Journal of Petroleum Science and Engineering最新文献

There are a lot of exploration examples of far-source reservoirs, but the description of the connotation and accumulation mechanism is very rare. The Dongsha Uplift is one of the major oil-producing areas in the eastern Pearl River Mouth Basin in the northern South China Sea. The uplift lacks generally hydrocarbon source rock and is far from the generative kitchen, making it a typical far-source oil and gas reservoir. The accumulation mechanism of crude oil in the reservoirs are still unknown. By systematically comparing biomarkers, nitrogenous compounds and isotopic characteristics of the crude oil and source rocks with those in the neighboring depressions, and combining with fracture, sand body, unconformity migration conduits and barrier conditions, this paper simulates oil and gas migration paths and formation time with Pathway and IES software, and analyzes oil and gas accumulation process from a dynamic perspective. We found that the deep lacustrine hydrocarbon source rocks of the Wenchang Formation in the H26 Sag of the Huizhou Depression reached peak oil production at the end of the Hanjiang Formation deposition. Influenced by the strong tectonic activities at the final deposition of the Hanjiang and Yuehai formations, two episodes of hydrocarbon charging occurred at the top of the Dongsha Uplift. The accumulation of hydrocarbons far from the source rocks in the Dongsha uplift is mainly controlled by the efficient carrier system at hydrocarbon generation period. The oil is mainly accumulated in L4-1 and L11-1 oil fields through the long-distance stepped migration mode. The spatial and temporal relationship between hydrocarbon generation of source rock and episode of fault activity are mainly responsible for accumulation in the far-source reservoirs of the Dongsha Uplift.

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.

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.

To achieve high-speed and undisturbed core drilling, the standing wave vibration of the drill string in a sonic drill is excited by a high-frequency inertial vibrator; the resulting high alternating stress cycle in the drill string can easily cause fatigue damage. In order to minimize the fatigue failure of drill-string at the stage of its design, it is necessary to assess the fatigue damage caused by alternating stress to guide engineering practice. In this paper, based on one-dimensional wave theory, we analyse the standing wave vibration in a drill-string excited by a sonic vibrator, and theoretically prove that the dynamic resonant stress of a drill-string is the key factor influencing the fatigue damage. By using the Palmgren–Miner fatigue damage rule, we establish a theoretical formula for the cumulative fatigue damage of a variable-length standing wave vibration drill string and reveal the fatigue damage mechanism of the variable-length resonant drill string. Furthermore, the effects of sonic drill systems and process parameters on the damage are quantified. It was found that by an appropriate choice of a drill-pipe length, the fatigue damage can be reduced whilst the axial stress concentration factor (aSCF) $k_{\sigma }$ on threaded connections can significantly increase it. At the fundamental frequency of the resonant sonic drilling, the maximum fatigue damage point, $x_f$, is located approximately $l_a/2$ above the drill bit, not exceeding the theoretical sonic standing wave starting length, $l_a$, and unrelated to the hole depth. This study promotes the theoretical understanding and exploration of variable-length standing wave oscillators.

Dynamic appraisal in carbonates with excess permeability is critical to successful reservoir modeling and depletion planning. Accurate recognition and characterization of a dual-porosity system may translate to improved project performance. We present a catalog of diagnostic signatures that elevate pressure transient analysis beyond the traditional V shape, to aid in identifying non-matrix features’ presence, extent, and contribution to reservoir performance. We reviewed 152 well tests from the Brazil Pre-Salt, integrated with multi-scale static and dynamic data (conventional core, borehole image logs, seismic, and drilling losses). A recurring set of eight signatures with characteristic slopes and shapes stood out, which we reconciled with geologic concepts and tested with numerical modeling. These signatures reveal key insights into excess-permeability architecture and non-matrix types, from touching vugs to caves, from natural fractures to fault damage zones. They will assist subsurface teams to optimally frame well test objectives and maximize value of information during early appraisal and field development. They will help enhance reservoir performance prediction, by enabling a comprehensive use of well test data in geologic and reservoir simulation models.

With the advantages of high separation efficiency and less footprint, the inline gas-liquid cyclone separator has gained wide attention in the fields of petroleum, chemical industry, nuclear energy and aerospace. However, single-stage gas-liquid cyclone separator usually cannot accommodate a large range of inlet gas volume fractions. For gas-liquid cyclone separator operating in series with the same structure, it is difficult to operate the second stage efficiently. Therefore, a new two-stage inline gas-liquid cyclone separator is designed in this study considering the bubble size and the variation of inlet gas volume fraction. It integrates the advantages of horizontal and vertical inline gas-liquid cyclone separator, so as to meet the separation requirement for both gas and liquid. The tangential velocity, gas volume fraction and pressure distribution inside the separator are studied by numerical simulation using Computational Fluid Dynamics. The experimental results show that the optimal standardized flow split is about 1.0. When the inlet gas volume fraction varies from 10% to 90%, the degassing efficiency gradually increased with a maximum value of 8.88%. Meanwhile, the dehydration efficiency gradually decreases, with a maximum value of 4.24%. In addition, the maximum pressure drop of the two-stage inline gas-liquid cyclone separator is only 140 kPa during the process of experimental test. This research can provide efficient solution to the working condition with wide range of inlet gas volume fraction and to meet the requirement of high compactness as well.

Interwell Stratigraphic Correlations Detection (ISCD) guides reservoir modeling and oil development. Many existing AI (artificial intelligence) methods have been proposed for ISCD. However, it is difficult to generate labels for large-scale geological data, which leads to the problem of small samples. In this paper, we propose a few-shot learning-based approach to detect stratigraphic correlations for overcoming this challenge. Specifically, we design a Knowledge Enhanced Few-shot Transformer ISCD model (KEFT-ISCD) to enhance reservoir sample features. We design a dynamically balanced marginal softmax ($dbm\text{-}softmax$) to further optimize the model loss for identifying edge features, which improves the stratigraphic matching effects. In addition, we design a bi-window co-sliding approach to address the cross-matching problem in practical stratigraphic matching. To the best of our knowledge, this is the first work to use few-shot learning for the ISCD. We evaluate the proposed method with different well sections in a pair of adjacent wells from a real-world well logging dataset. Experimental results indicate that the proposed KEFT-ISCD performs well and achieves a detection accuracy of 91.12%. We also conduct experiments on different wells and blocks. The results further demonstrate the generalizability of the proposed approach.

Water-based working fluids are widely applied in the development of tight gas formations. However, these fluids’ flowback rate is generally low than 50%, resulting in a large amount of water retention to dramatically decline the gas delivery. Typical tight sandstone core samples are selected in this study to perform the gas-driven water displacement experiment to investigate the underlying mechanisms for the low water flowback behaviors in tight gas reservoirs. Results show that the average water flowback rate for 15 tight sandstone samples by gas-driven water displacement is obtained to be only 31.31%, which in turn causes an average gas permeability damage rate of 58.94%. Analysis suggests that multiscale pore structures, ultra-low connate water saturation phenomenon, filling of hydrophilic clay minerals, and insufficient pressure drop contribute to the congenitally unfavorable geological factors of low water flowback capacity. On the other hand, irreversible formation damages like water phase trapping, salting out issues, and residual water film effect caused by water retention are the main elements that restrict water removal during a gas-flow drying process. The findings of this study provide useful insights into the control mechanisms of low water flowback behaviors and the formation damages induced by water invasion in tight sandstone gas reservoirs.

Natural gas hydrate-bearing sediment permeability, which influences the flow behavior of fluids, is a key physical parameter used to determine the exploitation efficiency of hydrate. However, no comprehensive overview of existing research related to its measurement and application development has been conducted to date. In this review, the related advances in sediment permeability are systematically summarized in terms of experiments, models, numerical simulations, and its influence on hydrate exploitation. The sediment permeability measurement and their influencing factors have been comprehensively analyzed. In particular, the effects of hydrate phase transition on sediment permeability are discussed in detail. In addition, the normalized models of sediment permeability and numerical simulations of sediment structure are investigated. However, no universal normalized models of sediment permeability and numerical simulation of hydrate phase transition are available. The mechanism by which sediment permeability magnitude and anisotropy influence the hydrate exploitation efficiency has also been discussed. Finally, future efforts should focus on dynamic evolution, high-precision measurement, multifactor coupling effect, generalization of models, and optimization of numerical simulations, which are beneficial to improve guidance for the commercial exploitation of hydrate.

In this work, the flooding processes of low salinity waterflooding and low salinity polymer flooding (LSWF and LSP) in sandstone reservoirs were mechanistically modelled at nano-and macro-scales. Triple-layer surface complexation models were utilised to simulate interactions at the oil-brine and sandstone-brine interfaces. The Derjaguin-Landau-Verwey-Overbeek (DLVO) theory was applied to describe the stability of interfacial films in crude oil-brine-sandstone rock systems. The novel application of the maximum energy barrier (MEB), calculated from the interaction potential of the DLVO theory, as an upscaling and interpolant parameter to adjust relative permeability curves as a function of reservoir properties is proposed in this work. Numerical simulations using the commercial simulator CMG-STARS were used in tandem with the surface complexation models and film analysis to evaluate the performance of LSWF and LSP in sandstone reservoirs.

Results of the numerical simulations showed that the LSP gave significantly higher oil recovery compared to standard polymer flooding because of its utilisation of wettability alteration due to LSWF and the improved mobility control due to LSP. A comparison between studied injection processes i.e. low and high salinity waterflooding, and low and high salinity polymer flooding, revealed that oil recovery as a result of wettability alteration is significantly higher than that of mobility control. Further analysis indicated that temperature affects the wettability alteration favourably, and the polymer slug viscosity unfavourably. However, the temperature effect on the wettability was found to be more pronounced. The workflow presented in this study provides valuable guidelines in screening the appropriate sandstone reservoirs for LSWF and LSP applications using the numerical simulation techniques through the upscaling from nano-to-macro-to-field scale.