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Natural gas foam flooding has good fluid control and formation blockage capabilities, but the high-temperature, high-pressure, and high-salinity environment puts forward higher requirements for the comprehensive performance of natural gas foam. The impact of different gas types on the overall performance of the foam system was evaluated via a high-temperature, high-pressure visual foam stirrer. It is found that nitrogen foam systems have strong stability but weak foaming ability, while carbon dioxide foam systems exhibit strong foaming ability but poor stability. The methane foam system showed relatively better and balanced foaming ability and stability, making it more suitable to oil fields. Ten surfactants were screened and the results indicated that α-olefin sodium sulfonate (AOS14, AOS12) and sodium dodecyl sulfate formed natural gas foam systems with better overall performance with methane. The effects of temperature, pressure, surfactant concentration, and foam stabilizers on the comprehensive performance of the methane-AOS14 foam system were investigated. With increase in the surfactant concentration, the foaming ability and stability of the methane-AOS14 foam system first increase and then decrease. Higher temperatures reduced the viscosity of the surfactant solution and decreased the interfacial tension between solution molecules, weakening the overall performance. Increased pressure facilitated the generation of denser foam with smaller diameters, slowing the liquid loss from foam films and enhancing the overall performance. Under high-temperature, high-pressure, and high-salinity conditions, polymer-based foam stabilizers enhanced the stability of the methane-AOS14 foam system by forming a spatial network structure on the foam film, with higher molecular weight yielding better effects. [ABSTRACT FROM AUTHOR]

To solve the problem that scale in oilfields can lead to a reduction of formation permeability and blockage of wellbore and production system pipelines, through the scale inhibitor-formation water compatibility experiment and the minimum effective scale inhibitor concentration experiment, three different types of surfactants are selected as adsorption promoters. Three different types of surfactants were selected as adsorption–desorption accelerators through dynamic core adsorption–desorption experiments. The results of the indoor experiment show that the three types of scale prevention agents selected can meet the environmental protection requirements of the sea area. The static scale prevention rate at high temperature (>120 °C) exceeds 80%, and the minimum effective concentration is less than 3.5 mg L−1. The preferred cation Gemini surfactant has a stable adsorption enhancement effect of the scale inhibitor under different water-bearing conditions and can effectively extend the squeezing life under complex formation conditions. The results improve the comprehensive economic benefits of the field and provide technical feasibility to significantly improve the scale prevention efficiency of the field. [ABSTRACT FROM AUTHOR]

Aiming at low permeability, high water content light reservoir with a recovery rate higher than 20%, an improved air injection enhanced heat flooding technology is applied by combining the combustion reaction flow and flue gas flooding mechanism. The method involves the injection of air into the reservoir, which reacts with the crude oil at temperatures ranging from 220 to 300 °C. This reaction consumes part of the oil, enabling effective evaporation and flow of the remaining oil. This process combines combustion reaction flow with flue gas flooding, using high-temperature oxidation reactions to mobilize residual oil. Experimental results from combustion tube tests demonstrate stable reaction fronts, peak temperatures reaching up to 550 °C, and a significant increase in recovery rates, reaching 73.8% in some cases. Field applications of this technology require maintaining high air flux and burning rates in low-permeability zones to ensure effective heat-driven evaporation. The geological model of the well group shows that the recovery factor of the target block can be increased by more than 20% by air injection based on the water drive recovery factor of 28%–30%. The oil exchange ratio can be less than 4000 sm3/m3 by optimizing the air injection rate and oxygen content. The research results provide technical feasibility for heat flooding to significantly improve oil flow and recovery in low-permeability light oil reservoirs. [ABSTRACT FROM AUTHOR]

Formation blockage caused by solid particle invasion and migration is the main reason for the decline of the geothermal reinjection capacity, especially in the weakly consolidated sandstone formation. In this paper, a novel evaluation model for the formation blockage risk in the geothermal water reinjection was established based on the particle bridging principle. Three kinds of solid particles were considered in this model, including the clay-sand particles self-generated in formation, and the invasive scale and suspended particles in reinjected water. A sensitivity analysis of factors influencing formation blockage risk was carried out. The results show that when self-generated particles, suspended particles, and scale particles act alone, the reinjection capacity decreases by 46.72%, 65.44%, and 42.90% after 5 years, referring to the reinjection test of a geothermal well in Xining Basin; when the above particles act at the same time, the reinjection capacity will be lost by 97.12% after 5 years, and 0.5 years later the well will have to be shut-in. Among the sensitive factor affecting formation blockage, the key parameters are the most sensitive, followed by the reinjection pressure, and finally, the composition and concentration of solid particles have less influence. Using key parameters including deposition coefficient, starting coefficient, and K-C coefficient in this model, the deposition range, migration mass, and the porosity–permeability relationship under different blockage conditions can be described flexibly. [ABSTRACT FROM AUTHOR]

Natural gas foam can be used for mobility control and channel blocking during natural gas injection for enhanced oil recovery, in which stable foams need to be used at high reservoir temperature, high pressure and high water salinity conditions in field applications. In this study, the performance of methane (CH4) foams stabilized by different types of surfactants was tested using a high pressure and high temperature foam meter for surfactant screening and selection, including anionic surfactant (sodium dodecyl sulfate), non‐anionic surfactant (alkyl polyglycoside), zwitterionic surfactant (dodecyl dimethyl betaine) and cationic surfactant (dodecyl trimethyl ammonium chloride), and the results show that CH4‐SDS foam has much better performance than that of the other three surfactants. The influences of gas types (CH4, N2, and CO2), surfactant concentration, temperature (up to 110°C), pressure (up to 12.0 MPa), and the presence of polymers as foam stabilizer on foam performance was also evaluated using SDS surfactant. The experimental results show that the stability of CH4 foam is better than that of CO2 foam, while N2 foam is the most stable, and CO2 foam has the largest foam volume, which can be attributed to the strong interactions between CO2 molecules with H2O. The foaming ability and foam stability increase with the increase of the SDS concentration up to 1.0 wt% (0.035 mol/L), but a further increase of the surfactant concentration has a negative effect. The high temperature can greatly reduce the stability of CH4‐SDS foam, while the foaming ability and foam stability can be significantly enhanced at high pressure. The addition of a small amount of polyacrylamide as a foam stabilizer can significantly increase the viscosity of the bulk solution and improve the foam stability, and the higher the molecular weight of the polymer, the higher viscosity of the foam liquid film, the better foam performance. [ABSTRACT FROM AUTHOR]

Oil production forecasting is an important task to manage petroleum reservoirs operations. In this study, a developed time series forecasting model is proposed for oil production using a new improved version of the adaptive neuro-fuzzy inference system (ANFIS). This model is improved by using an optimization algorithm, the slime mould algorithm (SMA). The SMA is a new algorithm that is applied for solving different optimization tasks. However, its search mechanism suffers from some limitations, for example, trapping at local optima. Thus, we modify the SMA using an intelligence search technique called opposition-based learning (OLB). The developed model, ANFIS-SMAOLB, is evaluated with different real-world oil production data collected from two oilfields in two different countries, Masila oilfield (Yemen) and Tahe oilfield (China). Furthermore, the evaluation of this model is considered with extensive comparisons to several methods, using several evaluation measures. The outcomes assessed the high ability of the developed ANFIS-SMAOLB as an efficient time series forecasting model that showed significant performance. [ABSTRACT FROM AUTHOR]

Underground CO2 storage is a promising technology for mitigating climate change. In this vein, the subsurface condition was inherited a lot of uncertainties that prevent the success of the CO2 storage project. Therefore, this study aims to build the 3D model under geological uncertainties for enhancing CO2 storage capacity in the Shahejie Formation (Es1), Nv32 block, China. The well logs, seismic data, and geological data were used for the construction of 3-D petrophysical models. The target study area model focused on four units (Es1 × 1, Es1 × 2, Es1 × 3, and Es1 × 4) in the Shahejie Formation. Well logs were utilized to predict petrophysical properties; the lithofacies indicated that the Shahejie Formation units are sandstone, shale, and limestone. Also, the petrophysical interpretation demonstrated that the E s 1 reservoir exhibited high percentage porosity, permeability, and medium to high net-to-gross ratios. The static model showed that there are lateral heterogeneities in the reservoir properties and lithofacies; optimal reservoir rocks exist in Es1 × 4, Es1 × 3, and Es1 × 2 units. Moreover, the pore volume of the Es1 unit was estimated from petrophysical property models, ranging between 0.554369 and 10.03771 × 106 sm3, with a total volumetric value of 20.0819 × 106 sm3 for the four reservoir units. Then, the 100–400 realizations were generated for the pore volume uncertainties assessment. In consequence, 200 realizations were determined as an optimal solution for capturing geological uncertainties. The estimation of CO2 storage capacity in the Es1 formation ranged from 15.6 to 207.9 × 109 t. This result suggests the potential of CO2 geological storage in the Shahejie Formation, China. [ABSTRACT FROM AUTHOR]

Geological storage of CO2 technologies has become an important and effective way to reduce the greenhouse gas emissions, especially when it is combined with CO2 enhanced oil recovery (EOR), which can not only trap CO2 but also enhance oil recovery. However, the risk of CO2 leakage has always been a prominent issue. In this paper, the mechanisms and pathways of CO2 leakage during geological storage in oil reservoirs were analyzed using fault tree analysis (FTR). Besides, monitoring technologies were discussed and deployed in a CO2 EOR demonstration project. The analysis results showed that the sealing failures of oil producer and CO2 injector wells, like well cement failure and casing failure, are the main reasons for the CO2 leakage, which has been observed in the oil field monitoring project. The monitoring results indicated that there is no large‐scale CO2 leakage, while relatively high and abnormal CO2 concentration in soil gas near some wellbores are observed, which indicates there is some leakage of CO2 through incomplete cement ring and well casing string. FTR results provide guidelines for monitoring and preventing of CO2 leakage during geological storage in oil reservoirs. The near‐surface monitoring methods, especially the soil gas monitoring technologies, can effectively detect the leakage of CO2, and are a proper method for CO2 leakage monitoring. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

In this study, we applied a two-phase flow model to simulate water and sand blowout processes when penetrating shallow water flow (SWF) formations during deepwater drilling. We define 'sand' as a pseudo-component with high density and viscosity, which can begin to flow with water when a critical pressure difference is attained. We calculated the water and sand blowout rates and analyzed the influencing factors from them, including overpressure of the SWF formation, as well as its zone size, porosity and permeability, and drilling speed (penetration rate). The obtained data can be used for the quantitative assessment of the potential severity of SWF hazards. The results indicate that overpressure of the SWF formation and its zone size have significant effects on SWF blowout. A 10% increase in the SWF formation overpressure can result in a more than 90% increase in the cumulative water blowout and a 150% increase in the sand blowout when a typical SWF sediment is drilled. Along with the conventional methods of well flow and pressure control, chemical plugging, and the application of multi-layer casing, water and sand blowouts can be effectively reduced by increasing the penetration rate. As such, increasing the penetration rate can be a useful measure for controlling SWF hazards during deepwater drilling. [ABSTRACT FROM AUTHOR]

The DF1-1 gas field, located in the western South China Sea, contains a high concentration of CO, thus there is great concern about the need to reduce the CO emissions. Many options have been considered in recent years to dispose of the CO separated from the natural gas stream on the Hainan Island. In this study, the feasibility of CO storage in the lateral saline aquifer of the DF1-1 gas field is assessed, including aquifer selection and geological assessment, CO migration and storage safety, project design, and economic analysis. Six offshore aquifers have been investigated for CO geological storage. The lateral aquifer of the DF1-1 gas field has been selected as the best target for CO injection and storage because of its proven sealing ability, and the large storage capacity of the combined aquifer and hydrocarbon reservoir geological structure. The separated CO will be dehydrated on the Hainan Island and transported by a long-distance subsea pipeline in supercritical or liquid state to the central platform of the DF1-1 gas field for pressure adjustment. The CO will then be injected into the lateral aquifer via a subsea well-head through a horizontal well. Reservoir simulations suggest that the injected CO will migrate slowly upwards in the aquifer without disturbing the natural gas production. The scoping economic analysis shows that the unit storage cost of the project is approximately US$26-31/ton CO with the subsea pipeline as the main contributor to capital expenditure (CAPEX), and the dehydration system as the main factor of operating expenditure (OPEX). [ABSTRACT FROM AUTHOR]

Jilin oilfield is conducting the first large-scale demonstration project on CO2 storage and enhanced oil recovery (EOR) in the northeast of China. A comprehensive monitoring program has been designed and deployed in the target reservoir of block H-59 using a wide range of techniques to monitor the injection and production systems, the CO2 migration fronts, and potential CO2 leakage pathways. Tube fault detection, corrosion inhibitors, anti-CO2 corrosion cement, and production dynamic analysis have been adopted to guarantee the safety at the well site. CO2 movement in the reservoir is detected mainly by gas tracer, electric spontaneous potential measurement, and fluid sampling. Near-surface environmental monitoring is also conducted around the injection site. Field experience has shown that the monitoring targets should be focused on the reservoir, near-surface, and injection and production systems. Applying monitoring techniques to ensure the integrity of wellbores can not only prevent the leakage of CO2, but also avoid the blind expansion of monitoring program scopes. It is reliable and economical to take full advantage of techniques based on wellbores to monitor CO2 movement in oil reservoirs with dense well patterns. Up to April 2013, nearly 21.7 × 104 tons of CO2 has been injected without obvious leakage caused by integrity failure of wells or the geological structure of reservoir. More than 96% of injected CO2 has been safely stored with the rest of injected CO2 normally breakthrough in the production wells. The preliminary monitoring experience obtained can provide valuable guidance for the future enlarged Jilin project and other CO2 EOR and storage operations. [ABSTRACT FROM AUTHOR]

Oil production forecasting is one of the essential processes for organizations and governments to make necessary economic plans. This paper proposes a novel hybrid intelligence time series model to forecast oil production from two different oil fields in China and Yemen. This model is a modified ANFIS (Adaptive Neuro-Fuzzy Inference System), which is developed by applying a new optimization algorithm called the Aquila Optimizer (AO). The AO is a recently proposed optimization algorithm that was inspired by the behavior of Aquila in nature. The developed model, called AO-ANFIS, was evaluated using real-world datasets provided by local partners. In addition, extensive comparisons to the traditional ANFIS model and several modified ANFIS models using different optimization algorithms. Numeric results and statistics have confirmed the superiority of the AO-ANFIS over traditional ANFIS and several modified models. Additionally, the results reveal that AO is significantly improved ANFIS prediction accuracy. Thus, AO-ANFIS can be considered as an efficient time series tool. [ABSTRACT FROM AUTHOR]