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Journal of Petroleum Science & Engineering
Elsevier Science B.V.
Journal of Petroleum Science & Engineering

Elsevier Science B.V.

0920-4105

Journal of Petroleum Science & Engineering/Journal Journal of Petroleum Science & Engineering
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    Effects of bedding direction on brine imbibition in Lower Shaximiao tight sandstone: An NMR analysis

    Xu, LiangLi, QiMyers, MatthewTan, Yongsheng...
    11页
    查看更多>>摘要：Spontaneous imbibition phenomenon caused by capillarity plays an important role in the production of tight sandstone gas. Understanding the effects of bedding direction on liquid imbibition is important as it can give insights into water block phenomena that can negatively impact gas production. In this paper, four tight sandstone specimens were cored from Sichuan Basin, China with different bedding directions (i.e., the angles between the bedding plane and the horizontal plane of four specimens are 0 degrees, 45 degrees, 60 degrees and 90 degrees, respectively). Nuclear magnetic resonance (NMR) technique was used to monitor the fluid distribution changes during the spontaneous imbibition processes of these specimens. The results show that such tight sandstone exhibited strong hydrophilicity with the small pores dominating throughout the imbibition process. The T2 spectra for all four rocks specimens not only increased upward but also shifted to larger relaxation times due to brine intake along the minerals surface (further indicating the hydrophilic characteristics of this rock). For such tight sandstone, capillary force and friction resistance between the fluid (brine) and mineral surfaces controlled the imbibition processes. For the 0 degrees, 45 degrees and 60 degrees specimens, "stop illusion" phenomena which the imbibed brine volume had a tiny increase during a long period occurred. However, this was not observed in the 90 degrees specimen (where the bedding direction and fluid flow direction are parallel). This is largely attributed to the significant tortuosity in the flow for the 0 degrees, 45 degrees and 60 degrees specimens compared to the 90 degrees specimen, leading the smallest friction resistance existed in the 90 degrees specimen. Among these four specimens, the 0 degrees specimen had the slowest imbibition rate and lowest imbibition efficiency, while the 90 degrees specimen exhibited the fastest rate and highest efficiency. With the aim of maximizing gas production, this work provides some guidance for the selection of directional fracturing and injection-production methods in the exploitation and production of tight sandstone gas field.
      原文链接:
    • NSTL
    • Elsevier

    Oil-in-water and water-in-oil emulsions formation and demulsification

    Sousa, Ana M.Pereira, Maria J.Matos, Henrique A.
    18页
    查看更多>>摘要：In the petroleum industry, oil and water emulsions are frequent, not only in oilfield operations but also during the transportation and refining processes. Once depicting emulsion formation and stabilization, it is essential to analyse how it is possible to reverse the process, demulsifying the emulsion. Depending on operating conditions and fluid components, crude oils can form stable emulsions with water. In fact, some of the oil's compounds can act as natural surfactants, decreasing the interfacial tension between fluids, promoting emulsification. Several studies have been developed to analyse how the emulsification process occurs and how to demulsify them. However, the literature does not offer a systematic review of both methods. The current work is a critical review to highlight the energy input needed to promote the formation of an emulsion and the type of emulsifying agents necessary to enable the appearance of oil-in-water or water-in-oil emulsion. Secondly, this work also aims to review the state of the art of demulsification techniques applied in the oil industry. The result offers a robust background on this matter, discussing the demulsification methods, enabling a decision support perspective since it emphasizes their advantages and disadvantages.
      原文链接:
    • NSTL
    • Elsevier

    Influence of sequential changes in the crude oil-water interfacial tension on spontaneous imbibition in oil-wet sandstone

    Sukee, AnupongNunta, TanakonHaruna, Maje AlhajiKalantariasl, Azim...
    10页
    查看更多>>摘要：Crude oil-water interfacial tension in petroleum reservoir is reduced or increased due to surfactant injection or surfactant retention, respectively. Changes in the interfacial tension crucially attribute to a governing capillary pressure and hence an oil displacement in spontaneous imbibition process. While a reduction in the interfacial tension has been highlighted as one of the underlying mechanisms for enhanced oil recovery, fluctuated surfactant concentration within reservoir promptly disturbs such interfacial phenomenon. The current study therefore attempts to elucidate an influence of such changes on spontaneous imbibition by replacing surfactant concentration consecutively with two approaches: sequential decrease and sequential increase in the interfacial tension. Two fluid flow directions were examined simultaneously: co-current and counter-current flows. Dimensionless numbers were analyzed to emphasize the fluid displacement. With strongly oil-wet wettability (contact angle >= 123 degrees), capillarity was a resisting element to oil displacement and therefore controlled by the oilwater interfacial tension. The sequential-reduced interfacial tension was found to weaken such resisting capillary force gradually and resulted in consecutive incremental oil production. On the contrary, the sequential-increased interfacial tension initiated the lowest interfacial tension fluid that produced an immediate large amount of oil, but did not much displace further oil. The current study also observed a greater oil recovery obtained from a sequential reduction in the interfacial tension scheme (26.9%) compared to a conventional single reduction scheme (22.4%), with both schemes attaining same interfacial tension at last. Variation in pore-filling events was believed to attribute to such discrepancy since an inertia hindrance to oil displacement developed differently. In counter-current imbibition, same characteristics of oil displacement were observed as in co-current imbibition, with less oil produced (<= 17.6% ultimate recovery) and less sensitive to fluid changes due to negligible gravitational contribution. The results emphasized how the sequential-reduced interfacial tension exhibits a greater oil recovery by imbibition as analogy to secondary oil production by surfactant injection after water flooding, while increasing interfacial tension is likely attributed from surfactant retention could produce less oil.
      原文链接:
    • NSTL
    • Elsevier

    Effect of pressure fluctuation in oil-gas multiphase pump on cavitation and performance of sealing liquid film

    Zhang, JinyaZhang, JiaxiangLi, QingpingGao, Chang...
    14页
    查看更多>>摘要：During the operation of the oil-gas multiphase pump, due to the variable gas content of the incoming flow, the medium pressure at the high-pressure end fluctuates widely, which is easy to cause the stress change at both ends of the mechanical seal compensation ring and "instability" phenomenon. In this paper, a three-dimensional spiral groove seal film model is established. Considering the cavitation effect of liquid film gap, the variation law of end face cavitation and sealing performance of liquid film seal is explored according to the effect of pressure pulsation in the pump on the inner diameter side (Static mechanical seal, PLAN74 flushing scheme in API 682) and outer diameter side (Rotary mechanical seal, PLAN53A flushing scheme in API 682). The results show that the local pressure drop in the sealing liquid film is the main cause result to cavitation of liquid film. The inner diameter side pressure fluctuation has a great impact on the end face cavitation, and the wave peak is about 100 times that of the outer diameter side pressure. The inner diameter side pressure fluctuation should be avoided in engineering application. There is hysteresis between gas volume fraction (GVF) and boundary pressure fluctuation. The synchronization between sealing performance parameters and outlet pressure fluctuation is good, but there is phase difference with inlet pressure fluctuation. The inner diameter side pressure fluctuation has a great change on the sealing performance. The peak is about 5-20 times that of the outer diameter side pressure, which is easy to cause vibration of the mechanical seal. The amplitude and period of pressure fluctuation have a great impact on the GVF and sealing performance. The larger the fluctuation period is, the less obvious the hysteresis of GVF is, and the closer to the variation law of pressure fluctuation. During the actual operation of the oil-gas multiphase pump, the mechanical seal connected with the medium in the pump is rotary, and the flushing scheme ought to be PLAN53A to ensure the safe and stable operation of the oil-gas multiphase pump.
      原文链接:
    • NSTL
    • Elsevier

    Organic geochemical signatures of source rocks and oil-source correlation in the Papuan Basin, Papua New Guinea

    Xu, MinHou, DujieLin, XiaoyunLiu, Jian...
    13页
    查看更多>>摘要：The Papuan Basin is the largest petmliferous basin in Papua New Guinea (PNG), where developed several sets of potential source rocks (SRs). The Jurassic SRs are clay-rich shales, whose organic matter (OM, mainly type II2-III) is predominantly derived from terrestrial higher plants deposited in a more oxic environment with relatively high maturity (0.35% < Ro < 2.03%). The Cretaceous SRs contain mixed inputs of terrigenous and marine OM (type II2-III) formed in sub-oxidized to oxidized depositional conditions with moderate maturity (0.33% < Ro < 1.58%). Whereas the Paleocene-Miocene SRs are predominant marine calcareous shales with subsidiary terrigenous OM inputs. These SRs containing type III kerogen are mostly immature (0.21% < Ro < 0.70%). The Papuan Basin oils were classified into three distinct genetic families based on biomarkers and stable carbon isotopes. Family A oils, with heavy carbon isotopes, low Pr/Ph ratios, C-29/C-27 alpha alpha alpha 20 R sterane <1.0, are likely originated from autochthonic Paleogene-Neogene mature marine OM. Family B oils have the characteristics of high Pr/Ph, moderate carbon isotopes, the dominance of C-29 alpha alpha alpha 20 R sterane, and are predominantly derived from autochthonous Jurassic SRs. Family C oils in the Eastern Papuan Fold Belt (EPFB) can be further subdivided into three subtypes by more subtle differences in specific biomarkers. Type C-1 oils, most likely stemmed from the Lower Cretaceous SRs, are characterized by light stable carbon isotopes, Pr/Ph > 2, the mild dominance of C-29 aaa 20 R sterane and the absence of oleanane +/- lupane. Type C-2 oils can be clearly distinguished from Type C-3 by C-19/(C-19 + C-23) tricyclic terpane <0.5, while the latter ones have higher abundances of oleanane +/- lupine and diahopanes as well as C-24 tetracyclic/C-23 tricyclic terpane ratios. Type C2-3 oils are originated from calcareous SRs that deposited in Late Cretaceous or younger age.
      原文链接:
    • NSTL
    • Elsevier

    Developing novel bio-nano catalyst well clean up fluid to remove formation damage induced by polymeric water-based drilling fluids

    Mohammadi, Mojtaba KalhorRiahi, SiavashBoek, Edo S.
    10页
    查看更多>>摘要：Drilling and completion fluids may cause significant formation damage in oil and gas reservoirs, directly affecting productivity. For many years, operators have applied different stimulation practices such as acidizing, oxidizers, chelating agents, and enzyme treatment to remove formation damage associated with drilling fluids filter cake. An enzyme-based biological treatment was combined with other chemicals or additives as a selective well clean-up practice to improve removing polymer content in the filter cake. However, the secondary formation damage such as deep cleaning of the invaded zone and wettability alteration remained the main concern. This paper presents the development of an innovative clean-up fluid formulation by immobilizing an enzyme and a selective nanoparticle as Bio-Nano Well Clean-Up Fluid (BNWC) in potassium chloride brine to enhance WBM filter cake removal. Several bulk experiments, including; precipitation, iodine test, and viscosity measurement, demonstrate the enzyme's optimization, the nanoparticle concentration, and base fluid brine. BNWC in potassium chloride brine showed the highest HPHT filtration rate at 200 degrees F and differential pressure of 100 psi and increased the filtration rate by more than 90 percent compared to the conventional enzyme in the same brine. Contact angle measurements confirmed wettability alteration of the carbonate rock to water-wet, and IFT measurements showed higher oil mobility potential. Finally, core flooding tests at reservoir conditions showed a 300 percent enhancement in injection rate and a 50% improvement in core permeability after damage. The immobilization of the enzyme with the nanoparticle has been developed successfully for other applications in bioremediation, farming, and other industries, but the novelty of this research demonstrates the application of nanobiocatalysts in drilling fluids for the first time. This innovative clean-up fluid enhances the enzymatic activity and removes primary and secondary formation damage associated with drilling fluid filter cake.
      原文链接:
    • NSTL
    • Elsevier

    A lattice Boltzmann simulation on the gas flow in fractal organic matter of shale gas reservoirs

    Hu, BowenWang, J. G.
    16页
    查看更多>>摘要：The gas flow in the organic matter with multiple flow regimes is critical to the shale gas production from shale gas reservoirs, but simultaneously simulating the full flow regimes of shale gas in the nanopores of the fractal shale organic matter is still unavailable. This paper presents a modified lattice Boltzmann model with effective relaxation time to simulate the shale gas micro-flow behaviors in fractal organic matter for permeability prediction. Firstly, some fractal shale organic matters are reconstructed by the quartet structure generation set (QSGS) algorithm, and the structural parameters such as fractal dimension, lacunarity and average pore diameter are calculated to characterize the complexity of the fractal shale organic matter. Secondly, effective viscosity and Knudsen layer are introduced into the effective relaxation time to formulate a modified lattice Boltzmann model. Thirdly, this modified lattice Boltzmann model is verified by comparing with the theoretical permeability models for the gas flow in the body centered cubic (BCC) arrays. Finally, a series of gas flow simulations in reconstructed fractal shale organic matter are conducted to explore the effects of structure parameters on permeability. Numerical simulations show that the modified lattice Boltzmann model can simulate the full gas flow regimes and predict the permeability of the fractal shale organic matter. The logarithm of permeability is negatively linearly correlated with fractal dimension and positively linearly correlated with lacunarity of the shale organic matter. This permeability exponentially increases with the increase of average pore diameter and a power law is observed between the fractal dimension and average pore diameter of these fractal shale organic matters. The anisotropic structures have great impacts on the directional permeability of shale organic matter. The permeability kx in the horizontal direction increases first and then decreases with the increase of anisotropic ratio (AR) and reaches the peak when AR is about 20. The permeability ky in the vertical direction monotonically decreases with the increase of AR.
      原文链接:
    • NSTL
    • Elsevier

    Natural fractures and their contribution to tight gas conglomerate reservoirs: A case study in the northwestern Sichuan Basin, China

    Zeng, LianboGong, LeiGuan, CongZhang, Benjian...
    10页
    查看更多>>摘要：Well-developed natural fractures in the tight gas conglomerate reservoirs of the northwestern Sichuan Basin, China, are proved to greatly contribute to the porosity and permeability of such reservoirs. Natural fractures can be storage space for hydrocarbons in the reservoir and also serve as fluid flow conduits. Outcrops, cores, and image logs were assessed in order to understand the natural gas production from the tight conglomerate reservoirs. Based on the type of interaction between fractures and clast grains, here we present three types of fractures in the conglomerate tight gas reservoirs: intergranular fractures, intragranular fractures, and grain-edge fractures. These fractures may be tectonic, diagenetic, or combined tectonic-diagenetic. Factors affecting natural fracture development in conglomerates include composition of grain and interstitial material, grain size, contact behavior of grains, and structural position. Well-developed open fractures make up over 70% of the porosity within the tight conglomerate reservoir, while the local permeability can be 3-5 orders higher than that of the matrix reservoir. Natural fractures can also significantly impact the natural gas productivity from individual wells. Production data suggests that higher natural fracture intensity correlate with higher natural gas productivity from wells. Compared with the intensity of intragranular fractures and grain-edge fractures, the high intensity of intergranular fractures shows a notably stronger correlation with high gas productivity. The impact of fractures on natural gas productivity varies greatly with fracture orientation. East-West fractures are predominant flow channels under the existing East-West stress field, contributing significantly to gas production. Northeast-Southwest-oriented fractures are of secondary importance.
      原文链接:
    • NSTL
    • Elsevier

    Investigation on drag reduction of aqueous foam for transporting thermally produced high viscosity oil

    Fu, JiqiangLu, YingdaUllmann, AmosBrauner, Neima...
    15页
    查看更多>>摘要：An innovative idea is proposed for facilitating the transportation of thermally produced high-viscosity oil by injecting temperature tolerant aqueous foam. To this aim, experimental investigations of the flow characteristics of heated highly viscous oil flowing through a 25 mm i.d. horizontal rough-wall tempered borosilicate glass pipe were conducted. Measurements were made for the superficial oil and foam velocities in the range of 0.05-0.40 m/s and 0.04-0.39 m/s, respectively. Eccentric core annular flow configurations detected by a high-speed camera were found to be particularly dominant throughout the entire tested range. A two-fluid, three-zone mechanistic model for horizontal foam-oil flows was implemented for the case of shear thinning power-law fluid in the annulus, which is in accordance with the foam rheological behavior at the tested elevated temperature. Good agreement was achieved between the predicted and measured data over a wide range of operational conditions. When a complete foam annulus encapsulating the oil core is formed, a critical value of input foam volume fraction can be determined for the maximum drag reduction ratio. An optimal oil core-to-pipe radius ratio range was determined for the highest oil-transport operational coefficient. The drag reduction performance of the tested hot oil-foam system is better than that obtained with the oil-foam system employed at room temperature.
      原文链接:
    • NSTL
    • Elsevier

    Study on recovery factor and interlayer interference mechanism of multilayer co-production in tight gas reservoir with high heterogeneity and multi-pressure systems

    Chai, XiaolongTian, LengDong, PengjuWang, Chunyao...
    14页
    查看更多>>摘要：The coupling effects of complex pore structure and poor reservoir properties generally lead to relatively low production of single layer in tight gas reservoir. The multilayer or multilayer co-production increasingly gain popularity in exploitation of tight gas reservoirs to achieve high recovery factor and economic profit. The multilayer co-production of tight gas reservoir with high heterogeneity or multi-pressure systems is more complex than that of the single-layer production. It is still not very clear about the mechanism of co-production. To fill this gap, a set of numerical simulations are intentionally designed and implemented in this paper to systematically understand production characteristics, interlayer interference, and recovery factor of multilayer co-production in tight gas reservoirs. Based on the established numerical gas reservoir simulation model, sensitivity analysis of influencing parameters of interlayer interference and recovery factor, including interlayer permeability contrast, interlayer pressure difference, thickness of gas layer, gas saturation, and producing rate, has been carried out. Subsequently, a type of machine-learning method, i.e., random forest method (RFM), is use to quantitatively characterize the main influencing parameters on interlayer interference and recovery factor. In the end, the predicted models of recovery factor and interference time are proposed by using the linear correlation and nonlinear correlation. The numerical experiment results reveal that the gas of high-pressure layer will flow back to the low-pressure layer in the multilayer co-production scenario and the influencing parameters have a great effect on daily gas production, recovery factor, backflow time, formation pressure and contribution rate of each layer. The thickness of gas layer and producing rate have the strongest and weakest influences on the gas recovery, respectively. However, the influence of interlayer pressure difference on interlayer interference is highest and the gas saturation has a lower effect on interference time than other parameters. The recovery factor and interference time of multilayer co-production is about 54.09%-63.82% and 55-565 days respectively. The correlation results of recovery factor and interference time have a good agreement with the results of numerical simulation, and the uncertainties are controlled within 10%. The research results of numerical simulation, RFM and predicted model are applied to a gas well of the tight gas and the validity and practicability of the results are verified, which can provide a solid foundation for the exploitation of tight gas reservoirs with high heterogeneity and multi-pressure systems.
      原文链接:
    • NSTL
    • Elsevier