One of the major problems in all area of petroleum industry, including production, operation, storage and transportation, is formation of heavy organic compounds, e.g., asphaltene and wax, and their consequent deposition in equipment and pipelines. Change in crude oil composition, temperature and pressure leads to asphaltene precipitation. Thus, it is of vital importance to determine onset of asphaltene precipitation during oil production. In this regard, various techniques have been suggested in literature, each with its own pros and cons. However, from practical point of view, one needs to decide which method serves to be proper one. To this end, present study gives a comprehensive critical review for different techniques serve to determine onset of asphaltene precipitation along with comparing their advantages and disadvantages. Since each method presents its own definition for onset, such as onset of precipitation, clustering and deposition; it is necessary to distinguish their difference based on underlying physical mechanisms. It was concluded that mechanism of asphaltene precipitation for determining onset of asphaltene precipitation plays a substantial role.

There are few reports about the penecontemporaneous karst of the lacustrine carbonate of Da'anzhai Member which developed on the top of Lower Jurassic Ziliujing Formation, eastern Sichuan Basin. Based on the analysis of the macroscopic and microscopic characteristics of Heping Reservoir section in Beibei area, It is discovered that the penecontemporaneous karst in the lacustrine carbonate, Da'anzhai Member, and its characters as follows: (1) The dissolved fractures and karrens are common, which have been filled with vadose silts, bioclasts, terrigenous quartzes, crystal and intergrown calcites; (2) The penecontemporaneous karstification mainly occurs in the micrites and shell limestones of the middle and upper part of the shallowing-upward sequence, and the desiccation cracks occur in some shallowing-upward sequences; (3) Three meteoric-water diagenetic lenses are identified in this section. By further study we also find the factures, stylolite and burial dissolution pores occur along the karst system (tubes, conduits and caves of the karst). And the asphalt not only fills the stylolites and fractures, but also is mixed with the vadose silt in the karst system, although the pore space formed by penecontemporaneous karstification is filled with vadose material and cements. Therefore it is concluded that the development and modification of the tight lacustrine carbonate reservoir of Da'anzhai Member, to some extent, are relevant with the penecontemporaneous karstification, and the penecontemporaneous karst reservoir may develop in the buried Da'anzhai carbonate of the basin.

It is well known that the flowing of oil and gas in fracture and cave does not obey Darcy law, which makes it unable to interpret parameters correctly when doing well testing for those kinds of formation for having no flowing test used to correct corresponding flowing equations. Based on similarity criterion, a physical experimental method for gas flowing from cave to wellbore through fracture has been built up. The characteristics of fluid flowing in fracture and cave can be seen clearly according to log-log curves with the measured data, which was obtained from the experimental model test and dealt with Savitzky-Golay filtering method. In addition, a new mathematical model reflecting those transient-flow behaviors as well as its solution has been presented in this paper. Log-log curves obtained from our new model could reflect the characteristics of flowing in fracture and cave. The results showed that test experiments can reflect the influence of large-scaled cave and fracture on the flowing characteristics and the new model can be applied to explain parameters of fracture and cave for similar cases.

Coreflood, interfacial tension (IFT), contact angle, and phase behavior measurements were performed to investigate the viability of a hybrid of low-salinity water, surfactant, and CO₂ flood enhanced oil recovery (EOR) process.

Low-permeability carbonate reservoir cores were aged for eight weeks at reservoir temperature and pressure. Coreflood and contact angle between oil droplets and core surface measurements were performed. Additional contact angle measurements on sandstone and shale cores were also performed. The coreflood sequences were seawater flood, followed by low-salinity water flood, followed by surfactant floods until residual oil saturations to each flooding sequences and finally CO₂ injection.

Coreflood in low-permeability carbonate cores show that the hybrid EOR process produces incremental oil up to twenty-five percent beyond seawater flooding. Contact angle measurements on carbonate, sandstone and shale cores indicate that wettability alteration and IFT decrease are the main oil-mobilizing mechanisms in the hybrid EOR process.

The hybrid EOR process mobilizes part of the residual oil because: (i) low-salinity brine improves wettability towards hydrophilic condition favorable for surfactant flooding; (ii) surfactant in low-salinity water solubilizes some of the remaining oil as Winsor type II⁻ microemulsion and lowers IFT between oil and water; and (iii) CO₂ will follow surfactant to mobilize more of the remaining oil in the wettability-improved condition.

Due to extreme poison, strong corrosion, and complex precipitation and deposition of H₂S in the reservoir, it is very difficult and risky to investigate and explore drilling, completion, production and gas transportation. In the course of production of fractured gas reservoir with high H₂S content, formation pressure falls continually, which lead to decline of solubility of sulfur particles in gas phase. Sulfur particles which dissolve in gas phase originally in the formation should precipitate from gas phase after running up to saturation state and deposit at pore space and throat, sequentially resulting in formation porosity and permeability reduction. At present, the researches of sulfur deposition are mainly focused on the conventional gas reservoirs and sulfur deposition in the near wellbore region is generally estimated using Roberts' model. However, most of the gas reservoirs with high-content H₂S are fractured gas reservoirs, classical damage model is no longer applicable to fractured gas reservoirs with high H₂S content. In the present study, a sulfur deposition damage model is established. The refined model, based on non-Darcy flow, takes into consideration the effects of sulfur deposition, variation in gas properties and fracture. In addition, the effect of gas well production rate on formation permeability is also studied. The results show that formation permeability decreases with fracture aperture and gas well production rate increasing. The bigger gas well production rate is, the quicker sulfur precipitates. The sulfur deposition of fractured gas reservoir with high-content H₂S is mainly in the near wellbore zone, and the fracture aperture has a significant impact on the formation permeability in the near wellbore zone.

Currently, most models for multiple fractured horizontal wells (MFHWs) in naturally fractured unconventional reservoirs (NFURs) are based on classical Euclidean models which implicitly assume a uniform distribution of natural fractures and that all fractures are homogeneous. While fractal theory provides a powerful method to describe the disorder, heterogeneity, uncertainty and complexity of the NFURs. In this paper, a fractally fractional diffusion model (FFDM) for MFHWs in NFURs is established based on fractal theory and fractional calculus. Particularly, fractal theory is used to describe the heterogeneous, complex fracture network, with consideration of anomalous behavior of diffusion process in NFURs by employing fractional calculus. The Laplace transformation, line source function, dispersion method, and superposition principle are used to solve this new model. The pressure responses in the real time domain are obtained with Stehfest numerical inversion algorithms. The type curves of MFHW with three different outer boundaries are plotted. Sensitivity analysis of some related parameters are discussed as well. This new model provides the relatively more accurate and appropriate evaluation results for pressure transient analysis for MFHWs in NFURs, which could be applied to accurately interpret the real pressure data of an MFHW in field.

When the bottom-hole flowing pressure in a gas condensate reservoir drops below the dew point pressure, liquid starts to build up around the well bore resulting in gas productivity decline.

For this reason it is important to be able to accurately either measure or estimate the dew point pressure. The condensate formed in the reservoir will not flow until its saturation reaches the critical saturation and in many cases it might not be entirely recovered. It order to maximize gas production and condensate recovery, the reservoir pressure must be maintained close to the dew point pressure. Several attempts have been made to predict the dew point pressure in case the gas sample becomes unavailable or measured value is unreliable. Unfortunately, most of these attempts have minor success rates and are based on limited data.

In this paper we present a robust, cheap, and easy model for predicting the dew point pressure for gas condensate reservoirs. The new model is an intelligent based model called “Gene Expression Programming” that is carried out to generate a precise and accurate correlation to estimate the dew point pressure in condensate gas reservoirs. The new model has been trained and tested using a large data bank collected for the literature. Precision of the suggested correlation has been compared to published correlations. The validity of this model has also been compared to experimental data and other published correlations.

For carbonate reservoirs, gas-water and oil-gas relative permeability curve are of importance for parameters calculation in oil-field development, dynamic analysis and numerical reservoir simulation. The oil-gas/gas-water relative permeability curves were measured with unstable method under normal temperature and low pressure, using fifteen artificial fractured cores. The shape and change characteristics of gas/water and oil/gas relative permeability curve were mainly analyzed. The results showed that for the relative permeability curve of water driving gas. The saturation of equal permeability point, the saturation range of two-phase flow region and the displacement efficiency has a good power-function relation with core permeability. In addition, the saturation of equal permeability point, the saturation range of two-phase flow region and the displacement efficiency will decrease with the increasing of core permeability. However, for oil-gas relative permeability curves, the saturation of equal permeability point, the saturation range of two-phase flow region and the displacement efficiency will increase with the increasing of core permeability. It should be noted that the gas relative permeability presents a straight line in the normalized relative permeability curve, which indicates that the main flow is dominated by fracture with low displacement efficiency. The research results provide theory basis for fracture-vuggy carbonate reservoir development and new research idea for the further study of this kind of reservoir.

The development of eco-friendly shale inhibitors is still an area which has attracted a lot of attention in the drilling industry. Henna extract is a natural dye which has recently shown considerable inhibition and weak deflocculation properties in clay-water system. This study aims to investigate swelling inhibitive feature and side effects of Henna extract in water-based drilling fluids (WBDFs). It was carried out through extensive experiments including adsorption measurements on shale by batch equilibrium, inhibition evaluation by dynamic linear swelling and cuttings dispersion, wettability alteration via contact angle measurements, compatibility by rheological properties determinations and fluid loss measurements, and lubricity. Both in natural pH and adjusted pH to 9, Linear adsorption model was more suitable for anticipating the adsorption behavior of Henna extract on the given shale sample. The results of the linear swelling and cuttings dispersion tests demonstrated that Henna extract in drilling fluid formulations diminished the swelling and dispersion characteristics of the addressed shale sample. Moreover, contact angle measurements showed that Henna extract expanded the hydrophobicity of shale formations, preventing and promoting water adsorption and shale stability respectively. This issue definitely introduces wettability alteration as a mechanism for shale stability by Henna extract. Compatibility determinations additionally uncovered that Henna extract is compatible with common WBDFs additives. As indicated by the lubricity tests, Henna extract enhanced the lubricity of WBDFs, a finding which can be of an incredible significance in directional drilling. Among others, advantages such as environmental friendliness, low cost, accessibility, and the counter corrosion property make the applicability of Henna extract in WBDFs profoundly suitable.

The purpose of this experimental study is to evaluate the feasibility and oil recovery efficiency of continuous N₂ injection in a multi-well fractured-cavity reservoir. In this study, the similar criterion of physical simulation was firstly discussed. In order to reveal the mechanism of remaining oil startup and production performance characteristic by continuous N₂ injection, a visualized two-dimensional fractured-cavity model and a three-dimensional pressure resistant model were designed and fabricated respectively based on the similar theory. And the 2D visualized physical experiments and 3D physical experiments were performed with the simulated oil and brine reservoir samples in Tahe oilfield. Four groups of experiments in 2D and 3D model were performed, each of which included bottom water depletion driving, water injection and N₂ injection. The 2D visualized experiments indicated the main mechanism of N₂ developing remaining oil was to occupy the high position and replace the attic oil due to gravitational differentiation. Furthermore, both the 2D and 3D experiments demonstrated that higher oil recovery factor could be achieved if N₂ was injected through high positional wells. The 3D physical model is closer to the real reservoir condition, so the production performance can reflect the real field production process. This paper confirmed the efficiency of continuous N₂ flooding in the light oil saturated fractured-cavity reservoir.

Slow strain rate test (SSRT) and tensile fracture observation are applied to study the stress corrosion cracking (SCC) of L360NS pipeline steel. 5.0 wt. % sodium chloride solution containing elemental sulfur and 0.5 wt. % glacial acetic acid solution containing elemental sulfur are used. The results show that brittle fracture mainly occurs on the samples in high sulfur environment. In the sulfur suspension solution, the SCC sensitivity of L360NS pipeline steel increases along elemental sulfur content. In sulfur melting cladding condition, obvious corrosion can be observed with a large amount of corrosion pits appearing on the gauge section of the sample. The corrosion products are Fe_1+xS, black easily detached, and H₂. In sulfur suspension and sulfur melting cladding conditions, stress oriented hydrogen induced cracking (SOHIC) is the main cracking, which is caused by the joint effect of SCC and hydrogen induced cracking (HIC).

This paper studies the adsorption behavior of representative guar-based polymers onto the surface of source rock outcrop samples to provide a better picture of the interaction(s) of polymers with these rocks. Outcrop samples from the Barnett, Eagle Ford, and Marcellus shales were collected, analyzed for mineralogy and total organic content, and then exposed to different polymer solutions under elevated temperature and moderately elevated pressure. Viscosities of these polymer solutions were measured before and after exposure to the rock samples to establish a correlation between polymer adsorption and rock mineralogy and/or organic content. Results indicate a direct correlation between polymer adsorption and both rock mineralogy. Cationic polymers are shown to be more prone to adsorption onto the surface of the rock than non-ionic polymers. The results from this work establish that fluid-rock interactions are significant and that further research regarding shale polymer interactions and its effects on hydrocarbon production is needed with representative downhole shale samples given the trends now shown with outcrop samples.