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Background. Pregnancy in systemic lupus erythematosus (SLE) patients is a challenge due to the potential maternal and fetal complications. Therefore, a multidisciplinary assessment of disease risk before and during pregnancy is essential to improve pregnancy outcomes. Objectives. Our purpose was to (i) define clusters of patients with similar history and laboratory features and determine the associative maternal and perinatal outcomes and (ii) evaluate the risk spectrum of maternal and perinatal outcomes of pregnancy in SLE patients, represented by our established risk-assessment chart. Methods. Medical records of 119 patients in China were analyzed retrospectively. Significant variables with p < 0.05 were selected. The self-organizing map was used for clustering the data based on historical background and laboratory features. Results. Clustering was conducted using 21 maternal and perinatal features. Five clusters were recognized, and their prominent maternal manifestations were as follows: cluster 1 (including 27.73% of all patients): preeclampsia and lupus nephritis; cluster 2 (22.69%): oligohydramnios, uterus scar, and femoral head necrosis; cluster 3 (13.45%): upper respiratory tract infection; cluster 4 (15.97%): premature membrane rupture; and cluster 5 (20.17%): no problem. Conclusion. Pregnancy outcomes in SLE women fell into three categories, namely high risk, moderate risk, and low risk. Present manifestations, besides the medical records, are a potential assessment means for better management of pregnant SLE patients.

The drilling and research communities are leading the way toward more digitally-controlled operations to ensure that the drilling process takes place as safely and gently as possible with the lowest possible carbon footprint. Today’s cutting-edge operations are run on large high-performance drilling installations where operations are largely run remotely from the driller’s operating station. Digitalization of the drilling process is the goal for performing drilling operations remotely from onshore. Leak-off test (LOT) or extended leak-off test (XLOT) plays a critical role in the petroleum industry. Therefore, recognizing all affecting parameters on LOT/XLOT and Formation integrity test (FIT) performance is vital. Because, in some cases, it is not possible to fully understand what happened during the test, having a deep insight into the LOT procedure is very important. One of the current study's main objectives is to thoroughly explain all stages of these tests and assemble all the significant parameters. Thus, many scientific papers on these tests were deeply reviewed and were classified into four main groups focusing on the application of LOT/XLOT (i) in stress estimation and geomechanical studies, (ii) concerning hydraulic fracturing, (iii) concerning wellbore stability, and (iv) numerical modeling, and then, the corresponding discussions were conducted. It was found that in-situ stress estimation is the most common application of the leak-off test. Moreover, considering the importance of LOT and the desire to digitize operations in the oil and gas industry, it was found that the automatic LOT/XLOT is a fully required approach. The primary purpose of this study, which is hence considered its main contribution, is to prepare a LOT flowchart that would set off the further code development tasks of the field. The fundamental code of the present study was written and checked using a real dataset in a Python environment. The results were satisfying and indicated a successful start, which lays a foundation for future automated LOT/XLOT tests.

Despite holding a significant proportion of the known hydrocarbon reserves by the carbonates, enough studies have not been conducted to understand their geomechanical parameters and their predictab...

In continuous formations, the rock properties and the state of in situ stresses control the propagation direction of an induced hydraulic fracture (HF) and its geometry. The present study succinctly reviews more than a hundred scientific papers that have deeply explored hydraulic fracture propagation from the rock mechanical perspective and summarizes the current state of knowledge on the propagation of hydraulic fractures. These studies fall into three major categories of field, experimental, and numerical studies. It was found that numerical simulations are the most common methods for studying hydraulic fracture propagation, while field and analytical studies are the least-used methods because of their technical complications and practical limitations. One of the most efficient methods for the numerical simulation that has been adopted by numerous researches from around the world in recent years is the Lattice simulation approach. This method is a particle-based model and uses the Distinct Element Method. Since the Lattice simulation presents higher accuracy and computational efficiency over the existing methods to simulate complex reservoir conditions, the current review particularly focuses on this method and also discusses the functionality of the recently introduced XSite simulation package. The results from this work demonstrate the superior ability of the Lattice simulation and XSite package in modeling different propagation regimes, geometry, and growth of the HF. Moreover, the authors simulated the interaction mode of hydraulic and natural fractures based on two significant parameters of the phenomenon, namely “angle of approach” and “in situ differential stress”, and verified the results with the Blanton criteria.

Complete and thorough core cleaning is a critical prerequisite for the precise measurements of most rock's petrophysical parameters. In shale, the oil cleaning process, aimed to remove the volatile hydrocarbons, is often complicated by the requirement for intact solid organic. Evaluation of shale's cleaning methods needs to take structural integrity of organic matrix into account but neglected in the existing researches. Here, we develop a novel evaluation method using a modified ESH (extended slow heating) pyrolysis cycle, which starts at a lower initial temperature of 150°C for 10 minutes and then slowly increases to 650°C by 10°C/min. Hydrocarbons on the ESH pyrogram were divided into light free hydrocarbon (SA), FHR (fluid-like hydrocarbon, SB), and solid organic matter (SC). We propose a set of quantitative evaluation criterions comparing the results of pyrograms, for different types of the hydrocarbons, at different cleaning conditions. We showed that a modified pyrogram achieves complete cleaning with SA and SB removed while SC remains almost intact. The modified pyrogram achieves complete removal of FHR in the second stage of pyrogram, while earlier researches often report residual FHR. The introduced method improves the accuracy in the identification of production potential in kerogen-rich shale reservoirs up to about 3% of the total pore volume. Further, the new approach allows a quantitative assessment for the cleaning quality without altering the sample's organic matrix. Future studies on the petrophysical properties of the hydrocarbon-bearing reservoir rocks may benefit from the thorough hydrocarbon removal achieved through the modified pyrogram methods proposed in this study.

Analyzing the petrophysical properties of gas hydrate reservoirs under different conditions by experimental methods is time-consuming, costly, and very difficult. Therefore, it is of great ...

Studying the failure mechanism of methane hydrate specimens (MHSs) is of great significance to the exploitation of methane hydrate. Most previous studies have focused on the macro or micromechanical response of MHS under different conditions. However, there are a few studies that have investigated the mechanical response mechanism of MHS based on energy evolution. Therefore, in this study, a numerical model of the methane hydrate-bearing sediments was constructed in the particle flow code (PFC) environment. Then, the numerical model was validated using the conducted laboratory tests; and a series of numerical tests were conducted under different methane hydrate saturation conditions, and the obtained results were analyzed. These results qualitatively describe the main mechanical properties of the methane hydrate-bearing sediments from the viewpoint of energy evolution. The simulation results indicated that during the shear test, the bond breaks at first. Then, the soil particles (sediments) start to roll and rarely slid before shear strength arrives at the highest value. Around the highest shear strength value, more soil particles begin to roll until they occlude with each other. Strain softening is induced by the combined action of the breakage of the hydrate bond and the slipping of soil particles. The higher the hydrate saturation is, the more obvious the strain softening is. Considering that a good agreement was observed between the numerical simulation results and the laboratory test results, it can be concluded that the numerical simulation approach can complement the existing experimental techniques, and also can further clarify the deformation and failure mechanism of various methane hydrate-bearing sediments. The results obtained from the present study will contribute to a better understanding of the mechanical behavior of the gas hydrate-bearing sediments during hydrate dissociation and gas exploitation.

Understanding different types of pores and their wettability conditions in tight oil reservoirs is a crucial step in evaluating oil accumulation and migration process of these energy resources. Nuclear magnetic resonance (NMR) technique has been widely used in conventional reservoirs to study rock properties including porosity, permeability, pore structures, and wettability. However, the existence of high contents of organic matter and complicated NMR relaxation mechanisms pose considerable challenges on interpreting the NMR results of tight oil reservoirs. In this study, we performed NMR measurements on rock samples under different fluid saturation states and combined the results with imbibition methods as the novel experimental procedure to characterize wettability and pores of tight oil reservoirs. 1D and 2D NMR experiments were first conducted on core samples at four different fluid saturation states including water-saturated state, after-centrifuge state, 80 °C oven-dried state, and 140 °C oven-dried state. Then, we investigated the unmovable hydrogen-bearing matters by monitoring the loss of NMR signal in the four saturation states. In the next step, pores having different wettability conditions were investigated based on the NMR results of oil imbibition and water imbibition experiments. The results showed that while the transverse relaxation behavior of the tight oil rock samples were different from each other, hydrocarbon-wet pores, mix-wet pores and water-wet pores coexisted in these samples. NMR relaxation of oil in hydrocarbon-wet organic pores happened to be the fastest relaxation mechanism compared to other types of pores, and the peak transverse relaxation time was about 0.13 ms. In addition, our experimental results revealed the existence of intermolecular homonuclear dipolar coupling between organic matters and fluids.

This study incorporates X-ray computed tomography (CT) technology into the in-situ observation of the xenon hydrate formation process in sand sediments under excess gas conditions. While the scanning images were used to obtain microscopic distribution information of the hydrate, we implemented the finite element method (FEM) to calculate the resistivity of the hydrate-bearing samples obtained from scanning images. Consequently, it was observed that the resistivity index (RI) versus hydrate saturation (Sh) data matched better with our new calculation model rather than the simple Archie formula fitting model (i.e. experimental fitting model). Besides, we calculated the resistivity versus the hydrate saturation curves based on digital rock models with idealized hydrate distributions. These distributions included adhesive type, cemented type and scattered type. Observation of microscopic distribution and simulation results indicated that the resistivity versus hydrate saturation exhibited certain differences for the three types of hydrate distributions. We also found that saturation exponent (n) is a function of the hydrate saturation (Sh), which can be applied in the proposed new calculation model in order to calculate the resistivity versus hydrate saturation data. This suggests that the established model is a useful methodology for the purpose of saturation calculations and reservoir identification in hydrate-bearing sediments.

Our main scheme in this study was distinguishing between fracture porosity and matrix porosity in coalbed methane reservoirs through a novel approach which is the joint usage of NMR transverse relaxation (T2) measurements and rock physics modeling based on Levenberg-Marquardt (LM) algorithm. For this purpose, NMR T2 relaxation curves of 34 water-saturated coal samples, prepared and processed in the laboratory, were measured and the pore size distribution inside them was investigated. Subsequently, matrix and fracture porosity were separated based on the threshold T2 relaxation time (90–110 ms) which was achieved through our particularly designed fracturing experiments (this is different from the common T2 cutoff). The T2 measurements were performed in the laboratory using our NMR machine. After that, a rock physics scheme based on Levenberg-Marquardt algorithm was applied to independently estimate matrix porosity and fracture porosity from the samples' statistic mechanical properties including compressional wave velocity (Vp), shear wave velocity (Vs), bulk modulus (K), shear modulus (G), Young's modulus (E), and Poisson's ratio (ν) which were all carefully measured in the laboratory. Afterward, both types of the abovementioned porosities were comprehensively characterized and the obtained achievements were listed. Once finished with this step, the 3D structure of the entire reservoir was extracted using the recorded data inside 32 drilled wells, and then the established models were upscaled and the unique and independent contour maps of fracture porosity and matrix pore porosity were drawn over the entire reservoir area. The proposed novel approach provides the kind of information about fractures of the media which is not obtainable with either of NMR or rock physics methods when they are used individually. This study established a novel discussion investigating application of rock physics relationships in order to determine fracture porosity of the coal reservoirs. The approach was used to successfully investigate and characterize pore-only porosity and fracture-only porosity of a coalbed methane reservoir. According to the obtained results, joint usage of rock physics modeling and LM algorithm would be considered as a reliable technique in quick or deeper exploration of unconventional coal reservoirs.

The presence of clays in hydrocarbon reservoirs challenges the producible amount of oil and gas significantly. Therefore, this study reports a detailed quantitative characterization of clays' specific properties from two fundamental aspects which include clays' type and amount, and their impact on reservoir's fluid flow. We used Scanning Electron Microscopy (SEM) images and respectively adopted deep learning for typing and quantifying clays, and the Lattice-Boltzmann Method (LBM) for flow simulations with and without the presence of clays. The trained deep learning model of the present study was translated into a MATLAB application that is a convenient tool for clay characterization by the future user. This model was trained using 2160 images of different clay minerals based on transfer learning using AlexNet and resulted in more than 95.4% accuracy while applied on the unforeseen images. Moreover, we established the technique of depth-slicing of 2D SEM images, which provides the possibility of 3D processing of the routine SEM images. The results from this technique proved that clays could reduce reservoir porosity and permeability by more than 30% and 400 mD, respectively. The introduced approach of the present study provides new insights into the detailed impacts of clay minerals on the reservoir's quality.

X-ray CT scanning is one of the main methods to study the pore structure of the rocks. However, low resolution is currently one of the major challenges of this method, which does not allow for the identification of microscopic pores. Even though adopting images of higher resolutions could reflect the microscopic pores of the rocks, due to the small size of the scanned rock sample in the x-ray CT scanning method, the rock parameters cannot be effectively obtained, especially for the rocks with strong heterogeneity. This would cause the loss of important pore information, such as fractures' information. Focusing on this problem, the current research tries to propose a method for constructing high-precision digital rocks of complexly porous rocks. This method is based on the simultaneous application of x-ray CT scanning images, nuclear magnetic resonance measurements, as well as mercury injection experimental data and fractal discrete fracture network. These methods effectively compensate for the shortcomings of the scanning method where it cannot capture pores smaller than the scanning resolution and for the lack of fracture information due to rock sampling. The research results showed that compared with the digital rock models constructed by single-resolution scanning, the high-precision complex pore digital rock constructed by this method can effectively improve the accuracy of the results of porosity and permeability calculations. These results were closer to the results of rock physics experiments. This approach provides a solid foundation for the numerical simulation of rock parameters in unconventional reservoirs with complex pore structures, such as carbonate, tight sandstone and shale reservoirs.

Rocks in low porosity reservoirs contain a considerable number of micro-pores which make the accurate measurement of total porosity more and more difficult. Nuclear magnetic resonance (NMR) is wildly used in petrophysical analyses; however, when using traditional NMR porosity measurement method, it is hard to detect signals of micro-pores due to the limitation of echo spacing. In the current research study, we used a robust NMR method, i.e. magic-sandwich echo (MSE) pulse sequence, to measure the porosities of various types of hydrocarbon-bearing rocks, and compared the results with those of the conventional measurement methods. It is worth mentioning that clay minerals have a great influence on NMR porosity measurement results. Therefore, it was needed to measure the magnetic resonance signal of dry rock to reduce the influences of clay minerals on the rock porosity measurement by NMR approach. After conducting experiments on different low porosity rocks, the results showed that the relative error of our method was 13.50%, which was more accurate than traditional NMR porosity measurement method. In addition, based on porosity deviations of shales and homonuclear dipolar coupling, we put forward a novel method to estimate shale total organic carbon (TOC) content which is a helpful tool for evaluation of unconventional shale reservoirs.

Deeply buried fractured reservoirs have evolved into significant oil and gas potential in many basins of the world. However, fracture prediction in deeply buried carbonate reservoirs has always been challenging. Fracture prediction in the deep-buried carbonate structure of North China is problematic because of multiphase tectonic movements, variable sediment lithology, and complex diagenesis. Because of deep burial depth and complex heterogeneity, the resolution of seismic reflection data beneath the buried-structure is poor, making it challenging to identify the fault reflection characteristics. This paper proposes a novel idea to identify natural fractures in carbonate reservoirs using conventional logs with seismic reflection data. The proposed model can also predict the fracture aperture and fracture density, a distinctive feature. Another novel hybrid model based on deep-learning neural network (DNN) and cluster analysis is proposed to predict further the spatial variations of lithology, porosity, and fracture parameters from seismic inversion. The proposed models provide valuable insights that help determine fracture parameters in the Paleozoic strata and associated reservoirs through quantitative analysis using petrophysics, rock physics, seismic inversion, and seismic attributes. The overlapping of seismic interpreted fault networks and spatial variations of the inverted fracture parameters indicate a high correlation of fracture development zones. The methodology proposed in this study presents a valuable template valid for the characterization of fractured reservoirs in deeply-buried carbonate reservoirs throughout the world.

Gas relative permeability characterization is of key significance to model the behavior of gas flow in gas hydrate-bearing sediments. The present study proposes a novel model to relate gas relative permeability to gas hydrate saturation based on X-ray micro-CT imaging information of xenon hydrate pore-scale distribution in sand sediments. Lattice Boltzmann method (LBM) was used to obtain permeability values of xenon hydrate-bearing sediments via micro-CT data. The results showed that gas relative permeability (Kr) versus gas hydrate saturation (Sh) data are consistent with the new model and the imitative effect is relatively better than that of the simple Corey model. Besides, we calculated gas relative permeability versus gas hydrate saturation curves for various pore habits via idealized models. Experimental measurements and simulation results showed that the grain-coating gas hydrate exhibits the highest gas relative permeability, while pore-filling gas hydrate exhibits the lowest values of gas relative permeability, and the cementing gas hydrate ranges in between. We validated the new gas relative permeability calculation model by applying it to the well logging data of gas hydrate reservoirs. Our results showed that the novel model is beneficial for permeability characterization of gas hydrate reservoirs and gas relative permeability calculations.

Pore fluids are generally classified into movable fluid and irreducible fluid by one or two NMR T2 cut-offs (T2C). Fluid movability in tight sands may not be accurately characterized by pore size-based classification methods solely because of the complex pore structure and heterogeneity in pore size. In this study, we propose a nine-grid model to characterize fluid movability and calculate the percentages of free fluid (FF), capillary-bound fluid (CAF), and clay-bound fluid (CBF). The pore size distributions and capillarity boundaries are converted from T2 and mercury injection capillary pressure (MICP). Three T2 spectra (TFF, TCAF, and TCBF) under water saturation, centrifugation, and heat-treatments are measured to classify pore fluids as FF, CAF, and CBF according to the pore capillary force needed to displace them. T2C1 and T2C2 are calculated to classify pores into three size categories. Finally, the nine-grid model that is composed of the three T2 distributions and two T2C is applied to explain results of a N2 displacement test and evaluate fluid movability in two samples. The results suggest that the conventional classification method based on fixed T2C results in the underestimation of CAF and overestimation of CBF. The macro-pores (T2 > T2C1) range in size larger than 85.20 nm and 113.64 nm and have pore capillary pressures lower than 6.46 MPa and 8.62 MPa. Micro-pores (T2

After long-term production by water injection, the conductivity features of oil reservoirs are changed, leading to difficulties in calculating remaining oil saturation by traditional well-logging techniques. There are some specific phenomena relating to petrophysical properties in water-flooded layers, and a deep investigation of them could help us understand resistivity changes of rocks during the water-injection process. We compared traditional mixed-fluid resistivity methods and determined their drawbacks. In addition, we revised the theoretical models and came up with a novel method to calculate mixed-fluid resistivity. The displacement process was divided into three stages: non-water-flooded stage, low and medium water-flooded stage, and high water-flooded stage. To study the relationships between rock resistivities and water saturations when injecting fresh-/saltwater, we used digital rock numerical methods. We first constructed 3D digital rock models based on the process-based method, and then we obtained oil and water distributions in the pore space by the pore morphology method. When resistivities of every component in digital rock models were assigned, rock resistivities could be calculated in different water saturations by the finite-element method. We found that in the case of freshwater injection, the relationship between water saturations and rock resistivities formed an S-shaped curve, but in the case of saltwater injection, if the injection water salinity was higher, the rock resistivity would be decreased by increasing the water saturation. In different rock heterogeneity and wettability conditions, these curves showed similar shapes and trends. Combined with resistivity logging data, this novel approach was used in the interpretation of a real oil well. Compared with the existing models in the interpretation practices, this new model better matched the real-field saturations and improved the accuracy of saturation interpretation in the studied water-flooded oil reservoir.

Regulators often use environmental policy to induce green initiatives by firms. This paper examines the emission-reduction-inducement effect of the environmental tax deduction (ETD) incentive by Stackelberg game models between an environmental regulator and a profit-maximizing monopolistic firm facing emission-dependent demand. Different cases, i.e., with/without considering the regulator&rsquo, s environmental concerns, were used to investigate the ETD policy effects with a numerical example. This paper shows that the regulator&rsquo, s tax policy will only affect the emission reduction level, but cannot influence the output, which combined with the firm&rsquo, s operation factors mainly depends the consumers&rsquo, attitude toward green products and price sensitivity. Numerical simulation results showed that for the cases with a moderate level of environmental concern and emission standard, the regulator can set an ETD incentive to motivate the choice of a higher level of emission reduction and simultaneously increase social welfare, otherwise, the increase in environmental quality is at the expense of social welfare. When the market&rsquo, s environmental consciousness increases, it is easier for the regulator to guide the firm to adopt an ETD solution. Therefore, improving consumers&rsquo, awareness of environmental protection is an effective way to promote green investment of firms.

The current research presents a semi-analytical solution for the anti-plane dynamic response of a shallow-buried lined tunnel. The tunnel with an imperfect interface between the tunnel lining and its surrounding medium is embedded in an anisotropic and elastic half-space medium. For anti-plane problems, three elastic constants can describe the characteristics of medium anisotropy according to the generalized Hooke’s Law. Therefore, the complex variable function method and multi-polar coordinate system were applied to express the wave fields with three unknown constants in this study. These constants also automatically satisfy the zero-stress boundary condition on the horizontal ground surface in the half-space and the Sommerfeld radiation condition at infinity. The imperfect interface is represented by a series of elastic spring model. Meanwhile, parametric sensitivity analyses indicate that both the medium anisotropy and the imperfect interface stiffness affect significantly the dynamic response of the medium-lining system including stress and ground surface displacement. Besides, the influence of both factors is also dependent on incidence direction and frequency.

Gas hydrate, as an alternate hydrocarbon source, has attracted significant attention in past decades. A precise estimation of permeability of the gas hydrate-bearing formation is essential for predicting the flow behaviors and the associated gas production performance. In this research, the influence of gas hydrate saturation on pore structural properties and then affect permeability was investigated using a three-dimensional micro X-ray computed tomography dataset that records an experiment of xenon hydrate formation in a sand pack at selected times during the experiment. Unlike the previous work, the goal of this work is to characterize pore space evolution, during gas hydrate formation, using a set of key microscopic pore characteristics, i.e. pore and throat radii, pore throat ratio, coordination number and tortuosity, by applying pore network analysis, on larger and therefore more representative sub-volumes. The same segmented volume of that dataset was used in this work to estimate gas hydrate saturation and permeability, recalculated by the lattice Boltzmann method, on those larger sub-volumes at selected snapshots. Besides, the analysis provides further insights into the links of gas hydrate localities and local pore characteristics and therefore their controls on the permeability. New evidence of semi-quantitative nature emerges that grain-coating gas hydrate formed at low gas hydrate saturations play a crucial role on reducing permeability, while pore-filling and/or cementing gas hydrate become dominating at high gas hydrate saturations, and these can be explained by gas hydrate formation mechanisms.

This review focuses on the recent applications of nuclear magnetic resonance (NMR) technology for characterizing fractures. The paper aims to help researchers in extending the existing reservoir characterization methods (which are commonly used in conventional hydrocarbon reservoirs) for appropriate usage in unconventional resources. This is because some techniques for quantifying and qualifying fractures have been investigated in conventional sandstone and carbonate reservoirs, but the reality for unconventional resources is that such techniques are still poorly developed. Fractures are necessary for economical production of petroleum from many low-permeability reservoirs. The characterization of fractures by well logging technology is of great interest in the petroleum industry. The main purpose of this study is to review the characterization techniques that are developed either for identifying fractures or distinguishing fracture porosity from matrix porosity. This concept plays a leading role in providing availability of an optimized well completion program. The results of this study indicated that in terms of both sandstone and carbonate tight reservoirs, there have not been many steps taken toward the aforementioned goal up to now. Nevertheless, these steps are valuable enough to be counted on and could serve a meaningful function in treating hydrocarbon reservoirs. Because of the ongoing changes in today's petroleum industry, development of a comprehensive methodology will create greater economic benefits in unconventional reservoirs than in the conventional ones.

Fractured gas-bearing carbonates are dual porosity media characterized by their complex pore structure and heterogeneity. In reservoir evaluation, the pore fluids could accurately be characterized by nuclear magnetic resonance (NMR) well logging. However, the NMR-based permeability models of fractured carbonates are limited due to lack of understanding of how fractures affect NMR T2 spectrum. Based on the inevitable influence of fractures on reservoir permeability conditions, the current research investigates the effects of different fracture parameters on the resultant T2 spectrums and permeability values of the fractured gas-bearing carbonates. Firstly, a carbonate core sample having no fractures was scanned by CT imaging and its digital model was reconstructed by digital core algorithms. Secondly, fracture having various parameters dip angle, length, aperture and density were inserted into that digital core model to represent different fractured carbonate rock. In the next step, random walk simulation and lattice Boltzmann method were respectively used to simulate corresponding T2 spectrums and permeabilities of these models. We introduced a new kind of spectrum called ‘T2 spectrum of fractures’ or ‘T2f spectrum’ and used it to study effects of different fracture parameters on the NMR T2 spectrum. Finally, based on the quantitative analysis, a novel permeability model was presented for the fractured carbonates. Combined with nuclear magnetic resonance well logging data, this novel approach was used in the interpretation process of well logs. Compared to the existing models of permeability, this new model better matched the real-field permeabilities and greatly improved the accuracy of permeability interpretation in the studied fractured carbonate gas reservoir.

CO2 HnP, despite its promised potential and societal support for potential carbon negativity, suffered from the elevated cost; its application is limited in scale at the time of this writing. Practitioners had explored a mixture of CO2 with N2 as the treatment gas to reduce the cost and improve recovery. Nevertheless, these efforts are currently thwarted by a lack of understanding of the fluids displacement mechanism on the pore-scale that can only be addressed through laboratory experiments. In this study, we investigate why sequential N2-CO2 HnP recovers more oil than pure CO2 HnP. We found that N2 and CO2 perform similarly in the displacement of free fluids (FF), but N2 displaces little capillary bound fluids (CAF). However, replacing N2 with CO2 after a few N2 HnP cycles results in significant improvement in the recovery of CAF in the medium-sized pores than the HnP using CO2 exclusively. The injected N2 displaces pore fluids directly by squeezing their volumes but can only work on highly mobile FF. The displacement of fluids by CO2 relies more on creating a fluids/CO2 mixture and the subsequent swelling effect that can also displace CAF. Nevertheless, the N2 does not just ‘push’ the fluids out but also enhanced the rock’s hydraulic conductivity by possibly enlarging the pores and thus resulted in higher CAF recovery in the later cycles of HnP using CO2. More optimized N2-CO2 HnP procedures may further boost the recovery of fluids in the medium-sized pores, where a significant amount of hydrocarbon would remain unrecovered.

Gas hydrates are one of the most abundant clean energy resources and can effectively solve the energy crisis with a lower carbon footprint. Gas hydrates typically exhibit complex microscopic filling modes, including adhesive mode, cemented mode and scattered mode. Furthermore, the scientific understanding of such filling modes and the associated petrophysical parameters is essential for successful exploitation and development of hydrate formations. However, a precise identification of such filling modes remains a big challenge. Thus, here we proposed a novel hybrid gas hydrate filling mode identification method via digital rock technique. The hybrid method uses a combination of multiple methodologies. Firstly, the dry core samples were scanned by the high-resolution micro-scale 3D X-ray computed tomography (μCT) and the digital rock models were built. Then the resistivity was simulated as a function of gas hydrate saturation with three idealized gas hydrate-filling modes. The differences between the resistivity of three idealized gas hydrate-filling modes were analyzed, and based on the correlations obtained, the idealized gas hydrate saturation calculation models were formulated. We then considered well log data from a real hydrate reservoir in order to evaluate the application of proposed hydrate saturation model and identify the filling mode. Essentially, the gas hydrate saturation results from digital rock models and field well logging data are compared, and the filling modes in the research reservoir were successfully identified.

Capillary pressure curves are important data for reservoir rock typing, analyzing pore throat distribution, determining height above free water level, and reservoir simulation. Laboratory experiments provide accurate data, however they are expensive, time-consuming and discontinuous through the reservoir intervals. The current study focuses on synthesizing artificial capillary pressure (Pc) curves from seismic attributes with the use of artificial intelligent systems including Artificial Neural Networks (ANNs), Fuzzy logic (FL) and Adaptive Neuro-Fuzzy Inference Systems (ANFISs). The synthetic capillary pressure curves were achieved by estimating pressure values at six mercury saturation points. These points correspond to mercury filled pore volumes of core samples (Hg-saturation) at 5%, 20%, 35%, 65%, 80%, and 90% saturations. To predict the synthetic Pc curve at each saturation point, various FL, ANFIS and ANN models were constructed. The varying neural network models differ in their training algorithm. Based on the performance function, the most accurately functioning models were selected as the final solvers to do the prediction process at each of the above-mentioned mercury saturation points. The constructed models were then tested at six depth points of the studied well which were already unforeseen by the models. The results show that the Fuzzy logic and neuro-fuzzy models were not capable of making reliable estimations, while the predictions from the ANN models were satisfyingly trustworthy. The obtained results showed a good agreement between the laboratory derived and synthetic capillary pressure curves. Finally, a 3D seismic cube was captured for which the required attributes were extracted and the capillary pressure cube was estimated by using the developed models. In the next step, the synthesized Pc cube was compared with the seismic cube and an acceptable correspondence was observed.

Summary Nuclear magnetic resonance (NMR) is one of the most reliable techniques in obtaining permeability and porosity information of hydrocarbon reservoirs in today’s oil and gas industry. However, this technology is considerably expensive and its associated costs are the major limitations of its usage. Moreover, it is not possible to run NMR log in producing cased wells. Accordingly, the current research tries to suggest a novel alternative technique for the wide scale field measurements of the NMR log and tries to provide a more cost-effective and time-effective approach. Our introduced novel technique which is based on mathematical algorithms proved to act successfully in accomplishing desired purposes.