Carbon dioxide-enhanced oil recovery (CO₂-EOR) has gained widespread attention in light of the declining conventional oil reserves. Moreover, CO₂-EOR contributes to the reduction of the global emissions of greenhouse gases through CO₂ sequestration in subsurface geologic formations. This method has been largely used in the petroleum industry for several decades especially for extracting oil from light-to-medium oil reservoirs approaching an advanced state of maturity. Traditionally, CO₂ is used in a continuous flooding scheme for EOR. However, continuous CO₂ flooding tends to be problematic due to unfavorable mobility, viscous fingering/channeling and early breakthrough of CO₂, especially in the presence of reservoir heterogeneities. In this paper, recent developments in the methods used to overcome these problems are reviewed. These developments include CO₂water-alternating-gas (WAG) injection, polymer-assisted CO₂ injection, surfactant-assisted CO₂ mobility control (CO₂-foam injection), and nanoparticle-assisted CO₂ flooding. Each method addresses, to an extent, one or more of the problems associated with conventional CO₂ flooding. Furthermore, incorporating more than one method can provide better performance in terms of CO₂ mobility control and oil recovery. In comparison with CO₂-WAG and CO₂-foam injection methods, the use of polymers and nanoparticles with CO₂ flooding is relatively new. These two new methods were mostly investigated experimentally, at the laboratory level, and they still need further development prior to field implementation.

The saturation calculation in complex reservoirs remains a major challenge to the oil and gas industry. In simple formations, a tendency towards simple saturation models such as Archie or Simandoux for clean and shaly reservoirs respectively is always preferable. These models were found to be working effectively in homogeneous formations within which the porosity and permeability are linked in the light of a simple facies scheme. Where the rocks show some degrees of heterogeneity, the well-logs are usually affected by different factors. This adversely results in a compromised or averaged log profiles that may affect the saturation calculations. Four wells drilled across a shaly sand of high heterogeneity have been studied in the Perth Basin, Western Australia. The aim is to resolve the hydrocarbon saturation and explain the high productivity results, despite the high water saturation, obtained through a conducted formation well test across the interested reservoir zones. A new integration technique between a suite of conventional and advanced logging tools together with the capillary pressure measurements has been carried out to generate a high-resolution reservoir saturation profile, that is lithofacies dependent. Three different independent methods were used in the studied wells to calculate the saturation and to reduce the uncertainty of the final estimated profiles. The methods are the resistivity-based saturation, the NMR-based irreducible saturation, and a new application through saturation height modeling. Furthermore, through the workflow, an effective calibration for the magnetic resonance T2 cutoff has been applied that is supported by the excellent reservoir production behavior from such complex reservoir. The methodology will help resolve the saturation calculation as one of the most challenging reservoir parameters, particularly where the resistivity logs are affected in complicated shaly sand environments. The effectiveness of the workflow shines the possibility to predict high resolution facies and saturation profiles in the lack of resistivity logs. A further possibility can complete the analysis on real time basis, which can certainly provide facies and saturation profiles extended to the uncored wells. Application of this methodology in the uncored wells has shown very encouraging results in various well trajectories, either vertical, deviated or horizontal long boreholes.

A great breakthrough was achieved on the Middle Devonian's oil-gas exploration in the Longmenshan area in northwestern Sichuan. However, only the Guanwushan Formation was researched in detail. The underlying formation -Jinbaoshi Formation as a set of the potential well reservoir and its reservoir characteristics have not been discussed. Based on the section's fine description, thin section analysis, and core borehole logging, combined with petrophysical analysis, the reservoir characteristics, controlling factors, and evolution process of the Jinbaoshi Formation reservoir in the Longmenshan area are deeply studied in this paper. The results showed that the Jinbaoshi Formation has developed a set of sand-shale interbedding deposit of terrigenous clastic and carbonate rocks. The reservoir lithology is mainly quartz sandstone and calcareous quartz sandstone. The quartz sandstone reservoir has good physical properties, but the calcareous quartz sandstone has the characteristics of strong heterogeneity, low porosity, and permeability. Residual intergranular pores are mainly developed in the reservoir space. And the development of intercrystalline pores and intergranular dissolved pores can also be seen, but the development frequency is low, and the scale is small. Among them, the Devonian Jinbaoshi Formation quartz sandstone's average porosity is about 8%, and the highest is 18.43%. The main diagenesis types of the Jinbaoshi Formation are compaction, recrystalization, and dissolution. Compaction is the main reason for the destruction of original pores, and dissolution is the main driving force for later porosity and permeability improvement. Rock fragments, calcareous silty clasts, and bioclastic grains are the main dissolution objects. The formation of intergranular dissolved pores significantly improves the physical properties of the reservoir. Therefore, the reservoir development of the Jinbaoshi Formation is mainly controlled both by favourable sedimentary facies and diagenesis. Quartz sandstone and calcareous sandstone of the Jinbaoshi Formation were controlled by early sedimentary facies in the syngenetic rock stage and developed more early intergranular pores; in the early diagenesis stage, compaction-pressure solution and cementation resulted in residual intergranular pores. In the middle-late diagenesis stage, the calcareous cement is dissolved, and more pores were formed.

The self-excited stick-slip oscillations of oilwell drillstrings are attributed to the nonlinear interaction between the drill-bit and the rock formation. Development of more accurate models will lead to improved predictions allowing more potential for successful suppression of the drillstring vibrations, thus reducing damage to the drilling system, prevention of expensive failures and increased output from the oilwell. In this paper, the effect of the transition from static friction to Coulomb friction on modelling of stick-slip phenomenon of oil well drill string is investigated through an analysis of the so called ‘decay factor’. Based on a distributed-lumped parameter model (DLPM) of the drilling system, the governing equations of motion for the system are obtained. By using different values of decay factor (low, high and medium), the stick-slip vibrations of the drill string are validated against published data from full-scale drill strings. The results from the simulation show that lowering the decay factor increases the critical speed and thus reduces the propensity for stick slip motion. However, a reduction in the decay factor also has the effect of inducing worse stick-slip motion once the critical speed has been reached. The results indicate the wider impact of both correct modelling of the decay factor, but also the importance of correct characterisation of the mud viscosity and drill/well contact for more accurate selection of drilling parameters in the field.

Working fluids loss is a major contributor to low productivity during production process of fractured tight reservoirs. Lost circulation control effect directly related to the tribological behavior between fracture surface and lost circulation materials (LCMs). In this study, the friction coefficient (FC) was investigated using typical clastic rocks and LCMs by considering multiple effect factors divided into external condition and internal condition. The results show that normal load had a relatively high effect on sliding model. A positive correlation was observed between FC and asperities heights. FC decreased induced by particle size degradation of rigid LCMs. Elastic LCMs manifested higher FC compared with rigid LCMs. Under the lubrication condition by working fluid, FC of rigid LCMs was mainly controlled by their surface wettability. FC of organic LCMs is more sensitive to high temperature aging than inorganic LCMs. Fracture plugging experiments show that LCMs optimized based on the research results can effectively improve the efficiency and strength of fracture plugging.

Many studies have analyzed the cumulative production performance in the SAGD (steam assisted gravity drainage) process by data-driven models but a study based on these models for a dynamic analysis of a SAGD production period is still rare. It is important for engineers to define the production period in a SAGD process as it has a stable and high oil production rate and engineers need to reset operational conditions after the production period starts. In this paper, a series of SAGD models were constructed with selected ranges of reservoir properties and operational conditions. Three SAGD production period parameters, including the start date, end date, and duration, are collected based on the simulated production performances. artificial neural network, extreme gradient boosting, light gradient boosting machine, and catboost were constructed to reveal the hidden relationships between twelve input parameters and three output parameters. The data-driven models were trained, tested, and evaluated. The results showed that compared with the other output parameters, the R² of the end date is the highest and it becomes higher with a larger training data set. The extreme gradient boosting algorithm is a better choice to predict the Start date while the artificial neural network generates better prediction for the other two output parameters. This study shows a significant potential in the use of data-driven models for the SAGD production dynamic analysis. The results also serve to support the utilization of the data-driven models as efficient tools for predicting a SAGD production period.

One of the promising and emerging enhanced oil recovery techniques in both sandstones and carbonates is engineered water injection (EWI). However, few studies discussed the field-scale applications of this technique in heterogeneous carbonate formations. This paper is an extension of our previous work of the EWI technology at core-scale. This research numerically investigates heterogeneity effect on EWI technique in carbonates at field-scale using five-spot models. Three synthetic five-spot sector models were considered including homogeneous, heterogeneous with permeability channeling, and heterogeneous with gravity underride.

The results showed that EWI improves both volumetric and displacement sweep efficiencies compared to conventional formation water injection (FWI) for all models investigated. Also, tracer method is recommended for better estimation of volumetric sweep efficiency as opposed to fractional flow method. Moreover, secondary EWI outperforms other techniques including secondary FW and tertiary EWI. In addition, the observed delay in tertiary EWI can be reduced by increasing well injection pressure and sulfate concentration in the engineered water. An optimum sulfate concentration of 25,000 ppm is recommended for achieving the highest oil recovery by EWI. This study gives more insight into understanding the performance of the EWI technique at field-scale. Recommendations for boosting the performance of this technique have been discussed, which assure more certainty and lower risk.

As a clean and abundant unconventional natural gas resource, natural gas hydrate (NGH) holds the characteristics of safety, high efficiency and sustainable exploitation, which helps to alleviate the energy shortage of China, reduce the foreign-trade dependence of oil and gas, and ensure the national energy security. Microwave heating is a significant method that has been used in natural gas hydrate exploration. By using the microwave heating, the NGH in the reservoir formations would be heated, decomposed and stimulated thanks to taking advantage of microwave heating's unique characters: efficiency, high speed, clean and pollution-free. This paper established the temperature under microwave heating gas hydrate distribution theory model, and by using the finite element method for simulating temperature field of microwave heating gas hydrate, this paper analyzed the natural gas hydrate in the microwave field temperature distribution in the influencing factors. Microwave has a significant heating effect on the hydrate reservoir in the immediate vicinity of wellbore, and it is not affected by the initial conditions of reservoir. The temperature can rise to above 50°C within 1 h which is higher than the phase equilibrium temperature at the time of hydrate decomposition and is helpful to improve the decomposition rate of hydrate. The frequency is set at 915 MHz, and the feed port has a spiral arrangement with a length of 10 mm, which greatly expands the microwave heating range.

Shale gas production has become the main driver of global gas production growth. Deep shale gas is difficult to extract, which puts forward higher requirements for drilling speed increase. The downhole power drilling tools are mainly screw drilling tools. Conventional screw drill tool stator bushing has poor heat dissipation, which is prone to thermal hysteresis failure, shortening drilling tool life, and is not suitable for high temperature and high pressure environment of deep shale gas wells. Equal wall thickness screw drilling tools and hydrogenated nitrile rubber have better high temperature resistance. Therefore, based on the thermal aging experiment and constitutive model of the rubber changes the displacement of the inner cavity of the stator bushing and the difference between the front and the back is up to 21.6%. The increase of the interference and eccentricity between rotor and motor leads to the increase of the maximum von Mises stress of the stator bushing and the thermal hysteresis temperature. The influence of the interference is greater than the influence of the eccentricity so that the interference should be given priority in the design. This paper provides a theoretical reference for the design and optimization of equal wall thickness bushing of positive displacement motor.

This paper presents an experimental and analytical study of comprehensive effects of surfactant and polymer in aqueous solutions on the propagation in carbonates. Single-phase flow tests of surfactant, polymer and surfactant-polymer mixture were respectively conducted on natural carbonate core plugs at high temperature and high salinity reservoir conditions. The effect of different factors on chemical propagation was taken into account by use of a convection-dispersion model. The dynamic adsorptions of two amphoteric surfactants at 2000 mg/L concentration onto the carbonate rocks were 0.21 and 0.17 mg/g-rock, respectively. The dynamic adsorptions of a sulfonated polymer at 2000 and 5000 mg/L were 0.11 and 0.17 mg/g-rock, respectively. Surfactant-polymer mixtures in aqueous solutions were co-injected to evaluate their competitive adsorption, showing the surfactant adsorption was reduced by approximately 50%. The dispersion coefficient of the chemicals in the carbonate cores was in the magnitude of 10⁻³ cm²/s. Caused by dispersion and adsorption, chemical concentration reduction occurred obviously during the propagation in carbonate porous media. Chromatographic separation took place in the surfactant-polymer co-injection scheme, which was estimated by modeling as well.

There is a direct link between the extent of formation damage and the filtration volume of the drilling fluids in hydrocarbon reservoirs. The filtration volume can be diminished by adding different additives to the drilling fluids. Recently, nanoparticles have been extensively used for enhancing the filtration characteristics of the drilling fluids. However, there is no reliable model for investigating the influence of this class of additives on the performance of drilling fluids. Hence in this study, two powerful tools ELM (extreme learning machine) and PSO-LSSVM (particle swarm optimization-least square support vector machine) are applied to determine the effect of various nanoparticles on the filtration volume. The assessment of the models is carried out by computing the statistical parameters, and it is found that ELM has a greater ability to predict the filtration volumes, while PSO-LSSVM performs satisfactorily too. The model predictions and experimental results are in excellent agreement as suggested by the values of root mean squared error (RMSE = 0.2459), coefficient of determination (R² = 0.999), and mean relative error (MRE = 2.028%) for the dataset. The statistical analysis shows that the suggested model can predict the filtration volume with great accuracy. Moreover, through sensitivity analysis of the input parameters, it is found that for a specified nanoparticle, the filtration volume is highly influenced by nanoparticle concentration and it is the essential variable for the optimization process.

Enhanced geothermal system (EGS) is considered to be the most effective way to mine hot dry rock. A conceptual model of rock mass-fracture-rock mass was established to study the limitation of temperature, insulation and heat transfer on the temperature field of enhanced geothermal system and supercritical carbon dioxide enhanced geothermal system. The temperature field of the rock mass under three boundaries for 30 years has been obtained. Effects of fluid velocity, specific heat capacity and thermal conductivity of rock mass on the temperature field were studied. The results show that boundary conditions have a great influence on temperature change of the reservoir. Under three boundary conditions, flow velocity of the fluid has a great influence on the temperature. But thermal conductivity and specific heat capacity of the rock mass have a little influence on the temperature. Under the same boundary conditions, heat exchange effect of the supercritical carbon dioxide enhanced geothermal system is significantly better than that of the traditional enhanced geothermal system.