Journal of Petroleum Science and Engineering最新文献

Drilling mud acts as an important primary barrier during the well construction phase, while the integrity of cement sheath is critical throughout the life cycle of the well. The mud-spacer-cement interactions highly affect the long-term integrity of the cement sheath and in other words the well integrity. Even today, the spacers are not capable of displacing all the drilling mud present in the wellbore before performing cementing operations and the cement slurry is contaminated with a small amount of drilling fluid and/or spacers. Oil based mud (OBM) is highly preferred over water-based mud (WBM) as a drilling fluid when drilling in challenging environments, but with current push for more environmentally drilling fluids the Water Base Muds (WBM) are preferred.

The detrimental effects of high OBM contamination (>5%) on the mechanical and rheological properties of API Cement slurries have been fairly studied in the previous decade. This study focuses on the strength development of low OBM contaminated (0.8%, 1.6%, 3.2%, 6.3%) API Class H cement slurries cured for up to 28 days at ambient temperature as well as the elevated temperature of 75 °C. The Ultrasonic Pulse Velocity (UPV) was measured by performing the non-destructive tests before performing the destructive tests which measure the actual Unconfined Compressive Strength (UCS). Based on the 141 samples tested in this study, even for 0.8% OBM contamination the strength of Class H cement samples cured for 7 days at 75 °C was reduced by 23%, and for 3.2% OBM contamination it was reduced by 39%. Novel correlations of UCS vs time and UCS vs UPV were developed to accurately simulate the downhole conditions and predict the long-term integrity of the wellbore cement. A reliable dataset for developing cement data repositories was established which also can be merged with existing databases.

Petrographic thin section images have an important role in depositional environment inference, prediction of reservoir physical properties, and oil and gas analysis. To overcome the current challenges in thin section image denoising, we propose the global residual generative adversarial network (GR-GAN). Compared with the classical generative adversarial network (GAN), the residual network structure of the GR-GAN is reconstructed, and the loss function is redefined. The GR-GAN is then applied to denoise the thin section images in two different oilfields. The final denoising results confirmed that the GR-GAN achieves the best denoising effects on both visual evaluation metrics and objective evaluation metrics compared with colour block-matching 3D filtering (CBM3D), K-singular value decomposition (K-SVD), the GAN and a fast and flexible denoising network (FFDNet). Specifically, the peak signal-to-noise ratio (PSNR) and structural similarity (SSIM) generated by the GR-GAN on the test set are 28.2410 and 0.9674, 28.1075 and 0.9443, and 27.9919 and 0.9399, respectively, when the Gaussian noise is 15 dB, 25 dB and 35 dB, respectively, in the thin section image of the small-pore and fine-throat-type structures of J Oilfield; however, the data become 27.2841 and 0.9228, 26.8177 and 0.9162, and 26.3043 and 0.9068 for CBM3D, respectively, and these data generated by other methods are between the aforementioned two sets of data. The normalized root mean squared error (NRMSE) generated by the GR-GAN and CBM3D with the test set are 0.0327 and 0.1382, 0.0584 and 0.1341, and 0.0786 and 0.1382, respectively, when the Gaussian noise is 15 dB, 25 dB and 35 dB, respectively, and the NRMSE generated by the other methods is also between the aforementioned two sets of data. For other types of thin section images, when the Gaussian noise is 15 dB, 25 dB and 35 dB, respectively, CBM3D, K-SVD, the GAN, FFDNet and the GR-GAN show similar denoising effects as previously described. Moreover, in a denoising experiment repeated more than 10 times with the above methods, the GR-GAN has the shortest mean running time of 1.0589 s, and the mean running times of CBM3D, K-SVD, the GAN and FFDNet are 6.4609 s, 155.3158 s, 1.9394 s and 1.0622 s, respectively.

Treatment of the oilfield wastewater from the chemical and petroleum industries, often present in the form of emulsion, is one of the major environmental concern in current times. Demulsification is presently the most viable method to separate the oil and water from a rigid, homogenous emulsion especially, chemical demulsification. Mostly, chemical demulsifiers used at high temperature can give enhanced separation efficiency and result in the use of less dosage of expensive chemicals. Mainly, the reservoir conditions also exist at high temperature, thus, it is important to consider the effect of temperature for the selection of best choice among available demulsifiers. The review discusses the recent discoveries and modification among the existing demulsifiers such as triblock EO-PO copolymer, non-biodegradable polymers, branched copolymers and others. The major chemical demulsifiers and their upcoming alternatives such as the nanomaterial demulsifiers and ionic liquids have also been discussed in great details. Chemical structure and molecular weight were found to influence the emulsion breaking ability of a demulsifier. The surface properties play an important role in the selection of appropriate demulsifier whether hydrophobic or hydrophilic. Method of heating whether microwave or conventional heating, doesn't play a significant role in influencing the emulsion breaking efficiency of polymeric surfactants. However, microwave heating is preferred for demulsification by ionic liquids. Lastly, the whole mechanism of chemical demulsification and few upcoming chemical treatments for demulsification are also well described in brief.

Supercritical carbon dioxide (ScCO₂) drilling can effectively protect shale formation from hydration damage and improve drilling rate comparing to conventional drilling technology. The wellbore stability of shale formation is one considerable issue under ScCO₂ drilling conditions. In this study, the numerical simulations are performed to calculate collapse cycling time of shale formation under ScCO₂ drilling conditions based on thermoporoelastic coupling model. The results show that comparing to water seepage condition, the variation of formation temperature is larger, pore pressure and stress are lower for ScCO₂ seepage condition without adsorption effect, the comparison between water and ScCO₂ seepage conditions verifies the thermoporoelastic coupling model. For ScCO₂ drilling conditions, if adsorption‒induced strain is ignored, the risk of wellbore collapse will be slightly underestimated comparing to the results with adsorption effect. When adsorption‒enhanced elastic modulus is ignored, the risk of wellbore collapse will be significantly underestimated comparing to the results with adsorption effect. The wellbore collapse may occur with the increasing well depth for ScCO₂ drilling conditions. This study can provide the theoretical guidance for exploiting shale reservoirs using ScCO₂.

Tuning the concentration of the ions is beneficial for improving oil recovery by water flooding. Despite the widely recognized distribution of salt ions at the water interface, their effects on the structure of interfacial water, such as hydrogen(H) bonds, are unclear. In this study, using oblique incident reflectance difference (OIRD) technique and interfacial rheometer to analyze the alkanes-ion solution interface, we show that ions have a significant effect on the perturbation of hydrogen bonds at the alkanes-water interface. The change in the water layer structure follows the gradual increase in the concentration of Na₂SO₄/Na₂CO₃ and the decrease in the interfacial tension, and dielectric constant at the alkane-solution interface. Specifically, structure-breaking anions such as SO₄²⁻ and CO₃²⁻ decrease the average H-bonding of water at the alkane/water interface, thus damaging the molecular cluster structure at the interface. Although Cl⁻ will form hydration ions with water molecules, it will not break the hydrogen bond structure between water molecules at the interface. These results indicate the mechanism of anion effects on the alkane/water interface, and for samples with high saturated alkane content, a repellent solution containing SO₄²⁻ can be preferentially selected for repelling, providing a new idea for the study of the molecular boundary of the oil-water interface.

Subsea water separation (SSWS) is a promising cutting-edge technology in handling specific problems related to offshore development, but the close evaluation of SSWS performance is quite lacking. This work develops an integrated production modeling (IPM) approach to comprehensively quantify the effect of SSWS both from technological and economical perspectives. A fully-implicit integrated production model is proposed, which assembles 3D reservoir equations and pipeline network equations together and seeks for simultaneous solutions. The feature of simultaneous hydro-thermal solution provides a remarkable value in the analysis of flow assurance issues related to wax deposition in the subsea flowlines. The indexing and mapping frameworks make the model prone to configuring different scenarios, both in temporal and spatial dimensions. A case study is presented to analyze the performance of SSWS under four subsea configurations in a pre-salt deepwater condition by three quantitative indicators: NPV, oil recovery, and wax-free index. Results show that subsea water separation has the potential to increase final oil recovery and project NPV for a clustered well system, while limited benefits shall be expected in a satellite well configuration. Also, higher risk of wax deposition is observed in a satellite well configuration compared to a clustered well system. The IPM approach, together with an economic model, provide decision makers with a way to estimate the break-even price on the investment of a subsea water separation station. The methodology proposed in this work also provides a guide in future assessment of other potential subsea technologies.

We apply Massively Parallel Interface for MPFA-O scheme with state-of-the-art Operator-Based Linearization (OBL) approach for multiphase flow in porous media. The implementation of MPFA-O scheme enhances the modelling capabilities for non-K-orthogonal mesh. A fully implicit scheme is applied to guarantee the stability of solutions when a mass-based formulation is involved to keep the flexibility of the framework for general-purpose reservoir simulation. As the MPFA-O introduces more non-zeros elements in the Jacobian matrix than the traditional TPFA, massively parallel computations via Message Passing Interface (MPI) in this work help to guarantee competitive computational efficiency for high-fidelity geological models. Concerning the Jacobian assembly hassle, we apply the OBL approach which introduces operators combining the fluid and rock properties in the conservation equations and discretizes the operators in the physical parameter space. By computing values and derivatives of the operators via a multilinear interpolation, the assembly of Jacobian matrix and residual vector could be drastically simplified. Another benefit of the OBL is that by only evaluating operator values on the predefined nodes in the physical parameter space, the overhead related to complex phase behavior and property evaluation is significantly reduced. In the end, we present several benchmark cases to rigorously demonstrate the accuracy, convergence, and robustness of the framework and two challenging field-scale cases to further prove its computing performance and parallel scalability.

Well drilling, completions, stimulation, and enhanced oil recovery operations induce downhole conditions that may negatively impact the integrity of the annular seal and consequently hinder zonal isolation. Thus, the ability to accurately quantify the evolution of the annular seal in response to the prevailing downhole environment is critical for the optimal design of the annular barrier for the life of a well. Thanks to increased accessibility and recent advancements in computing power and techniques, X-ray computed tomography has gained popularity as a non-destructive analysis method in materials science and geomechanics due to its ability to reveal details about the interior volume of objects in real-time without physical disassembly.

Therefore, in this study, a novel apparatus is presented for the construction of a lab-scale wellbore, with the purpose of simulating downhole processes while simultaneously monitoring wellbore elements of interest in real-time via x-ray computed tomography. The benefits of this novel setup for wellbore integrity are demonstrated via applications to two test cases: the mechanical evolution of annular cement under stresses induced by cyclic water injection as a function of the mechanical properties of the cased and cemented wellbore system; the evaluation of nano magnesium oxide performance as an additive for autogenous shrinkage mitigation in annular cement.

The results of the studies presented illustrate the benefits of combining x-ray computed tomography with lab-scale wellbore process simulations. The results of the cyclic water injection study suggest that residual strain in the cement is the major factor in annular seal degradation under cyclic downhole pressure fluctuations. Nano magnesium oxide is also shown to be very effective in preventing autogenous shrinkage of Class H cement. However, more study is required to characterize its effectiveness in a wider range of cement formulations. Finally, suggestions are offered on how to improve the experimental procedure presented while future potential applications of the apparatus are discussed.

The eastern Tunisian margin is considered an Upper Cretaceous and Eocene petroleum province. It has been affected by Mesozoic rifting and Cenozoic compression. Several oil and gas shows and accumulations have been discovered in Upper Cretaceous carbonates within structural anticlinal closures. These anticlinal highs represent inherited rift platform horsts with hiatuses, unconformities and sediment erosion. Seismic sequence stratigraphy and seismic tectonic analyses of Mesozoic and Cenozoic horizons, delineate the control of deep-rooted transtensional and transpressional Flower structure fault corridors, intruded by Upper Triassic salt. Petroleum system modelling and time events chart reconstruction of real and pseudo-wells, indicate that Cretaceous source rocks maturation and hydrocarbon generation began during Late Cretaceous with expulsion occurring from Eocene to Pliocene times. Hence, Upper Cretaceous petroleum system dynamics is intimately linked to basin geodynamics; where hydrocarbon migration pathways could follow the migration, rotation and tilting of platform and basin blocks. The volume of Lower Fahden and Bahloul source rocks expelled hydrocarbons from the basin kitchens, is much greater than that found in the drilled anticlinal axis. These hydrocarbons could have been trapped along the platform-basin border flanks and may not have reached the highest position on the anticlinal crest closure. Such pathways explain the unaccounted-for hydrocarbon volumes. These volumes could be trapped along the faults seal branches, unconformities, pinchouts as well as in the evidenced progradational and reefal system tracts sequences in the flank borders of the platforms. These traps could represent new exploration targets as potential structural and stratigraphic plays.

In this study, Modified Laponite with lyophobic wettability was synthesized as a multi-functional additive to solve instability of emulsions, rheological deterioration, and wellbore instability of oil-based drilling fluid. Properties and its influence on emulsion stability, rheological behavior and plugging property were investigated. The results showed that Modified Laponite was in a shape of sheet layer and had micro-meter length and nano-meter thickness which was in match with the diameter of shale pores. And it was proved to be resistant to approximately 450 °C by thermogravimetric analysis measurement. Mechanism analysis revealed that Modified Laponite could stable the oil-based drilling fluid through four sections. Firstly, Modified Laponite with lyophobic wettability could promote its existence in the interface of brine/mineral oil. Secondly, Modified Laponite could decrease the interfacial tension from 32.8 to 13.5 mN/m to maintain the emulsion particles in a small size for a long time then to ensure the emulsion stability. Thirdly, Modified Laponite could enhance the shear-thinning rheological behavior which could maintain the rheological stability and enhance the sedimentation stability in ultra-deep reservoirs with high temperature and high pressure conditions. Fourthly, Modified Laponite could plug the shale pores effectively by preventing pressure transmission and enhancing shale compressive strength, and decrease the filtration volume of oil-based drilling fluid from 7.4 mL to 2.6 mL after aging at 180 °C for 16 h to stable the wellbore. Therefore, Modified Laponite was a multifunctional additive to stable the emulsion, enhance the rheological stability and strength the wellbore stability, which could ensure the application of oil-based drilling fluid in drilling process of ultra-deep reservoirs.