Journal of Petroleum Science and Engineering最新文献

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.

With the development of nanotechnology, nanomaterials have shown good potential for enhanced oil recovery, which is of great significance for oil and gas production. Compared with nanoparticles and nanoemulsions, nanosheets have higher interfacial activity due to their two-dimensional structure, which can form a climbing film on the interface of oil-water and efficiently improve oil recovery. However, the influencing factors of the film-climbing effect and the relationship between the film-climbing effect and enhanced oil recovery are still not clear.

In this paper, small-sized water-soluble nanosheets which were molybdenum disulfide (MoS₂) nanosheets (30–50 nm) were synthesized using a one-step hydrothermal method, which have strong stability during the flooding test. And then, modifiers with different carbon chain lengths were used to modify the hydrophile-lipophile balance (HLB) of nanosheets.

Next, the influencing factors of nanosheets' climbing film were discussed, and the two-phase height index was innovatively used to characterize the strength of the nanosheets climbing film in the oil-water system. The results show that the longer the carbon chain length of the modifier, the closer the nanosheets are to neutral wet with stronger interfacial activity. In addition, molybdenum disulfide nanosheets can produce a climbing film at the oil-water interface, which is related to salinity, concentration, and diameter of test jar. In a word, the oil displacement efficiency can be characterized by the two-phase height index, and the higher the index, the higher the oil displacement efficiency. This makes us fully realize the importance of climbing film in tertiary oil recovery, and provides a new method for the effective development of oil and gas resources.

This study explores oil recovery mechanisms of static imbibition in a tight sandstone under different imbibition pressures, simultaneously optimizing imbibition agents. To this end, the static imbibition experiments of two common agents, polyacrylamide (PAM) slick water and anion–nonionic surfactants, are conducted under atmospheric and reservoir pressure (20 MPa). The interfacial tension and contact angle of these two imbibition fluids are also measured. Herein, the entire recovery period and imbibition equilibrium time vs. pressure are determined. Based on NMR and high-pressure mercury injection measurements, the contributions of pores with different sizes to the displacement recovery during imbibition are quantified. Under atmospheric pressure, the recovery rate with the surfactant was measured higher than that of the PAM slick water. The main reason was that the former has a lower interfacial tension (0.0961 mN/m), stronger hydrophilicity (average contact angle 27.7°), and stronger oil-displacing effect. Under a reservoir pressure of 20 MPa, the surfactant had lower recovery rate than the PAM slick water, while the latter enhanced the recovery further. Under atmospheric pressure, both agents recovered the crude oil in the medium-sized and larger pores whereas, under reservoir pressure (20 MPa), they mainly recovered oil from the smaller and medium-sized pores. At higher imbibition pressures, both agents recovered more oil from the smaller and medium-sized pores, and less from micropores and larger pores. This indicated that higher pressures can further improve the driving force of fluid replacement, to improve oil production from finer and medium-sized pores significantly. Under atmospheric pressure, both agents reached imbibition equilibrium in approximately 20 days while this period was reduced for the surfactant and slick water to 16 and 12 days, respectively. Based on the results PAM slick water is recommended for EOR purposes in tight sandstone which can be generalized to similar formations around the globe.

In situ combustion is one of the oldest enhanced oil recovery methods usually applied to heavy oil fields to improve recovery. In this process, air or oxygen-enriched gas is injected into a reservoir, burning some of the oil in place and generating heat and combustion gases. A considerable fraction of heavy oil resources resides in naturally fractured systems. There is no reported successful application of in situ combustion in a field with fractured systems in the literature to date. There is a limited number of studies regarding the subject in the literature. Thus, fundamental understanding of the process in fractured systems is limited.

In this study, laboratory experiments of in situ combustion in core samples with the presence of fractures were conducted. A total of 12 combustion tube experiments were conducted with 12° API heavy oil from the Bati Raman field in Turkey. These experiments differ in their configuration of fractures and oxygen concentration in the injected gas. Based on our experimental observations three distinct behaviors were observed regarding front propagation through fractured systems. The first type is strictly diffusion-limited, the second type is characterized by a thick combustion front and the last is homogenous behavior. These observations could provide a fundamental basis for possible field applications of in situ combustion in fractured systems.

To investigate the synchronous vertical propagation mechanism of multiple hydraulic fractures in shale oil formations interlayered with thin sandstone (SIS), we conduct a series of accurate, triaxial, hydraulic fracturing experiments using artificial SIS samples and analyze the effects of the formation dip angle and vertical stress difference on the penetration behavior of a single hydraulic fracture. Further, we develop a numerical model for the synchronous propagation of multiple fractures in SIS formations on a field scale using a three-dimensional lattice algorithm and investigate the controlling effects of the critical fracturing operation parameters on the penetration behavior of multiple hydraulic fractures. Increasing the formation dip angle inhibits the ability of the hydraulic fractures to penetrate the interlayer in the longitudinal direction significantly, while increasing the vertical, in-situ stress difference can improve this penetration ability. When the length of the segment to be fractured remains fixed, too many or few fractures are unfavorable to the longitudinal extension of the hydraulic fractures. When the segment to be fractured includes five perforation clusters, multiple hydraulic fractures on the outside can better penetrate the sandstone interlayer and enter the adjacent shale layers. Appropriately increasing the injection rate and viscosity of the fracturing fluid can enhance the penetration and extension ability of the outer hydraulic fractures; however, massive injections enhance the communication between the intermediate fractures and weaken the penetration and expansion ability of the outer fractures. An injection rate of the fracturing fluid equal to 12 m³/min can produce a better layer-penetration hydraulic-fracturing effect. When the method of intermittent pumping at a decreased injection rate of the fracturing fluid is used for fracturing under cyclic loading of first high and then low loads, the ability of multiple fractures to penetrate the interlayer in the longitudinal direction can improve further. The obtained results can provide a deeper understanding of the synchronous longitudinal propagation mechanism of multiple fractures in SIS formations, thereby providing more accurate guidance on optimizing layer-penetration fracturing parameters.

The sedimentary environment governs the depositional processes, ecological environments, and hydrodynamics, which affect the accumulation of organic-rich sediments. Some particular issues are unsolved about the organic matter accumulations of lacustrine shale mixed with shell bioclasts due to their alternating deposition. Freshwater bivalve remains are a familiar constituent of the Da'anzhai lacustrine calcareous shale, which indicates enhanced activities of benthic organisms. Under this background, favorable environmental conditions for the deposition and preservation of abundant organic matter may be different from classical models. Total organic carbon and elemental concentration analyses of lacustrine calcareous shale samples from the Jurassic Da'anzhai Member in the Sichuan Basin were carried out to reconstruct the paleoenvironment and reveal the organic enrichment mechanism. Results show that the samples are notably enriched in strontium, phosphorus and biogenic calcium (indicated by excess calcium concentrations) and reveal the mass death event of benthic organisms (including freshwater mussels and gastropods) in paleolakes under the control of climatic transformation. Such enrichment strongly supports the hypothesis that CaO is considered to be a paleoproductivity proxy to some extent. The paleolake was dominated by a warm and humid climate and rapid sedimentation rates and experienced intense chemical weathering, which are characteristic of freshwater input and a high flux of detrital fractions. The variations in the redox state and paleoproductivity are due to climatic shifts, hydrographic restrictions and biological behavior. Furthermore, the organic matter was enriched during both oxygenated and oxygen-deficient conditions. The combination of high sedimentation rates and high sinking influxes of particulate organic carbon reduced the chances of decomposition and thereby facilitated the efficiency of organic matter accumulation in an oxic environment. The low degree of organic matter degradation, moderate sedimentation rates and enhanced phosphorus recycling were responsible for the organic carbon accumulation and preservation in sediments for dysoxic bottom conditions.

In our previous study, as effective and eco-friendly polymer additive in the water-based drilling fluids (WBDFs), lignosulfonate-g-polyacrylamide (LS-g-PAAm) graft copolymers were successfully synthesized and characterized [J. Petroleum Science and Engineering, 171(2018) 484–494]. The aim of this study was to investigate effect of the functional groups (sources) of lignin as well as initiation condition on the chemical modification of lignin via graft copolymerization method. Kraft lignin (KL) extracted from black liquor (as a waste of paper mills) and sulfonated lignin (SL) were used as lignins with the different source and chemical structure. KL and SL were then modified by graft radical copolymerization of acrylamide initiated with thermal or redox initiator. The aliphatic hydroxyl groups were identified as the active sites in the graft copolymerization, where the number of these functional groups in the lignin chain had a significant effect on the progress of the graft copolymerization reaction. Structure of the copolymers was investigated qualitatively and quantitatively using Fourier transform infrared (FTIR) and proton nuclear magnetic resonance (¹HNMR) spectroscopies. The performance of lignin and lignin-based graft copolymers (with different grafting percentage) as an additive in the water-based drilling fluids (WBDFs) was studied. Before and after hot rolling, rheological properties including apparent viscosity, plastic viscosity, yield point as well as fluid loss were measured in the absence and presence of the salt contamination. In all fluids, except fluids containing unmodified lignin, an increase in apparent and plastic viscosities was observed. Also, thermal stability and resistance to the salt contamination were observed in fluids formulated with the graft copolymers. Best performance was observed for a fluid containing of kraft lignin graft copolymer 1 (KLGC1) where grafting percentage was as high as 452.9 wt%. Also, results showed that higher amounts of the aliphatic hydroxyl functional groups in the KL in comparison with the SL provides higher rate of the reaction progress, leading to a superior performance for use of corresponding graft copolymer as an additive in the WBDFs. The KL-based graft copolymers were able to maintain rheological and fluid loss properties during drilling operations under the hot rolling and salt contamination.

Transient cavitating flow is a dangerous condition in the operation of large drop crude oil pipelines. Accurately predicting the high pressure generated by cavity collapse is the premise of analyzing and formulating pipeline safety management and control strategies. A new numerical simulation method for one dimension cavitating flow in crude oil pipelines considering the effect of unsteady friction was proposed. The unsteady friction (UF) term is coupled to the classical discrete gas cavity model (DGCM) for modeling the cavitating flow, and the proposed model is called UF-DGCM. The method of characteristics (MOC) is used to solve the UF-DGCM. The validity of the model has been verified with experimental data. The pipeline length of the two test cases is 37.23 m and 15.22 m, respectively, and the pipeline diameter is 22.1 mm and 20.0 mm, respectively. For the two test cases, the accuracy of the prediction results is improved by 6.7% and 4.4%, respectively. A case study of cavitating flow caused by pump shutdown in a pipeline with a length of 35 km and a diameter of 738 mm was performed using UF-DGCM, and the effects of water hammer wave speed, crude oil vapor pressure, and pump shutdown time on cavitating flow were analyzed. The results show that the maximum pressure peak is dependent on the water hammer wave speed. About the increase in the wave speed value of 200 m/s will lead to an increase in the maximum pressure head value of 10.1 m. The increase of pump shutdown time will inhibit the growth of cavities, and increasing the pump shutdown time by 4 s will shorten the existence time of cavities by about 3 s. The extension of the pump shutdown time will prevent cavitating flow. The proposed improved model is more suitable for transient cavitating flow analysis, and the results of flow parameters research will be helpful to prevent cavitating flow in crude oil pipelines.

The underground formation of the water-in-oil (W/O) high internal phase emulsion (HIPE) plays an important role in the petroleum exploitation from the low permeation zone in the oil reservoir. However, most of the available emulsifier couldn't satisfy the requirement of the underground HIPE. In present study, the model asphaltene (the polyaromatic components, PACs) plus the model wax (n-C30, n-C40, n-C50 and n-C60) and the genuine asphaltene were compared to find out the effect of the emulsifier structural characteristics on the HIPE stability. The interfacial film strength test combined with the molecular dynamics (MD) simulation was carried out to reveal the contribution of the intermolecular forces, including the van der Waals (VdW) force, the hydrogen bond and the π-π stacking between the polyaromatic sheet, to the interfacial film strength. The result revealed that the intermolecular hydrogen bond and the VdW force between the aliphatic groups gave more influence on the EM than the π-π stacking. The PACs with aliphatic side chain (N, N′-Bis(2,6-diisopropylphenyl)-3,4,9,10-perylenetetracarboxylic diimide, DIP and Ditridecylperylene-3,4,9,10-tetracarboxylic diimide, DTP) combined with the wax led to the largest elastic modulus (EM) of the interfacial film up to 22–24 mN/m. The 3,4,9,10-Perylenetetracarboxylic diimide (PyN) and 3,4,9,10-the Perylenetetracarboxylic dianhydride (PyO) who had no side chain, formed the interface film via the π-π stacking and the hydrogen bond. They had lower EM from 15 to 22 mN/m, while the addition of wax had no positive effect on the EM. The all-atom MD simulation revealed that, the DTP and the DIP could fabricate a flexible network with the wax at the interface. The wax played as connector to bridge the node formed by the aggregated PACs. While the PyN and the PyO formed brick wall-like film, but the film could be broken by the wax. The dissipative particle dynamics simulation also indicated that, when the side group inhibited the π-π stacking and increased the dispersion of the asphaltene, the asphaltene could form a water-in-oil emulsion with up to 70% water content. Meanwhile, the stacking of the PACs was still necessary to supply a node for the stabilization of the interfacial film. The study made the first step to establish the relationship between the HIPE stability and the structural characteristics of the emulsifier, that provided a qualitative correlation between the stability of the emulsion and the functional group of the asphaltene, instead of the correlation between the stability of the emulsion and. It would be easier and more practical for the designing of the emulsifier for the underground HIPE.

Enhanced oil recovery (EOR) methods are generally applied in the tertiary mode to the depleted oil reservoir to increase the recovery factor through enhanced microscopic displacement and macroscopic sweep efficiency. Choosing a specific EOR method for a candidate reservoir characterized by specific rock and fluid properties is governed by standard EOR screening criteria. It is not uncommon that EOR researchers to come up with innovative ideas and/or good reservoir engineering practices to extend the applicability of those methods beyond that specified by the standard criteria. As per the standard criteria., nitrogen EOR can work at its best in deeper reservoirs where the chemical and thermal method fails. Further, nitrogen EOR is preferred for light oil characterized by low viscosity, high gravity, and the presence of lighter components so that miscibility needed for enhancing the microscopic displacement could be achieved. Regarding the sweep efficiency, thin reservoirs are preferred to avoid gravity override due to the low viscosity and density of nitrogen. Despite the abundance of nitrogen and advancements made to the nitrogen-based EOR, no significant efforts were made to analyze whether those advancements have exceeded the standard screening criteria.

This paper attempts to narrow this gap. Initially, a detailed compilation of the relevant nitrogen EOR work performed at the laboratory, pilot, and field scale is done by extracting the results from the available literature. Then the rock and fluid properties reported in each of the compiled works are compared with that of the standard criteria's stipulation to identify and classify the parameters that are exceeding and those not exceeding the standard criteria. Then a comparative analysis is done using the reported recovery factor to provide a statement for each compilation whether those exceeding parameters have indeed improved the nitrogen EOR performance. Based on the conducted study, properties such as oil viscosity, oil gravity, thickness, and oil composition, could be exceeded only when the depth is conducive to generating high pressure. The inert nature of nitrogen makes high pressure an important requirement for inducing miscibility and therefore, the reservoir depth of more than 6000 ft, stipulated in the standard criteria remains a must for an efficient nitrogen EOR process that targets microscopic displacement efficiency. Overall, depth and therefore the pressure requirement is a major influencing factor for nitrogen EOR to operate in its best miscible mode. Most of the recent studies were conducted at high pressures in order to induce miscible flooding pressure for increasing the oil recovery.