify the movable fluid content occupying the effective reservoir space, and accurately evaluate the reservoir fluid mobility. The combination and development of various pore-throat sizes and types in tight sandstone reservoirs results in different PTS characteristics, whereas differences in the mineral composition and content of reservoirs aggravate PTS heterogeneity, which is the main factor controlling the fluid mobility.