Wax deposition inside the tubing walls endures being a critical operational challenge faced by the petroleum industry. The build-up of wax deposits may lead to the increase of pumping power, as well as the decrease of flow rate or, even, to the total blockage, with production losses and high operational costs.

The current paper is a critical review of the main deposition mechanisms involved in wax deposition. Most of wax deposition models regard molecular diffusion as the dominant wax deposition mechanism. However, there are other deposition mechanisms which can also play a role.

As most oil fields produce water along with crude oil, the deposition process for oil-water emulsions has also been investigated. Furthermore, carbon dioxide injection effects upon wax appearance temperature along its current applications onto wells have been reviewed.

Having a total awareness of the wax deposition mechanisms background is the key factor to prevent the wax precipitation and control the deposition of solid wax crystals.

Intelligent well technology is an oil and gas well optimization completion technology integrated with underground real-time monitoring, data analysis decision-making and remote control of downhole tools. It's of great significance to the transformation and innovation of China's oil and gas development projects. The author of this paper expounds the definition, principle, composition and characteristics of intelligent well technology, and introduces the development status quo of intelligent well technology abroad, including mature intelligent well system, key technology research of intelligent well and its application technology. After the introduction to the related technology research of intelligent well in China, the author puts forward some opinions on the development of our own complete intelligent well system.

Through precisely measured data of field outcrops, wells logging data and samples analytical data in the research area, it is considered that the topography of the sedimentary period of Xiaoheba formation is relatively flat, the water flow is shallow and wide and the fluctuation is frequent, the supply of source is abundant, and it has favorable sedimentary conditions to forming shallow-river fluvial-dominated delta. The delta in the research area is a distal-basin sedimentary, and due to multiple branches and long extension of the river channel, there are large area of delta front sand deposits with fine grained development, high maturity and underwater environment existed within the research area. The Xiaoheba formation in the Jiannan-Fuling three-dimensional seismic region has the obvious characteristics of strong peak progradation reflection. Based on the above analysis, the sedimentary mode of shallow-river fluvial-dominated delta of Xiaoheba formation of Southeastern Sichuan Basin is established and the reservoir forming conditions are discussed. It is considered that the Xiaoheba formation has excellent hydrocarbon source, high-quality reservoirs and effective migration channel. This research has certain guiding significance for the next stage of tight marine clastic rocks oil and gas exploration of Southeastern Sichuan Basin.

Borehole instability was frequently encountered during shale gas drilling. Most conventional models are not applicable to layered formation's wellbore stability analysis on account of anisotropic strength characteristic. In this study, an empirical equation for predicting anisotropic strength was implemented in the Mogi-Coulomb criterion to describe variations of cohesive strength and friction angle of shale formations. A collapse pressure model and its appropriate solution method for layered shale formations were proposed. The impact of different strength criteria and rock anisotropy type on rock strength and collapse pressure was investigated. The analysis indicated that the predicted strength of our modified criterion was usually higher than the weak plane failure criteria. The collapse pressure calculated by the modified Mogi-Coulomb criterion was lower than the weak-plane failure criteria. Furthermore, it was more consistent with real mud weight. Additionally, the anisotropy type of rock notably influences wellbore stability. More significant anisotropy coefficients correspond to higher strengths, which results in smaller collapse pressure values. Improper anisotropy coefficients can over-or under-predict the collapse pressure. Reasonable estimates of collapse pressure of anisotropic rocks can be made through the modified Mogi-Coulomb criterion using limited experimental data and the anisotropy rock type.

To address the fast productivity decline of the horizontal wells and low oil recovery during natural depletion in Baikouquan formation, the approach of solution gas re-injection was proposed with the primary objective of further developing this formation. Herein, a field-scale numerical compositional reservoir model was built up based on the formation properties and then the effects of permeability, fractures and formation stress on the production dynamics were thoroughly investigated. A sensitivity analysis, which can correlate the oil recovery with these parameters, was also performed. The results showed that the re-injection of solution gas could remarkably retard the production depletion of the horizontal wells thereby improving the oil production. The oil recovery rate increased with permeability, fracture half-length, fracture conductivity, and formation dip. With regard to the fracture distribution, it was found that the interlaced fracture outperformed the aligned fracture for the solution gas re-injection. The influence of the formation stress should be carefully considered in the production process. Sensitivity analysis indicated that the formation dip was the paramount parameter, and the permeability, fracture half-length, and fracture conductivity also played central roles. The results of this study supplement earlier observations and provide constructive envision for enhanced oil recovery of tight reservoirs.

High water-cut has become a worldwide challenge for oil production. It requires extensive efforts to process and dispose. This entails expanding water handling facilities and incurring high power consumption costs. Polymeric microsphere injection is a cost-effective way to deal with excessive water production from subterranean formations. This study reports a laboratory investigation on polymeric microsphere injection in a large volume to identify its in-depth fluid diversion capacity in a porous media with large pore/particle size ratio. The performance of polymeric microsphere injection was evaluated using etched glass micromodels based on the pore network of a natural carbonate rock, which were treated as water-wet or oil-wet micromodels. Waterflooding was conducted to displace oil at reservoir temperature of 95 °C, followed by one pore volume of polymeric microsphere injection. Three polymeric microsphere samples with median particle size of 0.05, 0.3, and 20 μm were used to investigate the impact of particle size of the polymeric microspheres on incremental oil production capacity. Although the polymeric microspheres were much smaller than the pores, additional oil production was observed. The incremental oil production increased with increasing polymeric microsphere concentration and particle size. As a comparison, polymeric microsphere solutions were injected into oil-wet and water-wet micromodels after waterflooding. It was observed that the oil production in oil-wet micromodel was much higher than that in water-wet micromodel. The wettability of micromodels affected the distribution patterns of the remaining oil after waterflooding and further dominated the performance of the microsphere injection. The study supports the applicability of microsphere injection in oil-wet heterogeneous carbonates.

Polymer flooding method has attracted wide attentions in petroleum industry because of its relatively simple process equipment, low cost of agents and good performance on enhancing oil recovery. However, common polymer can hardly meet the technical requirements of the oilfields with high salinity. Existing salt-resistance polymer solutions get a large viscosity in high salinity condition by changing polymer molecules aggregation which, however, may result in the poor adaptability between polymer molecules and the pore sizes of reservoir. β-cyclodextrin (β-CD), a kind of chemical agent, is found to enhance the injectivity of salt-resistance polymer solutions by wrapping the hydrophobic groupings of salt-resistance polymer molecules. For a certain reservoir, the addition of β-cyclodextrin into salt-resistance polymer solution can balance the effect of plugging the layers with high permeability and the purpose of diverting to the layers with low and medium permeability. In this paper, viscosity of polymer solution is tested in condition of different concentrations of β-CD. On that basis, experiments on seepage characteristics are carried out to evaluate the injectivity of salt-resistance polymer solution. Finally, an appropriate concentration of β-CD, which is added into salt-resistance polymer solution, is chosen to adapt a certain reservoir with heterogeneity.

Realistic implementation of nanofluids in subsurface projects including carbon geosequestration and enhanced oil recovery requires full understanding of nanoparticles (NPs) adsorption behaviour in the porous media. The physicochemical interactions between NPs and between the NP and the porous media grain surface control the adsorption behavior of NPs. This study investigates the reversible and irreversible adsorption of silica NPs onto oil-wet and water-wet carbonate surfaces at reservoir conditions.

Each carbonate sample was treated with different concentrations of silica nanofluid to investigate NP adsorption in terms of nanoparticles initial size and hydrophobicity at different temperatures, and pressures. Aggregation behaviour and the reversibility of NP adsorption onto carbonate surfaces was measured using dynamic light scattering (DLS), scanning electron microscope (SEM) images, energy dispersive X-ray spectroscope (EDS), and atomic force microscope (AFM) measurement.

Results show that the initial hydrophilicity of the NP and the carbonate rock surface can influence the NPs adsorption onto the rock surfaces. Typically, oppositely charged NP and rock surface are attracted to each other, forming a mono or multilayers of NPs on the rock. Operation conditions including pressure and temperature have shown minor influence on nano-treatment efficiency. Moreover, DLS measurement proved the impact of hydrophilicity on the stability and adsorption trend of NPs. This was also confirmed by SEM images. Further, AFM results indicated that a wide-ranging adsorption scenario of NPs on the carbonate surface exists. Similar results were obtained from the EDS measurements. This study thus gives the first insight into NPs adsorption onto carbonate surfaces at reservoirs conditions.

Water blockage after hydraulic fracturing is one of the major challenges in shale oil recovery which affects the optimal production from the reservoir. The water blockage represents a higher water saturation near the matrix-fracture interface, which decreases the hydrocarbon relative permeability. The removal of water blockage in the field is typically carried out by soaking the well (i.e., shut-in) after hydraulic fracturing operation is finished. This soaking period allows water redistribution, which decreases the water saturation near the matrix-fracture interface. However, previous field reports show that there is not a strong consensus on whether shut-in is beneficial in terms of production rate or ultimate oil recovery. Due to the large number of parameters involved in hydraulic fracturing and tight formations, it is challenging to select which parameter plays the dominant role in determining the shut-in performance. Furthermore, literature on field case studies does not frequently report the parameters which are of researchers’ interest. In other words, the challenge of evaluating shut-in performance not only lies on the complexity of parameters and effects involved within the reservoir, but also the limited number of field case studies which report a comprehensive list of fracturing and reservoir parameters.

This paper aims to investigate the effect of well soaking timing on shut-in performance. This idea to investigate the shut-in timing effect is motivated by the fact that in the field, shut-in can take place either immediately after hydraulic fracturing but before the first flowback (i.e., pre-flowback) or sometime after the first flowback (i.e., post-flowback). The timing of shut-in is believed to influence the production performance, because it dictates how much water is allowed to imbibe from the fractures to the matrix before the extended production. A numerical model is built and validated by a successful history match with numerous data from core-flood experiments. Our previous study shows that shut-in performance depends heavily on the desiccation state of the formation: in non-desiccated formations, longer shut-in (pre-flowback) results in a lower regained hydrocarbon relative permeability, but in desiccated formations, longer shut-in (pre-flowback) does not affect the regained hydrocarbon relative permeability.

In this study, our model further demonstrates that shut-in performed after the first flowback (i.e., post-flowback) can help ensure a higher regained oil relative permeability than shut-in performed before the first flowback (i.e., pre-flowback) in such non-desiccated formations. A mechanistic analysis on the water blockage mitigation from these two shut-in timings is also presented. As a result, this study proposes that flowback should be carried out immediately following hydraulic fracturing, even if an extended shut-in is to be performed later.

Rising global energy demand has encouraged engineers to create and design new methods to improve oil recovery from reservoirs. In this study, feasibility of using Henna extract as a natural surfactant and synthesized nanoparticles (Titanium dioxide (TiO₂), Silicon dioxide (SiO₂), Graphene and composite of TiO₂-Graphene) for reduction of oil-water interfacial tension has been experimentally investigated. Nanoparticles were synthesized via sol-gel method and XRD, FESEM, EDAX and FTIR tests were conducted to confirm the authenticity of this synthesizing materials. Nano-surfactants were stabled with a natural water-based suspending surfactant called Tragacanth extract, which could be introduced as a practical substitute for industrial nanoparticles' stabilizers in oil industry. After CMC determination of Henna extract surfactant, the optimal concentration of Tragacanth extract surfactant, with the purpose of nano-surfactants’ stabilization, was determined through particle size and zeta potential tests. Results of interfacial tension (IFT) measurements showed that the increase of Henna extract concentration from 0 wt% to 10 wt% reduced IFT between kerosene and water from 37.23 to 15.24 mN/m. Furthermore, adding 1 wt% of synthesized TiO₂ nanoparticle to the Henna extract surfactant at its CMC value reduced IFT from 18.43 to 14.57 mN/m. As an impact of this significant reduction in IFT value, oil recovery factor could be improved drastically during EOR operations. Results proved that TiO₂ nano-surfactant was as effective as industrial surfactants, which put human's and environment's health at risk and impose heavy economic strain on governments.

This work highlights the application of Artificial Neural Networks optimized by Cuckoo optimization algorithm for predictions of NMR log parameters including porosity and permeability by using field log data. The NMR logging data have some highly vital privileges over conventional ones. The measured porosity is independent from bearer pore fluid and is effective porosity not total. Moreover, the permeability achieved by exact measurement and calculation considering clay content and pore fluid type. Therefore availability of the NMR data brings a great leverage in understanding the reservoir properties and also perfectly modelling the reservoir. Therefore, achieving NMR logging data by a model fed by a far inferior and less costly conventional logging data is a great privilege. The input parameters of model were neutron porosity (NPHI), sonic transit time (DT), bulk density (RHOB) and electrical resistivity (RT). The outputs of model were also permeability and porosity values. The structure developed model was build and trained by using train data. Graphical and statistical validation of results showed that the developed model is effective in prediction of field NMR log data. Outcomes show great possibility of using conventional logging data be used in order to reach the precious NMR logging data without any unnecessary costly tests for a reservoir. Moreover, the considerable accuracy of newly ANN-Cuckoo method also demonstrated. This study can be an illuminator in areas of reservoir engineering and modelling studies were presence of accurate data must be essential.

The ageing of the Algerian oil and gas (O&G) installations has led to many incidents. Such installations are over 30 years old (life cycle) and still in operation. To deal with this O&G crucial problem, the Algerian authorities have launched a rehabilitation and modernization schedule of these installations. Within the framework of this program, many audit operations are initiated to elaborate a general diagnosis of the works to be performed while optimizing production. In other words, industrial ageing risks shall be controlled.

In the process safety management (PSM) context, the aim of this paper is to study ageing problem of the Algerian industrial installations through proposed indicators. Their prioritization adjusted by (TOPSIS) Technique for Order-Preference by Similarity to Ideal Solution method which allows identification of ageing control solutions of Algerian onshore fields.