Petroleum Research最新文献

In this study, Hypermesh and LS-DYNA numerical simulation software are used to build a multi domain coupling model of natural gas pipeline, including soil, pipeline, TNT explosive and air domain, and the non-reflection boundary conditions are set for the model. The TNT equivalent method is used to convert the physical explosion amount of natural gas pipeline into 1387.38 kg TNT explosive amount. The simulation results show that the physical explosion of pipeline forms an approximate elliptical crater with a width of 12.68 m and a depth of 4.12 m; the TNT equivalent of the model is corrected by comparing the crater simulation value and the size value of the crater calculated by the PRCI empirical formula under the same laying condition, and the correction coefficient is selected as 0.9, and the corrected TNT equivalent is 1248.64 kg; the modified model crater size is 3.72 m deep and 12.66 m wide, compared with the crater size obtained from the field test, the error of crater depth and width calculated by the modified model simulation is 5.7% and 15.5% respectively.

The study delves into pore structure attributes within the complex Eocene carbonate of an Indian offshore field, encompassing pore throat, radius and their characteristics. Nuclear Magnetic Resonance (NMR) experimental data reveals crucial insights into pore structures and fluid states. This study compares the NMR T₂ distribution curve with capillary pressure data from the Mercury Injection Capillary Pressure (MICP) technique, deriving linear and nonlinear conversion coefficients to transform NMR T₂ spectra into equivalent pore radius distribution. Pore radius-dependent porosity partitioning, linked to permeability and the distribution of irreducible water, is conducted utilizing NMR-derived data. Following the T₂ cut-off analysis, a two-segment fractal analysis of NMR T₂ distribution is also carried out. This analysis unveils associations between fractal dimensions and various petrophysical parameters, including permeability, porosity, T₂LM, irreducible water saturation and R₅₀. The NMR-derived pore radius distribution is mostly unimodal, occasionally slightly bimodal. Six different pore size classes (less than 0.05 μm to more than 5 μm) are analysed in relation to permeability, porosity and irreducible water. Small pores (<1 μm) contribute more to irreducible water with low porosity and permeability. The fractal dimension of large pores correlates strongly with porosity, permeability, T₂LM, irreducible water and R₅₀ suggesting significant impact on reservoir seepage capacity. In addition to porosity partitioning, the current study demonstrates effectiveness in modelling modified permeability and correlating it with in situ permeability when applied to field NMR log data from the study area. While numerous studies focus on sandstone, our study marks the pioneering attempt at a comprehensive analysis on complex carbonate reservoirs.

Permanent downhole monitoring systems are responsible for measuring pressure and temperature time series and enable uninterrupted reservoir characterization during the oil field production period, playing a key role in the oil and gas industry. Located in hostile pressure and temperature environments (i) close to the reservoir, in the case of the PDG (Permanent Downhole Gauge) sensor, and (ii) at the wellhead, in the case of the TPT (Pressure and Temperature Transducer) and PT (Pressure Transducer), its data are transmitted from the subsea environment to the Floating Production Storage and Offloading (FPSO), where the Master Control System (MCS) provides the information in engineering format. This information fulfills its function in the FPSO plant and finally is stored in an onshore data historian. Such complexity, importance, and maintenance difficulty of this system make it necessary to control and manage its reliability. Therefore, the objective of this work is to increase the availability and maximize the useful life of the downhole permanent monitoring system through the reliability calculation, using the Weibull estimate with 2 parameters, and the application of an index quality of statistical inferences. The proposed method for estimating reliability uses a database containing information from permanent downhole monitoring systems of the PDG, TPT, and PT type, from January 1st, 2008 to January 9th, 2014, and considers only the failures that occur until the arrival of the data in the MCS. From the reliability results, it can be observed that stratifications of this database could generate samples with a smaller number of observations, thus inferring reliability even with a small number of samples. The deepening of this method results in the definition of the minimum sample that allows removing reliability inferences without statistical significance and a quality index that allows classifying the reliability estimates of stratified sets of the largest sample of a database. It is worth mentioning here that both methodologies developed in this work are inserted in a well monitoring system that intends to contribute to increasing the availability of pressure and temperature data for the management of well operations.

Optimal and cost-effective drilling operations in extended-reach horizontal wells depend on efficient solid cuttings removal from the borehole. Several solids-suspended multiphase processes such as crude petroleum transportation, separation, and processing of oil and gas streams also require the efficient removal of these solids. The terminal settling velocity (V_ts) of the solid particle is a vital parameter that controls the removal efficiency of these solids. In a drilling scenario when there is a hold on fluid circulation such as connection time, the accurate estimation of V_s provides the driller with time available to prevent solid deposition. In severe conditions, this can result in a stuck pipe, especially for extended-reach horizontal wells. In this work, both spherical and non-spherical particle deposition were experimentally investigated in several fluid rheology and salinity. Two concentrations ($0.1vol\%$ and $0.05vol\%$.) of partially-hydrolyzed polyacrylamide (PHPA) were used as a drag-reducing additive for water-based drilling mud. The PHPA drag-reducing fluid (reduced pressure loss) acts as a turbulence inhibitor. The PHPA polymer chain suppresses any turbulence in the flow, reducing the turbulent eddy viscosity. The effects of salinity ($3wt.\%NaCl$ and $3wt.\%CaC{l}_2$ contamination) on solid particle settling velocity (V_s) in drag-reducing fluids were also investigated. Terminal velocity was achieved for all experiments and seemed to increase with increased diameter/sphericity. However, cases when this trend was not consistent were observed and therefore a new parameter of Φ (sphericity index × diameter) was proposed. V_s increases with Φ value for all cases. During drilling, PHPA also aids in sealing the fracture in the formation. With and without salt in the fluid, how lowering drag affected the settling velocity of solid particles (drill cuttings) could be observed. The settling velocity tests will be improved in drag-reducing PHPA solutions with the knowledge from this study.

Mantle plume is an essential component of the mantle convection system, and its influence on the geodynamics of continental rifts is of great significance for understanding the crust–mantle interaction. The East African Rift System, as the largest continental rift in the Cenozoic and in the initial stage, provides an excellent option for studying the interaction between the mantle plume and the continental crust. Based on the data such as GPS, seismic tomography, and global crustal model, a viscoelastic-plastic 2D thermodynamic numerical model is established to reconstruct the evolution of the Afar depression, Ethiopian Rift, and Kenyan Rift. By comparing the differences between the models of the Afar depression, Ethiopian Rift, and Kenyan Rift, the relationship between the mantle plume and pre-existing structures and their influence on the evolution of continental rifts are discussed. The results show that the mantle plume can increase the depth of the rift faults, concentrate the distribution of the faults, and strengthen the control of main faults on the rifts, allowing the possibility of narrow rifts. Pre-existing structures control the fault styles and symmetry of the rifts and also the morphology of the mantle plume.

When producing from conventional fields, the well rates are primarily constrained by the production-system in the early years of the field-life, while later in the field-life the production rates are primarily constrained by the reservoir deliverability. For the post-plateau production period, the reservoir deliverability will no longer potentially exceed the production-system well-rate constraints. Traditionally, analytical equations are used in a nodal analysis method that balances the pressure at the well inflow point from the reservoir (inflow performance relationship; IPR) with the pressure required for the vertical lift performance (VLP; or vertical flow performance; VFP) from the same point upward. A faster and simpler approach is proposed in the present study. Whereas, the classical IPR solutions are based on a constant well-rate solution of the diffusivity equation, use of a constant bottomhole pressure assumption can bypass the need for nodal analysis type pressure matching solutions to obtain the well rate. Instead, the well rate can be directly computed from the pressure decline in the reservoir and any production system capacity constraint can be imposed on the theoretical well rate due to the reservoir quality. The merits of the new approach are explained and illustrated by way of a detailed production analysis case study using open-access data from the Volve Field (Norwegian Continental Shelf). In addition, the case study of the Volve Field wells demonstrates a new water-breakthrough analysis method.

Karaganda Coal Basin bears the largest undeveloped reserve of coalbed methane (CBM) in Kazakhstan, which lacks water resources for implementing large-volume hydraulic fracturing. Cryogenic fracturing utilizing liquid nitrogen (LN₂) has been trialled in fields and is a waterless fracturing technique under intensive research these days. This study aimed to evaluate the cryogenic treatment efficacy of Karaganda coal samples as well as to understand the coal permeability evolution during the thawing period. X-ray fluorescent spectrometry (XRF) and microscope imaging identified the compositional and structural heterogeneities of coal specimens mined from different interlayers. Acoustic emission test, permeability measurement, and microscope imaging comparatively characterized the dry coal structure alteration before and after immersion into LN₂. Cryogenic treatment slowed down the S-wave velocity through coal specimens, enhanced permeability by over 65 % after temperature recovery as well as created new fractures, enlarged existing ones, and spalled coal particles. Dynamic permeability evolution against temperature rise during the thawing process has been successfully captured for the first time. Overall, the experimental measurements support that the LN₂ cryogenic fracturing technique would be effective in stimulating coalbeds for CBM production in Karaganda Coal Basin.

Production flow rates are crucial to make operational decisions, monitor, manage, and optimize oil and gas fields. Flow rates also have a financial importance to correctly allocate production to fiscal purposes required by regulatory agencies or to allocate production in fields owned by multiple operators. Despite its significance, usually only the total field production is measured in real time, which requires an alternative way to estimate wells’ production. To address these challenges, this work presents a back allocation methodology that leverages real-time instrumentation, simulations, algorithms, and mathematical programming modeling to enhance well monitoring and assist in well test scheduling. The methodology comprises four modules: simulation, classification, error calculation, and optimization. These modules work together to characterize the flowline, wellbore, and reservoir, verify simulation outputs, minimize errors, and calculate flow rates while honoring the total platform flow rate. The well status generated through the classification module provides valuable information about the current condition of each well (i.e. if the well is deviating from the latest well test parameters), aiding in decision-making for well testing scheduling and prioritizing. The effectiveness of the methodology is demonstrated through its application to a representative offshore oil field with 14 producing wells and two years of daily production data. The results highlight the robustness of the methodology in properly classifying the wells and obtaining flow rates that honor the total platform flow rate. Furthermore, the methodology supports well test scheduling and provides reliable indicators for well conditions. By utilizing real-time data and advanced modeling techniques, this methodology enhances production monitoring and facilitates informed operational decision-making in the oil and gas industry.

Parametric understanding for specifying formation characteristics can be perceived through conventional approaches. Significantly, attributes of reservoir lithology are practiced for hydrocarbon exploration. Well logging is conventional approach which is applicable to predict lithology efficiently as compared to geophysical modeling and petrophysical analysis due to cost effectiveness and suitable interpretation time. However, manual interpretation of lithology identification through well logging data requires domain expertise with an extended length of time for measurement. Therefore, in this study, Deep Neural Network (DNN) has been deployed to automate the lithology identification process from well logging data which would provide support by increasing time-effective for monitoring lithology. DNN model has been developed for predicting formation lithology leading to the optimization of the model through the thorough evaluation of the best parameters and hyperparameters including the number of neurons, number of layers, optimizer, learning rate, dropout values, and activation functions. Accuracy of the model is examined by utilizing different evaluation metrics through the division of the dataset into the subdomains of training, validation and testing. Additionally, an attempt is contributed to remove interception for formation lithology prediction while addressing the imbalanced nature of the associated dataset as well in the training process using class weight. It is assessed that accuracy is not a true and only reliable metric to evaluate the lithology classification model. The model with class weight recognizes all the classes but has low accuracy as well as a low F1-score while LSTM based model has high accuracy as well as a high F1-score.

Member 5 of the Upper Triassic Xujiahe Formation (T₃X₅) in central Sichuan Basin has made a breakthrough in exploration recently. However, this new stratum has not been investigated sufficiently with respect to basic geology, making its types and distribution of sedimentary facies unclear, which severely restricts its subsequent exploration evaluation. In this study, types of sedimentary microfacies in the first sand group of T₃X₅ (T₃X₅¹) are clarified through core observation and logging interpretation using core, log and seismic data, and then distribution of sedimentary microfacies in T₃X₅¹ is determined according to seismic waveform features and seismic prediction. The results show that T₃X₅¹ in the Dongfengchang area is mainly composed of deltaic deposits of several microfacies, such as delta front underwater distributary channel, sheet sand, and interdistributary bay. On seismic sections, different microfacies are significantly different in waveform features, the underwater distributary channel is characterized by one trough between two peaks, while diversion bay exhibits chaotic reflections between T6 and T51. The sedimentary microfacies varied greatly during the depositional period of T₃X₅¹ in the Dongfengchang area, this is because that the sediment supply was mainly controlled by the southwest and southeast provenance regions. Three superimposed underwater distributary channels are developed in the Dongfengchang area. The phase-1 superimposed underwater distributary channel in the northwest transition to sheet sand in the northeast, the phase-2 superimposed underwater distributary channel in the south extends shortly, the phase-3 superimposed underwater distributary channel in the northeast has a large development scale. These research findings are helpful to guide the subsequent exploration of T₃X₅ gas reservoir and also theoretically significant for investigating the depositional evolution of the Xujiahe Formation in central Sichuan Basin.