The lattice Boltzmann method (LBM) is implemented in the Particle Flow Code (PFC) as a pore-scale CFD module and coupled with the particulate discrete element assemblage in PFC using an immersed boundary scheme. The implementation of LBM and LBM-PFC coupling is validated with the analytical solutions in a couple of hydrodynamics and fluid-particle interaction problems, i.e., the accuracy of LBM as a CFD solver is verified by solving channel flow driven by a pressure gradient for which the closed-form solution is also derived; the accuracy of LBM-PFC coupling is validated by solving flow across a cylinder, Taylor-Couette flow, Kármán vortex street, and fluid flow through a cylinder array. To demonstrate potential applications of this coupling code, a perforation cavity subjected to axial fluid flush is then tested, showing that the collapse and reconstruction of sand arch in the perforation cavity can be reproduced in this coupling system. The developed system is ready for exploring more complicated physical issues involved in sand production.

Fabric of carbonate rock is the important foundation and one of main research contents for study on carbonate sedimentology, and has always been the attention of the academic circles. Botryoidal structures from the Sinian Dengying Formation in the Sichuan Basin is a kind of special carbonate fabric, the fabric is named after the shape of a grape. In this paper, from four aspects of the research status, the definition of the botryoidal structures and the related terms, the construction characteristics of the botryoidal structures, the component of the botryoidal structures, geochemical characteristics and the genesis of the botryoidal structures are reviewed. It points out the current research issues of botryoidal structures from the Sinian Dengying Formation in the Sichuan Basin, and put forward that future research should focus on the accurate analysis of its internal construction, precipitation mechanism of the major components, and the construction mechanism of botryoidal structures.

Chemical enhanced oil recovery (EOR) and particularly surfactant injection has recently received a great deal of attention. The suggested recovery mechanisms after injecting surfactants include wettability alteration and IFT reduction. If a surfactant is properly selected according to the environmental variables-such as pressure, temperature, salinity, it can lead to more efficient enhanced recovery from an oil reservoir. On the other hand, poor selection of the surfactant can result in a low recovery and can even become detrimental to the reservoir due to undesirable wettability alteration and possible rock dissolution resulting in a chemical reaction with displacing fluid and blockage of the pore space. Also, choosing the wrong surfactant without considering the rock mineralogy may result in high adsorption on the pore surface of the rock and unnecessary waste of resources. It is also worthy to note that surfactants are some of the most expensive chemicals used during EOR. Extensive literature review suggests that anionic surfactant are the preferred surfactant category for EOR especially when it comes to sandstone reservoirs. Occasionally, in specific situations a better performance have been reported after injecting cationic, non-ionic or mixtures of both surfactants, particularly when dealing with carbonate reservoirs. This paper presents in detail a review of the most commonly applied surfactants in EOR studies and the optimum application criteria for of each type. To the best of the Authors' knowledge, such detailed and comprehensive review is not available in the literature, presently.

Combined with the regional strata filling characteristics of Middle-Upper Cambrian, the present paper conducts a systematic research on sedimentary facies in the basin and its peripheral area by utilizing 164 field outcrops and drilling and coring data. Further, the method of “multi-factor comprehensive synthesis based on single-factor analysis” was employed to investigate the sedimentary facies and palaeogeography of the study area and establish the sedimentary facies model. Stratigraphic reveals that the study area represents the pattern of thin-northwest and thick-southeast by stretching northeast-southwest. Within the present basin, the pattern of “one thin and two thick” predominates, while outside the basin “four thin and three thick” filling feature was found. Sedimentary facies shows that the study area was featured by rimmed carbonate platform. Specifically, carbonate platform, slope and northeastern corner Qinling paleooceanic Basin and southeastern corner Jiangnan Bain was identified from the west to the east. The carbonate platform contains restricted platform, evaporation-restricted platform, semi-restricted platform and the platform margin. Single factor analysis and lithofacies palaeogeographic characteristics manifests that during Middle-Late Cambrian, the western Old land evolved into peneplain stage, and that the eastern and southwestern sub-sags remained connected to the open-sea to some extent. At the time, the shllow seawater circulation was relatively restricted, while the ancient seabed tended to be flat and evaporation characteristics significantly diminished. Secondary sea-level fluctuation intensively influenced the development of scaled grain beach. It is suggested that tide marginal beach, intraplatform shoal subfacies zone, along with Shiqian-SangZhi in southeast and Zhenba-Xinshan in northeast platform-margin beach subfacies zone to be preferable targets for the favorable reservoir facies zone and potential oil and gas reservoir area.

Some Authors believe that a minimum pressure gradient (called threshold pressure gradient (TPG)) is required before a liquid starts to flow in a porous medium. In a tight or shale oil formation, this TPG phenomenon becomes more important, as it is more difficult for a fluid to flow. In this paper, experimental data on TPG published in the literature are carefully reviewed. What we found is that a very low flow velocity corresponding to a very low pressure gradient cannot be measured in the experiments. Experiments can only be done above some measurable flow velocities. If these flow velocities and their corresponding pressure gradients are plotted in an XY plot and extrapolated to zero velocity, a non-zero pressure gradient corresponds to this zero velocity. This non-zero pressure gradient is called threshold pressure gradient in the literature. However, in the regime of very low velocity and very low pressure gradient, the data gradually approach to the origin of the plot, demonstrating a non-linear relationship between the pressure gradient and the velocity. But the data do not approach to a point of zero velocity and a threshold pressure gradient. Therefore, the concept of threshold pressure gradient is a result of data misinterpretation of available experimental data.

The correct interpretation is that there are two flow regimes: nonlinear flow regime (non-Darcy flow regime) when the pressure gradients are low, and linear flow regime (Darcy flow regime) when the pressure gradient is intermediate or high. The nonlinear flow regime starts from the origin point. As the pressure gradient is increased, the curve becomes a straight line demonstrating the linear flow regime. We have verified our views by first analyzing the causes of non-Darcy flow, and then systematically analyzed typical experimental data and correlations in the literature. We conclude that TPG does not exist. We also use several counter examples to support our conclusion.

The radial basis function neural network is a popular supervised learning tool based on machinery learning technology. Its high precision having been proven, the radial basis function neural network has been applied in many areas. The accumulation of deposited materials in the pipeline may lead to the need for increased pumping power, a decreased flow rate or even to the total blockage of the line, with losses of production and capital investment, so research on predicting the wax deposition rate is significant for the safe and economical operation of an oil pipeline. This paper adopts the radial basis function neural network to predict the wax deposition rate by considering four main influencing factors, the pipe wall temperature gradient, pipe wall wax crystal solubility coefficient, pipe wall shear stress and crude oil viscosity, by the gray correlational analysis method. MATLAB software is employed to establish the RBF neural network. Compared with the previous literature, favorable consistency exists between the predicted outcomes and the experimental results, with a relative error of 1.5%. It can be concluded that the prediction method of wax deposition rate based on the RBF neural network is feasible.

The productivity of a gas well declines over its production life as cannot cover economic policies. To overcome such problems, the production performance of gas wells should be predicted by applying reliable methods to analyse the decline trend. Therefore, reliable models are developed in this study on the basis of powerful artificial intelligence techniques viz. the artificial neural network (ANN) modelling strategy, least square support vector machine (LSSVM) approach, adaptive neuro-fuzzy inference system (ANFIS), and decision tree (DT) method for the prediction of cumulative gas production as well as initial decline rate multiplied by time as a function of the Arps' decline curve exponent and ratio of initial gas flow rate over total gas flow rate. It was concluded that the results obtained based on the models developed in current study are in satisfactory agreement with the actual gas well production data. Furthermore, the results of comparative study performed demonstrates that the LSSVM strategy is superior to the other models investigated for the prediction of both cumulative gas production, and initial decline rate multiplied by time.

Air injection in light oil reservoirs has received considerable attention as an effective, improved oil recovery process, based primarily on the success of several projects within the Williston Basin in the United States. The main mechanism of air injection is the oxidation behavior between oxygen and crude oil in the reservoir. Air injection is a good option because of its wide availability and low cost. Whether air injection can be applied to shale is an interesting topic from both economic and technical perspectives. This paper initiates a comprehensive discussion on the feasibility and potential of air injection in shale oil reservoirs based on state-of-the-art literature review. Favorable and unfavorable effects of using air injection are discussed in an analogy analysis on geology, reservoir features, temperature, pressure, and petrophysical, mineral and crude oil properties of shale oil reservoirs. The available data comparison of the historically successful air injection projects with typical shale oil reservoirs in the U.S. is summarized in this paper. Some operation methods to improve air injection performance are recommended. This paper provides an avenue for us to make use of many of the favorable conditions of shale oil reservoirs for implementing air injection, or air huff ‘n’ puff injection, and the low cost of air has the potential to improve oil recovery in shale oil reservoirs. This analysis may stimulate further investigation.

Rheological properties of hydrolyzed polyacrylamide (HPAM) solutions were measured in oscillatory and flow shear. In oscillatory shear the storage and loss moduli increased as the concentrations of the solutions increased, but they decreased as salinity increased. The relaxation spectra were plotted using the Kontogiorgos method. As shown in the relaxation spectra, the number of density of segmental units increased at first and then the peaks shifted and split into several as the concentration increased. With salinity increasing, the number of motion units increase and the peaks of segmental units became broader. In flow shear tests, the curves of viscosity versus shear rate were fitted by a power law equation. The result showed that the flow behavior index decreased with increasing concentration, while it generally increased with increasing of salinity. Furthermore, the first normal stress difference increased as the concentration was increased, while it decreased as the salinity was increased. The first normal stress differences measured by the rheometer were compared with the first normal stress differences calculated by the Laun equation and the results showed that Laun equation deviates the experimental results.

The Oil & Gas industry has continuously increased its requirements and together with the high complexity of technological systems and the higher competitiveness of markets, has compelled providers to implement adequate management strategies for these systems in order to improve their availability and productivity to meet those more demanding criteria.

In this context, the complex of RAM factors constitute a strategic approach for integrating reliability, availability and maintainability, by using methods, tools and engineering techniques (Mean Time to Failure, Equipment down Time and System Availability values) to identify and quantify equipment and system failures that prevent the achievement of the productive objectives. The application of such methodologies requires a deep experience and know-how together with the possibility of acquiring and processing data in operating conditions. This paper presents the most relevant aspects and findings of a study conducted for assessing the operational performance of a reciprocating compressor system package installed and used in the oil and gas' industries. The study was based on the analysis of the behaviour of states defined for each individual parts and component of reciprocating compressor and also aimed to identify and evaluate the effects of RAM-type factors and was conducted in collaboration with a private company that, for privacy reasons, will be named RC company. The Methodologies procedures used in this descriptive study were the bibliographical research, documentary and content analysis of the main literature. Adopting the most suitable maintenance strategy is one of the main challenges that maintenance managers face. The main purpose of this work is to propose a new approach to evaluate maintenance strategies.

In this study, three criteria called reliability, availability and maintainability (RAM) have been employed to compare to future maintenance strategies.

Steam Assisted Gravity Drainage (SAGD) as a successful enhanced oil recovery (EOR) process has been applied to extract heavy and extra heavy oils. Huge amount of global heavy oil resources exists in carbonate reservoirs which are mostly naturally fractured reservoirs. Unlike clastic reservoirs, few studies were carried out to determine the performance of SAGD in carbonate reservoirs. Even though SAGD is a highly promising technique, several uncertainties and unanswered questions still exist and they should be clarified for expansion of SAGD methods to world wide applications especially in naturally fractured reservoirs. In this communication, the effects of some operational and reservoir parameters on SAGD processes were investigated in a naturally fractured reservoir with oil wet rock using CMG-STARS thermal simulator. The purpose of this study was to investigate the role of fracture properties including fracture orientation, fracture spacing and fracture permeability on the SAGD performance in naturally fractured reservoirs. Moreover, one operational parameter was also studied; one new well configuration, staggered well pair was evaluated. Results indicated that fracture orientation influences steam expansion and oil production from the horizontal well pairs. It was also found that horizontal fractures have unfavorable effects on oil production, while vertical fractures increase the production rate for the horizontal well. Moreover, an increase in fracture spacing results in more oil production, because in higher fracture spacing model, steam will have more time to diffuse into matrices and heat up the entire reservoir. Furthermore, an increase in fracture permeability results in process enhancement and ultimate recovery improvement. Besides, diagonal change in the location of injection wells (staggered model) increases the recovery efficiency in long-term production plan.

Controlling sand production in the petroleum industry has been a long-standing problem for more than 70 years. To provide technical support for sand control strategy, it is necessary to predict the conditions at which sanding occurs. To this end, for the first time, least square support machine (LSSVM) classification approach, as a novel technique, is applied to identify the conditions under which sand production occurs. The model presented in this communication takes into account different parameters that may play a role in sanding. The performance of proposed LSSVM model is examined using field data reported in open literature.

It is shown that the developed model can accurately predict the sand production in a real field. The results of this study indicates that implementation of LSSVM modeling can effectively help completion designers to make an on time sand control plan with least deterioration of production.