Graphene is a single atom thick crystal composed of carbon atoms. It is the lightest, thinnest, strongest material that conducts heat and electricity well heretofore. In terms of application, by introducing oxygen-containing groups, graphene can be well dispersed in solvents, can be chemically modified and functionalized, or connected with other electroactive substances through covalent bond or non-covalent bond to form composite materials, which is conducive to further processing and promotion. The application of graphene in oilfield chemistry started late, but developed rapidly. Graphene has played an active role in drilling fluid, cementing fluid, fracturing fluid, displacement fluid and other oilfield working fluids. It can enhance the temperature and salt resistance of working fluid and improve the effect of working fluid. In this paper, several directions of graphene applications in oilfield chemistry, such as modified graphene, graphene copolymers and graphene nanoparticles, are reviewed in detail from the synthesis methods, action mechanisms and effects of graphene and its derivatives, and the frontier cases at this stage are given. On the basis of the existing research, suggestions for the development direction of graphene materials in oilfield chemistry are given for a variety of graphene materials, aiming to provide guidance for the application of graphene in oilfield chemistry.

Asphaltene precipitation can result in several production, operational, and transportation problems during oil recovery. If asphaltene precipitates and deposits, it can reduce reservoir permeability, damage wellbore equipment, and plug the pipelines. It is therefore extremely important to evaluate the conditions at which asphaltene precipitation occurs; this is referred to as the asphaltene onset pressure. Asphaltene onset pressure has been measured using many different experimental techniques. There have also been many attempts along the years to predict asphaltene onset pressure using mathematical correlations and models. This research provides an up-to-date comprehensive review of the methods by which asphaltene onset pressure can be measured using laboratory experiments and mathematical models. The research explains the main mechanisms of all the laboratory experiments to measure asphaltene onset pressure under static conditions and how to conduct them and highlights the advantages and limitations of each method. The research also provides a summary of the commonly used mathematical models to quantify asphaltene onset pressure directly and indirectly.

The development of low-permeability oil and gas resources presents a significant challenge to traditional development methods. To address the problem of “no injection and no production” in low -permeability reservoirs, a novel fracture-injection-production integration technology named fracturing-flooding has been proposed by oilfield sites. This technology combines the advantages of conventional fracturing, water flooding, and chemical flooding, resulting in improved reservoir physical properties, increased injection, replenished energy, and increased oil displacement efficiency. The technology is especially suitable for low-permeability reservoirs that suffer from lack of energy, and strong heterogeneity. Fracturing-flooding technology has shown significant results and broad development prospects in some oilfields in China. This paper analyzes the development status of fracturing-flooding technology from its development history, technical mechanism, technical characteristics, process flow, types of fracturing and oil displacement fluids, and field applications. Physical and numerical simulations of fracturing-flooding technology are also summarized. The results suggest that fracturing-flooding technology is more effective than conventional fracturing, water flooding, and chemical flooding in stimulating low-permeability tight reservoirs and improving oil recovery. Moreover, it has a high input-output ratio and can be utilized for future reservoir stimulation and transformation.

The paper presents the results of studies on the transformation of the organic matter of siliceous-clayey carbonate rocks of the Semiluksko-Mendymsky horizon of the Romashkino oil field in a hydrothermal fluid for an hour (with a water-to-rock ratio of 33) at 340°C and 380°C and pressures of 17 and 20 MPa. As a result of hydrothermal treatment, at 340°C and 17 MPa, based on nitrogen porosimetry and electron microscopy data, transformations of rock-forming minerals in the rock are observed. They lead to an increase in the volume and average diameter of mesopores in it and the formation of micropores, as well, which improve its filtration properties. At the same time, the amount of kerogen in the composition of the organic matter decreases and the yield of the petroleum hydrocarbon extract increases, in which, according to the SARA analysis, the content of asphaltenes increases and the content of resins, aromatic and saturated hydrocarbons decreases. In the composition of aroatic hydrocarbons, the proportion of alkyltrimethylbenzenes and dibenzothiophenes increases, phenanthrene homologues appear, and in the composition of saturated hydrocarbons, the amount of iso-structure alkanes decreases relative to the content of linear alkanes. Raising the temperature and pressure of the hydrothermal fluid to 380°С and 20 MPa increases the degree of kerogen conversion from 12.4% to 23.6%. At the same time, changes occurring in the component composition of petroleum hydrocarbon extracts remains similar to the experiments carried out at 340°C and 17 MPa; the content of naphthalenes decreases, the content of dibenzothiophenes increases and C₁₁-C₁₇, C₁₉-C₂₂ alkyltrimethylbenzenes appear. According to IR spectroscopy, with increasing temperature and pressure of the hydrothermal fluid the intensity of the absorption bands of the aromatic ring, aliphatic fragments, and oxygen-containing groups increases in resins; the structural-group composition of asphaltenes changes little: aromaticity and the content of condensed structures slightly increase. The revealed distinctive features in the composition of organic matter after hydrothermal impact on siliceous-clayey carbonate rocks confirm the concept of staged destruction of kerogen, when large structural heteroatomic blocks (asphaltenes) are split off at the initial stages. Changes occurring in the composition of petroleum hydrocarbon extracts indicate their involvement in the process of hydrothermal transformation of organic matter of siliceous-clayey carmbonate rocks with the predominant reactions of dehydrogenation of naphthenic compounds and oxidative polycondensation of aromatic structures. The data of electron microscopy and nitrogen porosimetry of rocks after hydrothermal exposure at 380°С and 20 MPa indicate a deterioration in their reservoir properties. The most optimal thermobaric conditions of the hydrothermal fluid for the generation of petroleum hydrocarbons from kerogen of siliceous-clayey carbonate deposits of the Semiluksko-Mendymsky horizon of the Romashkino field, which improve their reservoir properties, are 340°С and 17 MPa; with implication of hard-to-recover heavy hydrocarbon resources and well-established catalytic methods of in-situ conversion.

Cambrian in Sichuan basin developed thick black shale, varies carbonate and clastic rock, which deposited in different sedimentary environment. Sichuan basin in the upper Yangtze platform contained a record of environment during the Cambrian. Detail facies analyses of Cambrian enable us to discuss the sedimentary environment and palaeogeographic setting. Sedimentation commenced in the Early Cambrian with the deposition of shelf facies (Qiongzhusi Formation and Canglangpu Formation). At this stage, thick shale and clastic rock deposited in Sichuan basin. At the end of the Early Cambrian, a carbonate platform developed in upper Yangtze platform, and Sichuan basin was located in restricted platform (Longwangmiao Formation). In the Middle Cambrian, tidal flat and restricted platform developed in Sichuan basin (Douposi Formation), because of continuous regression. During the Late Cambrian, Sichuan basin was located in carbonate platform again (Xixiangchi Formation). There are three types of sedimentary system in the Cambrian of Sichuan basin: clastic sedimentary system, clastics-carbonate mixed sedimentary system and carbonate sedimentary system. Vertically, the basin shows the evolutionary character of clastic-carbonate sedimentary systems. The three sedimentary systems correspond to three “transgression-regression” cycles of the Cambrian. The transgression in the initial period of the Early Cambrian led to the formation of clastic sedimentary system in the Qiongzhusi Formation of Lower Cambrian. The transgression in the later period of the Early Cambrian led to the formation of clastic-carbonate mixed sedimentary system in the Middle-Lower Cambrian. The transgression in the initial period of the Late Cambrian led to the formation of carbonate sedimentary system in the Xixiangchi Formation of Upper Cambrian. With the end of Late Sinian continental rifting ended, Sichuan basin entered a stable evolutionary stage of the craton basin, while the paleo-land developed in the north and southwest. In Qiongzhusi-Canglangpu period, the basin developed onshore-shelf sedimentary facies from west to east; In Longwangmiao-Xixiangchi period, the basin developed tidal flat-platform-slope sedimentary facies from west to east.

The stability analysis of horizontal wells is essential for a successful underground coal gasification (UCG) operation. In this paper, a new 3D coupled thermo-mechanical numerical modeling is proposed for analyzing the stability of UCG horizontal wells. In this model, the effect of front abutment stresses, syngas pressure, syngas temperature and thermal stresses is considered to predict the mud weight window and drilling mud pressure during UCG process. The results show that the roof caving in UCG panel has a greatest impact on the stability of horizontal well. Moreover, when the time of coal gasification is increased, the well convergence increases and for more stability it is necessary to increase the drilling mud pressure. This research was carried out on the M2 coal seam in Mazino coal deposit (Iran). The results showed that the mud weight window for horizontal well drilling is between 0 and 33 MPa. The appropriate stress for the maximum stability of the horizontal well, taking all the thermal and mechanical parameters into account, is 28 MPa. The suggested numerical method is a comprehensive and consistent way for analyzing the stability of horizontal wells in UCG sites.

Present drilling fluids for deep water wells have severe degenerative effect on the environment with high operational and disposal costs. Thus, making them less desirable in recent times. Ester synthetic drilling fluid provides a novel environmentally friendly alternative but conventional ester-based drilling fluids exhibit high viscosities in deep-water wells causing excessive equivalent circulating density (ECD) and increased risk of lost circulation owing to narrow mud density window. This study experimentally investigates the critical fluid properties and aerobic biodegradability potentials of two newly developed deep-water synthetic ester drilling fluids namely: iso-propyl caprylate (COIPE) and iso-propyl linolenate (LOIPE) synthetic fluids and their comparison with synthetic-paraffin (SP-SBF) and isomerized-olefin (IO-SBF) synthetic hydrocarbon fluids. The esters of iso-propyl caprylate and iso-propyl linolenate were produced from the isolation of ester mixtures that were obtained from the homogeneous catalytic transesterification of coconut and linseed plant oil biomass respectively. The COIPE was isolated from the coconut oil iso-propyl ester mixture by low-pressure fractional distillation technique. While fractional distillation and crystallization were used to isolate the LOIPE ester from the linseed oil iso-propyl ester mixture. Meanwhile, the aerobic biodegradation investigation was conducted by a modified oxygen consumption respirometry technique. The GC-MS analysis of the COIPE and LOIPE showed that the former contains essentially of lower saturated carbon compounds (C8). Whereas the latter contains higher molecular weight and unsaturated carbon compounds (C18⁺). The COIPE and LOIPE kinematic viscosity values are in good agreement with that of the reference synthetic hydrocarbon fluid samples (SP-SBF and IO-SBF). Although, the COIPE synthetic ester has lower viscosity value owing to the presence of shorter chain and saturated carbon atoms (C8 esters). Similarly, the linolenic oil iso-propyl ester has excellent cold flow characteristics for deep-water well drilling owing to lower values of cloud and pour points as a result of higher concentration of poly-unsaturated linolenic esters. The iso-propyl caprylate and the iso-propyl linolenate ester synthetic fluids are readily biodegradable in the sea water inoculum under aerobic condition. However, the iso-propyl caprylate is inherently biodegradable because its degradation level and that of the reference chemical sample were already above 60% during the 10-day window period. The SP-SBF and the IO-SBF synthetic fluids have lower aerobic biodegradation values because they contain little quantity of poly aromatic hydrocarbons as evident in their GC-MS profiles. Finally, esters and unsaturated synthetic-based fluid are more rapidly biodegradable than paraffinic synthetic fluids and the rate of biodegradation of organic compounds decreases as molecular weight increases

Shale gas reservoirs are unconventional tight gas reservoirs, in which horizontal wells and hydraulic fracturing are required to achieve commercial development. The fracture networks created by hydraulic fracturing can increase the drainage area extensively to enhance shale gas recovery. However, large volumes of fracturing fluid that is difficult to flow back to the surface and remained in the shale formation, will inevitably lead to damages of the shale formations and limit the effectiveness of stimulation. Supercritical water (SCW) treatment after hydraulic fracturing is a new method to enhance shale gas recovery by using appropriate heat treatment methods to the specific formation to convert the retained fracturing fluid into a supercritical state (at temperatures in excess of 373.946°C and pressures in excess of 22.064 MPa). An experiment was conducted to simulate the reaction between shale and SCW, and the capacity of SCW treatment to enhance the permeability of the shale was evaluated by measuring the response of the shale porosity and permeability on SCW treatment. The experimental results show that the shale porosity and permeability increase by 213.43% and 2198.37%, respectively. The pore structure alteration and permeability enhancement of the shale matrix were determined by analyzing the changes in pore structure and mineral composition after SCW treatment. The mechanisms that affect pore structure and mineral composition include oxidative catalysis decomposition of organic matters and reducing minerals, acid-catalyzed decomposition of carbonate minerals and feldspar minerals, hydrothermal catalysis induced fracture extension and cementation weakening induced fracture extension. SCW treatment converts harm into a benefit by reducing the intrusion of harmful substances into the shale formation, which will broaden the scope and scale of shale formation stimulation.

Fluid production from unconsolidated reservoirs often leads in sand production, which poses a number of issues. Sand deposition in flowlines can result in significant pressure dips, pipe and facility damage, and obstructions that decrease productivity. More research is needed to understand the movement and deposition of sand in oil-water-sand (O-W-S) fluxes. This article focuses on O-W-S flows in a 6-meter-long horizontal pipe with an inner diameter of 0.0381 m. The study looks at the flow behavior of high viscosity oil-water (O-W), water-sand (W-S), and oil-water-sand (O-W-S) flows. Experiments were carried out at 250 psig pressure in a laboratory flow test facility using various heavy synthetic oils (viscosities ranging from 3500 cP to 7500 cP at 25°C) and tap water. The sand concentration varied from 1% to 10%, with an average sand particle diameter of 145 μm and material density of 2630 kg/m³. Water cuts ranged from 0.0 to 1.0. The experimental results revealed a minor change in pressure gradient between (O-W) and (O-W-S) flows. However, increasing the sand concentration in (O-W-S) flow resulted in higher pressure losses. The reduction factor of pressure gradient indicated that the highest decrease in pressure drop occurred at higher superficial oil velocities. Furthermore, a direct relationship was observed between the reduction factor and the decrease in water cut. The results also showed that the minimum required transportation velocity for sand slurry decreased with increasing superficial oil velocity, while the minimum transportation condition increased with higher sand concentration. The comparison between the expected pressure gradient from Bannwart and McKibben et al. and the actual experimental data demonstrated significant accuracy for the oil viscosities and superficial oil velocities used in the study.

Due to the extremely low permeability of shale formations, the combination of horizontal well and volume fracturing has been proposed as an effective technique to improve the production of Dagang continental shale oil reservoirs. Based on the flow material balance method (FMB) and straight-line analysis (SLA) method, the stimulated reservoir volume (SRV) and drainage volume are determined to identify the flow regimes of the seepage mechanism of shale oil reservoirs. To resolve the challenges of multi-scaled flow regimes and bottom hole pressure (BHP) variation before and after pumping in shale oil wells, a multi-linear analytical flow model was established to predict the future production and the final expected ultimate recoverable oil (EUR_o) after fitting the historical production dynamics. Based on the results, it can be concluded that the flow regime of a shale oil well in production can be divided into two stages consisting of linear flow within SRV and composite flow from the un-stimulated area to SRV. The effects of fracturing operation parameters, such as fracturing fluid volume and sand/liquid ratio, on shale oil productivity, are analyzed, and insightful suggestions are drawn for the future development of this pay zone.

Sandstone reservoirs often contain clay particles that can cause damage and reduce permeability during low-salinity water flooding. In this study, the effect of surfactants on fine migration in clay-rich sandstones and its impact on oil recovery was investigated.

First, the impact of surfactants on interparticle forces in fine-matrix, fine-fine, and oil-matrix systems was modeled. The results showed that both CTAB (cetyltrimethyl ammonium bromide) and QS (quillaja saponin) cause EDL compaction, weakening the repulsive forces. However, SDS (sodium dodecyl sulfate) and TX (triton X-100) do not affect the EDL. Next, the effect of surfactants on IFT reduction and wettability alteration was experimentally investigated. All surfactants reduced IFT due to the surface excessive concentration mechanism. The wettability alteration experiment illustrated that although QS and CTAB compact EDL around oil and matrix particles leading to attraction force augmentation, they both alter wettability through adsorption on matrix and carboxylic groups present in crude oil, respectively.

Surfactant aqueous solutions were then injected into various clay-rich sandstone sanpacks, which resulted in increased oil recovery. However, the mechanisms leading to enhanced oil recovery variedby surfactant type. CTAB increased recovery by 10% through IFT reduction and wettability alteration, while SDS and TX increased recovery by 12% and 9%, respectively, through wettability alteration and extreme fine migration. In contrast, partial fine migration in the QS flooding experiment reached a recovery increase of 18%. Permeability trends through experiments were also recorded. During CTAB injection, permeability did not reduce, while QS aqueous solution reduced rock permeability to 5 mD. SDS and TX reduced the magnitude of permeability to 2 mD.

In conclusion, this study demonstrates that surfactants can effectively improve oil recovery in clay-rich sandstones by altering the interparticle forces, reducing IFT, and changing wettability. The results suggest that the type of surfactant used should be carefully selected to achieve the desired recovery increase without affecting the permeability of the reservoir.

Soil corrosion and hydrogen embrittlement are the main factors of hydrogen pipeline failure. The gas escapes, diffuses and accumulates in the soil and enters the atmosphere when leak occurs. The mechanism of gas diffusion in buried pipelines is very complicated. Mastering the evolution law of hydrogen leakage diffusion is conducive to quickly locating the leakage point and reducing the loss. The leakage model of the underground hydrogen pipeline is established in this paper. The effect of leakage hole, soil type, pipeline pressure, pipeline diameter on hydrogen leakage diffusion were investigated. The results show that when the hydrogen pipeline leaks, the hydrogen concentration increases with the increase of leakage time, showing a symmetrical distribution trend. With the pipeline pressure increase, hydrogen leakage speed is accelerated, and longitudinal diffusion gradually becomes the dominant direction. As the leakage diameter increases, hydrogen leakage per unit of time increases sharply. Hydrogen diffuses more easily in sandy soil, and its diffusion speed, concentration, and range are higher than that in clay soil. The research content provides a reference and basis for the detection and evaluation of buried hydrogen pipeline leakage.

The present work investigates the volumetric and viscometric properties of an aqueous solution of 1,2-dimethylethylenediamine (DEEDA) over an entire concentration range and an absorber operating temperature range of 313.15K-333.15K at atmospheric pressure. The investigated volumetric properties included the density, excess molar volume, partial molar volume, and the investigated viscometric properties included the viscosity, viscosity deviation, free energy for activation of viscous flow, excess free energy for activation of viscous flow, and excess entropy for activation of viscous flow. The results indicated that there are strong intermolecular interactions and suitable molecular packing in the binary DEEDA-water mixture. Hence, the mixture was found to deviate from a real mixture according to the calculated excess properties. The DEEDA solvent's preliminary volumetric and viscometric properties revealed convincing potential as a novel amine for carbon capture. Additionally, the Redlich-Kister-based correlations showed favorable correlative performance for excess molar volume, viscosity deviation, and excess entropy for activation of viscous flow.

Increasing world request for energy has made oil extraction from reservoirs more desirable. Many novel EOR methods have been proposed and utilized for this purpose. Using nanocomposites in chemical flooding is one of these novel methods. In this study, we investigated the impact of six injection solutions on the recovery of light and heavy oil with the presence of two different brines as formation water using a homogenous glass micromodel. All of the injection solutions were based on a 40,000 ppm NaCl synthetic seawater (SSW), one of which was additive free and the others were prepared by dispersing nanocomposite silica-based polyacrylamide (NCSP), nanocomposite alumina-based polyacrylamide (NCAP), the combination of both nanocomposites silica and alumina based on polyacrylamide (NCSAP), surfactant (CTAB) and polyacrylamide (PAM) with a concentration of 1000 ppm as additives. The Stability of nanocomposites was tested against the salinity of the brine and temperature using salinity and DSC tests which were successful. Alongside stability tests, IFT, contact angle and oil recovery measurements were made. Visual results revealed that in addition to the effect of silica and alumina nanocomposite in reducing interfacial tension and wettability alteration, control of mobility ratio caused a major improvement in sweeping efficiency and oil recovery. According to the sweeping behavior of injected fluids, it was found that the main effect of surfactant was wettability alteration, for polyacrylamide was mobility control and for nanocomposites was the reduction of interfacial tension between oil and injected fluid, which was completely analyzed and checked out. Also, NCSAP with 95.83% and 70.33% and CTAB with 84.35% and 91% have the highest light oil recoveries at 250,000 ppm and 180,000 ppm salinity, respectively which is related to the superposition effect of interactions between nanocomposites, solution and oil. Based on our results it can be concluded that the most effective mechanism in oil recovery was IFT reduction which was done by CTAB reduction also by using a polymer-based nanocomposite such as NCSAP and adding the mobility control factor, the oil recovery can be further enhanced. In the case of heavy oil recovery, it can be concluded that the mobility control played a much more effective role when the PAM performed almost similarly to the CTAB and other nanocomposites with a recovery factor of around 17%. In this study, we tried to investigate the effect of different injection solutions and their related mechanisms on oil recovery.

Surface chokes are widely utilized equipment installed on wellheads to control hydrocarbon flow rates. Several correlations have been suggested to model the multiphase flow of oil and gas via surface chokes. However, substantial errors have been reported in empirical fitting models and correlations to estimate hydrocarbon flow because of the reservoir's heterogeneity, anisotropism, variance in reservoir fluid characteristics at diverse subsurface depths, which introduces complexity in production data. Therefore, the estimation of daily oil and gas production rates is still challenging for the petroleum industry. Recently, hybrid data-driven techniques have been reported to be effective for estimation problems in various aspects of the petroleum domain. This paper investigates hybrid ensemble data-driven approaches to forecast multiphase flow rates through the surface choke (viz. stacked generalization and voting architectures), followed by an assessment of the impact of input production control variables. Otherwise, machine learning models are also trained and tested individually on the production data of hydrocarbon wells located in North Sea. Feature engineering has been properly applied to select the most suitable contributing control variables for daily production rate forecasting. This study provides a chronological explanation of the data analytics required for the interpretation of production data. The test results reveal the estimation performance of the stacked generalization architecture has outperformed other significant paradigms considered for production forecasting.