This study examines mechanisms of wax and asphaltene precipitation and deposition, effects of the depositions on oil reservoir characteristics and performance, deposіtion prediction methods, deposition mitigation and removal techniques. Estimation results of several thermodynamic models of wax appearance temperature and subsequent deposition agree wіth each other. These estimations along with the limited field data comparisons suggest moderate success in modelling wax deposition, maіnly because wax deposits depend on temperature. Asphaltenes' nature is unclear. Its mechanisms of precipitation, flocculation, and deposition remain unclear. So, the reliability of any forecast and simulation models can be questionable. Although there is a lack of documented evіdence of any reliable method for predicting asphaltene deposіtion with high confidence, probably due to unrepresentative crude oil samples, there is reasonably good chemicals performance. These chemicals show that, if the deposition prevention is impossible, at least it can be controlled and managed. The lessons learned from different development projects and the best practices were used to define the flow assurance mitigation strategies. Since this study contains the necessary information on wax and asphaltene deposition, it can be used as a reference for further exploration of this field.

Summary An industry-accepted standard for minifrac analysis for evaluating and improving design of hydraulic fracturing treatments originated from the original Nolte analysis (Nolte 1979) of pressure decline, followed by the introduction of Castillo G-function in a Cartesian plot (Castillo 1987). The latter provides a graphical method for the identification of fracture closure pressures and stresses with subsequent derivation of other parameters such as fluid efficiency and fracture geometry. With the introduction of a more advanced consideration of the G-function interpretation for various reservoir conditions (Barree et al. 2007), subdividing the interpretation into calculations based on flow regimes and leakoff modes, this approach has become even more sophisticated. Particularly, interesting flow regimes and leakoff modes during fracture closure include the fracture height recession mode. This mode tends to result in rapid screenout and difficulty in placing high proppant concentrations. Regarding interpretation, the G-function derivative curve for this mode can have more than one plateau, an outcome that is possibly indicative of features that have not been widely considered to date or on which little to no data have been published. This paper presents a case study as an example of such height recession mode, along with a subsequent G-function interpretation and analysis and with consideration of the vertical facies distribution along the wellbore. Considerable attention is paid to the G-function derivative plateau analysis. Three distinctive wells, namely X-1,X-2, and X-3, are discussed. Using this technique can lead to an improved fracture calibration, optimized fracture design, and adoption of a successful completion strategy; additionally, the confirmation of 1D facies distribution can provide new insights into the fracture closure period.

Proppant flowback after hydraulic fracturing treatment is quite a serious challenge that causes damage to both downhole and surface equipment, leading to unwanted workovers and production suspension, or other negative outcomes. Some special methods including preventive as well as corrective measures already exist in the industry to overcome the proppant flowback problems. However, there is no clear guidance on how to choose the method for certain conditions, particularly during the hydraulic fracturing design stages. Therefore, the authors conducted a comprehensive review of fourteen preventive technologies to systematize them and to propose an initial decision-making approach. The following methods were considered in this paper: Resin Coated Proppants (RCP), RCP with Activator, RCP with Nanoparticles, Proppant with Liquid Resin Systems (LRS), Proppant with Surface Modification Agents (SMA), Proppant with Proppant Consolidation Aid (PCA), Cylindrical Proppant, Microfibers, Thermoset Resin Fibers, Thermoset Film Strips, Deformable Isometric Particles (DIP), Expandable Proppants, Polymer Surface Modified Proppants, and In-situ Formulated Proppants. The review reveals physical, chemical, and technological properties of each method to select criteria for effective screening. So, the reader could find the appropriate proppant flowback mitigation method corresponding to a particular reservoir and the well conditions during the initial hydraulic fracturing design stages.

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Production optimization problem in hydrocarbon reservoirs has garnered prime importance in the last few years. There are numerous methods to achieve the requisite and desired production rates. One such method is hydraulic fracturing, which has been used since the 1940s. Like many other technologies, hydraulic fracturing considers the usage of various chemicals for formulating the fracturing fluid. It has a concomitant challenge of optimal selection of such fluid as per the given conditions. The objective of this study was to validate the composition of hydraulic fracturing fluid for fracturing jobs in high-temperature Jurassic oil and gas reservoirs located in Western Kazakhstan. A series of laboratory tests were conducted to select suitable chemicals on a scientific and practical basis. Methods used were fluid thermal stability tests, shear test and stability test - all executed on Chandler 5550 rotational viscometer. Several other tests such as emulsion break test, water analysis, crosslinking time, pH measurement and gel tests were also performed. Herein, justifications from known sources are provided alongside the enumerated laboratory tests. Thus, gelling agents, crosslinkers, breakers and various additives such as demulsifiers, pH buffers, clay inhibitors and biocides were selected. Each component has its own chemical equivalent with the desired concentration. The formulated hydraulic fracturing fluid was successfully implemented in 20-ton hydraulic fracturing job in the Jurassic sandstone deposits with bottom-hole temperature up to 105 ℃ and a permeability about 3 mD. The operation was successful and resulted in production increase and promising long-lasting effects. HIGHLIGHTS One of the common problem in hydraulic fracturing jobs is a proper fracturing fluid design in compliance with well and formation conditions Series of lab testing such as fluid thermal stability tests, shear test and stability test, emulsion break test, water analysis, crosslinking time, pH measurement and gel tests were performed for the proposed fracturing fluid composition The optimal formulation of the hydraulic fracturing fluid was selected for operations at high temperatures of the Jurassic clastic formations, in particular at 105 ℃ at depths of more than 2,000 m GRAPHICAL ABSTRACT