Journal of Petroleum Science and Engineering最新文献

Current flow models for fault-karst reservoirs are mostly described as a single fault formation, which cannot be applied in recent-developed multibranched fault-karst reservoirs. This paper established a novel analytical model to investigate pressure response behavior of a horizontal well in multibranched fault-karst reservoirs. The model is able to describe the influence of the physical properties and spatial structure of fracture-cave system on pressure transient response. The flow model considers different flow behaviors in each region, which includes Darcy flow (gravity included) in fault-fracture, large-scale storage flow in karst-cave, and Poiseuille-law-based horizontal laminar flow in the horizontal wellbore, respectively. These assumptions enable the model to match complex situations in multibranched fault-karst reservoirs. Then, the model was retrograded to compare with a single fault-karst reservoir model to verify its accuracy. Further, the solutions were graphed on log-log plots, and we discussed the effect of fluids mobility, formation storability, and structure characteristics (e.g., length, angle, depth, distance) of fracture-cave branches on transient pressure responses. Results show that (a) the number of fracture-cave branches in a reservoir can be directly observed by counting the number of V-shaped appearances on the pressure derivative curve. (b) The exact shut-in time when V-shape appears is affected by volume and distance between two neighboring fracture-cave branches. (c)The characteristics of the V-shape are affected by fluid mobility, formation storability, and length of fracture region. (d) The slope of the pressure derivative curve in the boundary-dominated flow regime can be used to evaluate the gravity effect. (e) The pressure response behavior exhibits a near-well effect when a horizontal well commingled production in the multibranched fault-karst reservoir. Finally, we applied our model and resulting observations to analyze pressure build-up data tested from SHB Oilfield, which demonstrated a workflow to identify the number of fault-karst branches and also to estimate reservoir properties.

Trapping of drops due to wettability contrast in porous materials emerges in a variety of subsurface and manufacturing applications. In carbon capture and storage, carbon dioxide must be trapped in order to avoid its release into the atmosphere, while trapped oil must be displaced. Both carbon dioxide and oil can exist as drops in porous media. The migration of a single drop attached to a wall can be hindered if the wall surface has a different wettability. However, the trapping condition becomes more complicated in the presence of two or more drops. In this work, we aim to study the trapping mechanism during thermocapillary migration of a merging drop on a heterogeneous surface. To do so, numerical simulations have been performed using the Front-Tracking/Finite Volume Method, where the Navier-Stokes equations are coupled with the conservation equations. The generalized Navier boundary condition (GNBC) has been used as the slip model to remove the viscous singularity. The combined finite-volume and tracking method is able to deal with different types of discontinuities in compressible or incompressible fluid flows, as e.g., interfaces. The material properties of the drop and the ambient fluid are different, and surface tension depends on the temperature. The results have shown that there exist three regimes characterizing the motion of merging drops, including the passage of the leading drop, the trapping of the merging drop, and the partial trapping, which correspond to the trapping of the leading drop but the passage of the merging drop. We show that there is a critical wettability contrast at which the merging drop gets trapped. The effects of Marangoni number (Ma) and viscosity ratio are investigated. The critical wettability contrast decreases with the increase of Ma number and the regime shift as a function of the viscosity and Marangoni number. These findings have implications for the design of geological carbon dioxide storage, improvement of oil recovery and microfluidic device development.

Cuttings-beds formation is an issue that must be considered during all wellbore drilling operations. This problem increases at highly deviated or horizontal wells, where cuttings removal efficiency becomes one of the most critical elements for the whole drilling operations. Removal of drilled cuttings is done through circulating the drilling fluid and then separate out the cuttings at the surface. When the wellbore is inclined or horizontal, the cuttings tend to settle and form cuttings-beds. The consolidation strength of these cuttings-beds is normally unknown. Traditional studies on cuttings-bed removal usually focus on the final result: effective cuttings-bed removal. The scope of this study is to analyze the wetted cuttings-bed particle bonding strength and the stress required to break the formed bed, by means of granular rheology methodology. In other words, the strength required to erode a formed cuttings-bed is addressed independently. Wet-granular rheology techniques, complemented by Mohr-Coulomb envelop analysis has shown to be an effective approach to describe the cohesive strength of consolidated cuttings-bed and flowability of the particles within the beds. We have analyzed simulated cuttings-beds’ shear strength and flowability using quartz particles saturated with water, water-based drilling fluid and oil-based drilling fluid. The results showed that the interstitial fluid and its composition significantly impact the shear strength of the bed, conveying higher cohesion for water-based drilling fluid in comparison to oil-based drilling fluids.

In recent years, the Shunbei karst-carbonate reservoirs becomes a huge productivity oilfield, which produced over one million tonnes crude oil annually. However, there are difficulties in understanding production contribution of each fault-karst branch in reservoirs, which significantly impacts the efficient development. Multibranched fault-karst reservoirs in the Shunbei have an obvious tree-shaped geostructure, in which the natural fractures and eroded cave develop along multiple large-scale faults. The existing models for pressure transient analysis (PTA) were mainly established for fracture-cave reservoirs only with single fault, which cannot be applicable to characterize the multibranched fault-karst reservoir. To fill this gap, a novel analytical PTA model for horizontal commingled production well in the multibranched fault-karst reservoir was established to describe pressure response and identify flow regimes. First, our model includes the Darcy flow with the fluid compressibility effect in fracture region, and the large-scale vertical storage flow in cave region as well as the horizontal laminar flow in the horizontal wellbore. Then, the accuracy of this PTA model is verified by comparing it with the existing single branch fault-karst pressure model. Further, we applied the model to analyze the Shunbei oilfield case data. Last, the effect of boundary type, fluid compressibility effect, fracture physical properties, and cave spatial distribution on the pressure response are discussed in detail. The sensitivity analysis results show (a) the cave storage flow regime exhibits an obvious unit-slope-line on pressure derivative curve, at the time the skin transient flow constitutes a V-shape characteristic. (b) The number of fracture-cave branches can be directly obtained by counting the number of V-shaped appearances on the pressure derivative curve. (c) The fluid compressibility effect leads to an upward trend on the pressure and its derivative, reservoir engineers should be cautious to explain that characteristic as a closed boundary effect. (d) The cave volume and cave position control the timing of the V-shape occurring. As the cave volume increases, the linear flow regime lasts longer and the V-shaped feature becomes apparent. With the cave distance and cave depth increasing, the V-shape characteristic comes later. This work can provide technical support for accurate characterization of multibranched fault-karst reservoirs, and give a type curve analysis method for rapidly diagnosing the spatial location of each karst cavity by analyzing bottom-hole pressure.

Porosity estimation is a fundamental input for reservoir management and petrophysical characterization, and this feature is usually estimated based on laboratory measurements or through the use of well-logs. As an important resource for porosity quantification, nuclear magnetic resonance (NMR) well-logs are extremely useful; they allow geologists and petrophysicists to rapidly quantify different types of porosities (including total, effective, and free fluid porosity), and to perform a full formation evaluation and a reservoir quality analysis. However, the activation of wireline tools, the signal-to-noise ratio, the environmental conditions, and the characteristics of the formation fluid can create expensive and adverse conditions for subsurface acquisition. This research aims to develop machine learning models for the creation of synthetic NMR well-logs, assisted by auxiliary well-logging features. Four supervised models: multilayer perceptron neural network, AdaBoost, XGBoost, and CatBoost, comparing the adjusted R² and RMSE. Of these, the CatBoost regressor provided the most highly optimized model. It was able to reduce local dissimilarities with the real dataset, and returned a better global metric score, yielding an adjusted R² of 0.87 and an RMSE of less than 0.01. Moreover, all of the machine learning models provided substantial improvements in total porosity estimation, particularly compared to conventional empirical calculations based on density and sonic well-logs. An improvement of 0.5520 in the adjusted R² was achieved for the density porosity, and 0.2 for the sonic porosity. The differences between real NMR well-logs and the machine learning outputs were in general less than 5%, for most of the well-logging interval. In addition, a tree boosted porosity model based on well-logs is presented for the first time, and the contributions and impacts of the input features on the model predictions are explored. Finally, the behaviors of the linear and nonlinear features of the model are examined, which allows us to better understand the complex relationships among the features and the dataset used.

Asphaltene deposition in pipelines disrupts the normal transportation of the fluid produced. The deposition within the pipeline depends on the content of saturates, aromatic, resin, and asphaltenes (SARA) in crude oil. SARA analysis is used in the petroleum industry to estimate the stability of asphaltenes. In this study, a new set of correlations has been developed using regression analysis and the MATLAB curve fitting tool. The SARA fractions and the colloidal instability index (CII) are correlated with density, viscosity, and the combination of density and viscosity. SARA analysis data from 310 crude oil samples were used to develop the correlations while field data from 29 unique crude oils were used for validation. The best-fit correlations are selected based on statistical indicators such as the correlation coefficient (R²), the root mean square error (RMSE), and the average absolute relative error (AARE). Asphaltene stability plots were also developed for the new density-based CII (DBCII), viscosity-based CII (VBCII), and the density-and-viscosity-based CII (DVBCII). Based on statistical indicators, analysis of results shows that the density-based correlations for the SARA fractions are relatively more accurate than the viscosity-based correlations. The R-squared value for the DBCII is 0.7031 compared to 0.3234 for the VBCII and 0.6875 for the DVBCII. However, the percentage accuracy of 83% for the DVBCII is higher than the accuracy of the existing methods. The newly developed deposition envelopes are divided into stable and unstable regions that can be used to determine the stability of the asphaltene based on the physical properties of crude oil. The newly developed correlations for each SARA fraction based on the oil density eliminate the requirement for the laborious and time-consuming SARA analysis. Therefore, it is useful to predict the stability of asphaltene based on the physical properties of crude oil.

Geothermal heat pump (GHP) systems have been established as a proven technology for cooling and heating residential, public and commercial buildings. There is a geothermal solution to the ambitious goal of decarbonizing the space heating and cooling, which is contingent on the successful deployment of the GHP technology. This in turn requires accurate site characterization, sound design methodologies, effective control logic, and short and long-term (life-cycle) performance analysis and optimization. In this article, we review the aforementioned aspects of the vertical closed-loop GHPs specifically focusing on the important role of the subsurface. The basics of GHP technology are introduced along with relevant trends and statistics. GHPs are compared with similar technologies such as air source heat pumps (ASHP) along with the effects of deployment on the grid peak load. We then review the common system architectures and the growing trends for deeper boreholes and the drivers behind it. Various methods for design, sizing, and simulation of GHPs are introduced along with software tools common in research and industry. We then move to subsurface characterization, drilling and well construction of vertical boreholes. Long-term performance monitoring for GHP systems is an important source of information for model validation and engineering design and is garnering increasing attention recently. Data science is another field that is growing rapidly with its methods increasingly utilized in GHP applications. The environmental aspect of GHPs is briefly reviewed. Finally, concluding remarks are given to summarize the review and highlight the potential of petroleum engineering expertise and methods in GHP applications.

To better provide zonal isolation for the production of oil and gas, low-density oil well cement (LD-OWC) filling a deep oil well was developed to reduce the high hydrostatic pressure caused by the cement slurry. The key mechanical properties of LD-OWC and related cracking susceptibility, nevertheless, have not been fully understood. This work was to characterize the elastic and creep properties of LD-OWC using microindentation and assess the radial cracking risk of the cement sheath. With two types of LD-OWC cured at different temperatures, our measurement through mercury intrusion porosimetry (MIP) showed that their porosities depended on the slurry densities level, and the basic creep exhibited a logarithmic increase in the long term. Mechanical properties such as Young's modulus (E), indentation hardness (H), and creep modulus (C) of LD-OWC were statistically characterized, in particular, E and C were in line with those obtained by macroscopic tests. Moreover, a viscoelastic sheath model was developed to evaluate the stress redistribution in the steel casing, the cement sheath, and the formation in the long term. We found that lower slurry densities of OWC reduced the risk of radial cracking. Taking advantage of parametric analysis, the power-function correlation between the safety factor of radial cracking and the mechanical and geometrical sheath properties was also demonstrated.

The occurrence characteristics of shale oil have a significant impact on its mobility and the ultimate oil recovery. How to quantitatively characterize the occurrence and distribution characteristics of shale oil is a challenging task. Accordingly, the laser scanning confocal microscopy (LSCM) combined with saturated oil experiment is used to quantitatively characterize the pseudo in-situ occurrence characteristics of light and heavy components of shale oil in sub-micron scale in Fengcheng Formation of Mahu Sag. Furthermore, the main controlling factors of light and heavy components’ occurrence characteristics are comprehensively investigated in this study. The results show that: (1) Shale wettability significantly affects the occurrence state of shale oil. The heavy components are prone to exist on the surface of oil-wet minerals and organic matter of shale compared with light components. (2) Shale oil is relatively rich in bright laminas and the content of light components is higher in contrast to dark laminas. (3) The temperature has a greater impact on the heavy components and pressure has a multistage impact on the occurrence state of shale oil. The microscopic preferential fluid occurrence index, ${\Delta \varnothing }_{H-L}$, is proposed to interpret the microscopic occurrence mechanism of the light and heavy components under different pressure conditions, which provides a new perspective on the shale oil occurrence mechanism. (4) Shale oil is not easy to be enriched in dolomitic lumps and alkaline minerals due to their low pore development level. Overall, the outcomes of this study are of great significance to the understanding of shale oil enrichment mechanism.

In the gas injection process for enhanced oil recovery (EOR), the interfacial tension (IFT) and the minimum miscibility pressure (MMP) are two key parameters for evaluating the miscibility condition. The vanishing interfacial tension (VIT) method is an efficient method for measuring the interfacial tension of oil and gas versus pressure and can estimate the minimum miscibility pressure. A problem in the VIT test of a hydrocarbon system is that during this test, oil and gas densities vary due to the composition variation of both phases. But in the conventional interfacial measurement, this issue is ignored, and the initial and non-equilibrium densities are utilized for estimating the interfacial tension. In this study, it is tried to nominate a novel method for estimating the most accurate value of IFT. Hence, for this purpose, first a VIT test has been performed for a hydrocarbon gas and a live oil system and using the axisymmetric drop shape analysis (ADSA), the oil droplet has been analyzed, and the geometry factor, which has been defined in this paper, was calculated. After that, the volume of oil droplet and the gas have been measured and were used for vapor-liquid-equilibrium (VLE) or flash calculation using Peng-Robinson equation of state (PR-EOS). By VLE calculation fulfillment, the final composition of two phases is determined. Eventually, the densities of two phases have been calculated for VIT modification. Finally, the IFT results were plotted versus the pressure steps, and the MMP were estimated. Furthermore, to evaluate the results of VIT test and its modification, slim tube displacement (STD) test, which is known as the most reliable laboratory method for measuring the MMP in the oil industry, has been performed. The results show that the values obtained for MMP values for the VIT test with the corrected densities which are lower than the values obtained for the VIT test for not-corrected densities and the suggested experimental-theoretical method has been estimated the MMP more accurately. The MMP obtained by VIT test and modified VIT method was equal to 3858.72 and 3722.0 psi, respectively. Meanwhile, the slim tube test has measured the MMP equal to 3667.13 psi.