Most modern floating storage and regasification units (FSRU) are fitted with recondensing equipment that feed condensed boil-off gas (BOG) to the regasification unit in addition to a stream of liquefied natural gas (LNG) extracted from the cargo tanks. Use of the recondenser during regasification operations reduces gas losses on FSRU. It does so by avoiding consumption of excess BOG, with no associated commercial benefit, in gas combustion units (GCU), steam dumps, flares etc. Here we consider the benefits of also using the recondenser in recirculation mode, returning condensed BOG to the cargo tanks in the form of slightly warmed LNG. Such recirculation can be beneficial during periods of low or no gas send out from the FSRU, often achieving significant reductions in gas losses, although it is not standard practice in the industry to do so. Once regasification is halted not much BOG is required by the FSRU engine room, so the vessel must handle this excess. By condensing the BOG to LNG and returning it to the cargo tanks, the significant volume reduction involved has the beneficial impact of slowing down tank pressure increase. The saturated vapor pressure (SVP) of the LNG, linked to its composition and temperature, plays a key role in the boil-off rate and resulting cargo tank pressure changes. Detailed analysis is provided to explain how using the FSRU recondenser in recirculation mode can be best exploited by considering the prevailing fill levels, temperatures and pressures in each of the cargo tanks, and returning the condensed LNG preferentially to certain tanks. FSRU efficiency can be improved, gas losses and emissions can be reduced, and more cargo sold by exploiting the capabilities of the FSRU recondenser in recirculation mode. Running the FSRU in recirculation mode requires no equipment modifications to standard recondensers, neither does it increase FSRU operating costs.

Chemical flooding has been widely used in the oil industry since the 1980s for enhanced oil recovery (EOR) process. Previous studies have shown that the effectiveness of calcium carbonate scale inhibitors is affected by many factors, such as water composition, system pressure, temperature, production rates, pH etc. The breakthrough of the EOR chemicals in the production well could also affect scale formation process and interfere with the scale treatment program as well. However, the studies on the impacts of injected EOR chemicals to scale inhibitor performances are very limited. This paper presents the comprehensive laboratory study on the impacts of the EOR chemicals on CaCO₃ scale formation and prevention using static bottle and dynamic tube blocking methods. The EOR chemicals used in this study are a combination of surfactants and polymers. Three different types of inhibitors were evaluated: tri-phosphonate, penta-phosphonate, and polyacrylate based chemicals. Inhibition (%) from the bottle test and minimum effective dose (MED) based on the tube blocking method were determined for each inhibitor at 160 °F. Scale precipitates from the bottle tests were also characterized for morphology and polymorphs using environmental scanning electron (ESEM) and X-ray diffraction (XRD) techniques. Results suggest that the performance of scale inhibitors could be substantially affected by the EOR chemicals. In dynamic tube blocking tests, the MED values of inhibitors were increased roughly 10 times with the EOR chemicals. The static bottle tests showed considerable changes under the test conditions. The impact of EOR chemicals were also demonstrated by the remarkable ranges of crystal morphologies, changing from simple aragonite columns to nanorod, distorted spheroid, and flower-like superstructure in the presence of EOR chemicals and inhibitors.

Vaporization of water during both gas reservoir development and CO₂ geological sequestration in saline formations can cause salt precipitation with rapid loss of formation porosity and permeability. Water vaporization and precipitation of halite around a single well from stage production to CO₂ injection are studied to investigate the effect on reservoir properties in a gas reservoir. This paper identifies and quantifies post-flood dry zones and permeability changes in depleted gas reservoir after CO₂ exposure with the comparison in gas production period by performing the numerical simulation with the compositional simulator. Simulation results indicate that water vaporization and salt precipitation occur during gas production, and can be intensified by CO₂ injection. Dry supercritical CO₂ injection vaporizes the brine promoting brine concentration and halite precipitation. The simulation indicates a drying area with a radius of 78 m around wellbore after CO₂ injection. Porosity reduces with the most scope of 58%, and permeability can be decreased by up to 93.9% due to salt precipitation. And the injectivity is damaged by 99.77% at the end of injection period based on maximum permeability reduction. Moreover, six factors are investigated to conduct the influence analysis, showing that higher salinity brine, higher injection rate, higher irreducible water saturation, lower initial permeability, higher temperature and with capillary flow are conditions enhancing the salt precipitation due to dry CO₂ injection.

In this study, the physical and chemical characteristics and direct aqueous mineral carbonation of red gypsum have been investigated. The characterization studies showed that red gypsum is a very potential feedstock for mineral carbonation. It is mainly consisted of CaO, Fe₂O₃ and SO₃ along with some impurities. On the other hand, the carbonation results showed that direct aqueous carbonation of red gypsum resulted in CaCO₃ and FeCO₃ production, however, the carbonates purity and carbonation efficiency are still very low.

The porosity of the petroleum reservoirs is considered one of the most important parameters in reserve estimation because it determines the effective volume of the hydrocarbon that is stored in the reservoir. Based on the reserve estimation, the development plan can be set and managed. Porosity can be determined in the laboratory which is the most expensive methods. Porosity also can be determined from the logs such as density, neutron, sonic, and NMR logs. There are a lot of uncertainties in the porosity estimation from wireline logs because it depends on many statistical analysis and also is affected by the logging environment and logging tools. The prediction of the porosity from different porosity logs using artificial intelligence (AI) methods validated with the laboratory measured values is the best method to determine an accurate value of the rock porosity.

The objective of this research is to evaluate AI tools such as artificial neural network (ANN), support vector machine (SVM) and Adaptive neuro fuzzy inference system (ANFIS) to predict the reservoir porosity based on wireline log data. More than 1700 field measurements of porosity with logs data were used for training and testing the AI techniques.

The results obtained showed that ANN and ANFIS can be used to estimate the reservoir porosity based on log data with a high correlation coefficient (R) and low average absolute percentage error (AAPE). The main inputs required for porosity estimation are bulk density, neutron porosity, and sonic compressional time. The developed mathematical equation based on the weights and bias of the ANN model can be used to predict the reservoir porosity based on log data with a correlation coefficient of 0.98 and an AAPE less than 8%. The advantage of this work is that we extracted the mathematical model from the ANN that can be used directly to determine the porosity without the need for training and testing the data. The porosity estimation from the neutron-density crossplots, which is the current technique used by the industry, yielded 14.7% error.

An effective design and optimum production strategies of a well depend on the accurate prediction of its bottomhole pressure (BHP) which may be calculated or determined by several methods. However, it is not practical technically or economically to apply for a well test or to deploy a permanent pressure gauge in the bottom hole to predict the BHP. Consequently, several correlations and mechanistic models based on the known surface measurements have been developed. Unfortunately, all these tools (correlations & mechanistic models) are limited to some conditions and intervals of application. Therefore, establish a global model that ensures a large coverage of conditions with a reduced cost and high accuracy becomes a necessity.

In this study, we propose new models for estimating bottom hole pressure of vertical wells with multiphase flow. First, Artificial Neural Network (ANN) based on back propagation training (BP-ANN) with 12 neurons in its hidden layer is established using trial and error. The next methods correspond to optimized or evolved neural networks (optimize the weights and thresholds of the neural networks) with Grey Wolves Optimization (GWO), and then its accuracy to reach the global optima is compared with 2 other naturally inspired algorithms which are the most used in the optimization field: Genetic Algorithm (GA) and Particle Swarms Optimization (PSO). The models were developed and tested using 100 field data collected from Algerian fields and covering a wide range of variables.

The obtained results demonstrate the superiority of the hybridization ANN-GWO compared with the 2 other hybridizations or with the BP learning alone. Furthermore, the evolved neural networks with these global optimization algorithms are strongly shown to be highly effective to improve the performance of the neural networks to estimate flowing BHP over existing approaches and correlations.

Estimating the significance parameters, such as skin factor, permeability, wellbore storage coefficient, are the most component of transient pressure analysis. Many optimization algorithms have been applied to parametric estimation and realized the minimum error of well test curve. Although a flexible heuristic particle swarm optimization can hunt optimal solution rapidly, it is difficult to search further in the vicinity of the optimal solution. Hence, to alleviate the local optimum and premature convergence, a global hybrid algorithm referred to as particle swarm simulated annealing is proposed, and proves to have better performance of convergence and accuracy than traditional methods, which are more suitable for parameter estimation.

This paper proposed a new empirical K-value equation is developed to calculate dew pressure for gas condensate reservoirs. This equation is applicable in the wide ranges of composition, temperature, and pressure by considering the effect of composition via two equations for normal boiling point and critical temperature of the mixture. The range of dew pressure, temperature, heptane plus mole fraction, methane mole fraction, N₂ mole fraction, CO₂ mole fraction, and H₂S mole fraction are fallen into 2666.7-9655 Psia, 40-350.87 °F, 0.0021-0.213, 0.3344-0.9668, 0-0.4322, 0-0.0864, and 0-0.942 respectively. As an important point, the proposed equation has any adjustable parameters, in addition, this equation indicates that in order to predict of dew pressure of gas condensate reservoirs, trial and error was not needed and therefore, computational speed increases beyond the accuracy. Moreover, the accuracy is validated by comparing against the experimental data of 81 gas condensate reservoirs samples from published literature and the results of Wilson, Whitson, and Ghafoori equations. Compared to the experimental data, the absolute average deviations of dew pressure calculations for the proposed equation, Wilson, Whitson, and Ghafoori were 7.6%, 97.6%, 99.4%, and 94.9% respectively.

Along with the continuously go deep into of the research on coal series stratum, unconventional coal-derived gas gets more attention, including coalbed methane, shale gas and tight sandstone gas. However, selection evaluation as the basis and prerequisite for the exploration and development of unconventional coal-derived gas has great significance. The purpose of this paper is to set up a selection evaluation system, and this system is called selection evaluation on co-mining of “the three gas” in coal series stratum. If a basin exists these three gases at the same time, then we can use this evaluation system to evaluate this type of basin and choose dessert area, finally, for co-mining of “the three gas” in coal series stratum provide guidance. By choosing the main control factors of coalbed methane, shale gas and tight sandstone gas, and based on fuzzy mathematics, analytic hierarchy process theory and multi-level fuzzy comprehensive evaluation theory to research selection evaluation system on co-mining of “the three gas” in coal series stratum. Finally, 26 main control factors are selected, and then the index system is set up; in addition, by calculating the weight and establishing the membership function and evaluation set, and then selection evaluation system on co-mining of “the three gas” in coal series stratum with a four layer index is established. This paper can provide a theoretical basis and engineering guidance for unconventional gas exploration and development.

The effectiveness, viability and feasibility of applying Fenton reactants in treating soil contaminated with automatic gas oil (AGO) was investigated ex-situ. Soil was simulated to achieve 10% contamination using AGO (diesel) as the primary contaminant. Physicochemical properties and heavy metal contents were characterized using standard analytical methods, while total petroleum hydrocarbon (TPH) content was determined by molecular spectroscopy. An investigation of the soil physicochemical properties shows severe impact of the contaminant on pH, conductivity, phosphorus and (TPH) content. The optimum concentration of Fenton reactants determined from the optimization study was found to be 350,000 ppm H₂O₂ and 600 ppm FeSO₄ at optimum room temperature range of 27-30 °C and optimum pH of 4.7. The highly exothermic Fenton oxidation treatment resulted in significant decrease in TPH content by 87.6% after 6 h of periodic monitoring; breaking down the hydrocarbons into non-toxic environmental friendly products. Kinetics analysis and evaluation shows pseudo -first order mechanism for the Fenton treatment with a calculated rate constant of 0.226 h^-1 and half life of 3 h 4 min. The Fenton method is found to be very effective and efficient not only for the removal of the diesel contaminant, but also for the restoration of lost physicochemical properties occasioned by the effect of the contaminant. The environmental friendliness and fast response time towards effective clean up gives the technique a cutting edge advantage over other conventional methods. It therefore presents potentials for remediation experts in outright applications on real field challenges.

The change of velocity and pressure of flow field in suction and discharge chamber of five-cylinder plunger pump obtained by CFD under maximum and minimum stroke, the results show that: when the stroke is 79 rpm, the internal of pump head will produce pressure holding, and the internal organization of pump head body will be in a fatigue state of high pressure for a long time. When the rotate angle is small, the peak velocity at the gap of valve disc and valve seat reaches 9.60 m/s, which is the orifice jet phenomenon. When the stroke is 299 rpm, the overall velocity curve is relatively stable, but the velocity of fluid flow through the pump head body is larger, and the maximum velocity reaches 18.72 m/s at the bottom corner of valve, it will produce the circumfluence and vortex discharge chamber at the same time, which will cause the increase of vibration of pump head body. So it should use proper punching gear in order to conducive to overall working life of pump.

Projects involving the construction of rock salt underground gas storage have several disadvantages, for example, effective management is not employed to manage the production information and data in the process of the project, resulting in duplication of data storage, waste of storage space, lower efficiency of data calling, and negative effects on the efficiency of data update. Therefore, a database and its management systems for a rock salt gas storage was constructed based on an SQL Server database system, primarily including the management forms of the geological modeling, storage simulation, stability evaluation, economic evaluation, and covering the addition and delete checks of static and dynamic data. The security of the system was improved by setting the administrator permission. The establishment of the database management system was of tremendous importance and it provided a significant technical support for the development of the gas storage project.