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 demulsi-fication. 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 tem-perature, 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 in-fluence the emulsion breaking ability of a demulsifier. The surface properties play an important role in the se-lection 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.
When a gas hydrate reservoir is depressurized for gas production, the production tendency and dissociation behavior may differ depending on conditions such as the bottom hole pressure and depressurization rate. Gas hydrate dissociation is a complex process that involves the transfer of materials and heat, and on-site analysis based on laboratory-scale results is critical. In the present study, a field-scale numerical analysis was performed to reflect the conditions of the Ulleung Basin in the East Sea of Korea. The dissociation behavior, which varies depending on the conditions in the gas hydrate-bearing sediment, was analyzed under various conditions of bottom hole pressure and depressurization rate. This study also identified the effects of depressurization conditions on gas hydrate saturation. As the bottom hole pressure decreased and the depressurization rate increased, the production rate and cumulative production of gas and water increased, and the radius of the pressure propagation effect at the beginning of production increased. In sediments with a gas hydrate saturation of ≥70%, the pressure propagation was unstable and the dissociation rate was low. These results can serve as preliminary data for the field production of gas hydrates in the Ulleung Basin.
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.
Breakthroughs in shale gas exploration in the Upper Ordovician-Lower Silurian strata of the Upper Yangtze Platform have attracted interest in its sedimentary-tectonic evolution, but the tectonic background of the northern margin of the Upper Yangtze Platform remains unclear. In this paper, the Wufeng-Longmaxi formations on the northern margin of the Upper Yangtze Platform were investigated. Based on geochemical and mineral-ogical analyses of the tuffs/K-bentonites of the Wufeng Formation and the barite in the Longmaxi Formation, as well as previous research results, it was concluded that the northern margin of the Upper Yangtze Platform was in an extensional tectonic background during the Late Ordovician-Early Silurian. Detailed analysis revealed that, (1) the U-Pb zircon age of the tuff in the Bajiaokou section in South Qinling is 443.91 +/- 0.92 Ma. The Zr/ TiO2-Nb/Y diagram of the tuffs/K-bentonites indicates that their protoliths were alkaline-subalkaline basalt and andesite series rock. Based on the Th-Hf/3-Ta, Th-Tb*3-Ta*2, and TiO2-Nb/3-Th diagrams, there are undis-covered intraplate tension calc-alkaline basalts in the northern Yangtze Platform or the southern Qinling region, which provided volcanic clastic materials to the Ziyang, Lan'gao, Chengkou, Yichang and other regions. (2) Scanning electron microscopy revealed that the barite crystals in the Longmaxi Formation exhibit dissolution features and have a large particle size. Energy spectrum analysis of these barite crystals revealed that they have C, O, S, and Ba contents of 8.48 wt%, 22.98 wt%, 13.09 wt% and 55.44 wt%, so they are speculated to have been formed via cold methane seep genesis in a weak extensional tectonic setting. The 87Sr/86Sr ratios of the barite revealed that different types of barite were simultaneously formed in this area under the influences of hydro-thermal and cold methane seeps. (3) The analysis of the heavy minerals in the Lower Silurian strata in the Bajiaokou section revealed that the provenance in the South Qinling area changed significantly during the late Early Silurian. Based on the above analyses, the northern margin of the Upper Yangtze Platform was in an extensional tectonic setting during the Late Ordovician-Early Silurian. The distribution of the total organic carbon content indicated that the extensional tectonic background provided good conditions for the enrichment and preservation of organic matter. The results of this study provide an understanding of the regional sedimentary-tectonic pattern and evolution of the Yangtze Platform during this period, as well as a reference for future shale gas exploration in this region.
Significant natural fractures develop in deep sandstone reservoirs. However, the previous numerical simulation for matrix acidizing in sandstone rocks always focused on the reactive flow in porous media. A series of responses between multiple types of acids and minerals in fracture and matrix pores have been a significant setback for seeking the mechanism of acid flow in fractured sandstone rocks. This paper, established a multistage reactive-transport model for fractured sandstone rocks based on the two-scale continuum model to explore the effects of fractures on the reactive flow. The weak forms of fluid flow and solute transport equations are derived using the Galerkin method to couple the matrix and fracture domains, and the extended finite element method was used to solve the discretization model. Additionally, we presented numerical simulations under 2D linear flow conditions with specific and sensitive analyses about fracture and matrix properties. Numerical cases showed that the wormhole-shaped structure generated by acid dissolution is hard to develop even in highly heterogeneous fractured sandstone rocks due to the low reaction rate between mud acid and minerals. However, fractures that are not parallel to the flow direction can accelerated acid flow in the formation and reduced Si(OH)4 precipitation. Increasing the injection rate can not change the dissolution patterns of sandstone, but expanded the acid diffusion range and decreased Si(OH)4 precipitation in fractured sandstone.
Ghana is recognised as one of the recent oil and gas producing countries in the Gulf of Guinea, West Africa. However, despite the significant hydrocarbon accumulation in the Western Basin of Ghana, not much is known about the current potential of source rocks in this Basin. To broaden the scope of current knowledge on the Western Basin of Ghana, this paper identifies the current formation potential, organic matter origin, thermal maturity, and possible ages within the Cretaceous Period for hydrocarbon generation in the basin, using geochemical techniques and statistical analyses of 1530 cuttings and core samples. The geochemical parameters include pyrolysis data such as free hydrocarbon (S1), hydrocarbon generated (S2), carbon dioxide released (S3), hydrogen index (HI), production index (PI), maximum temperature (Tmax), oxygen index (OI) and total organic carbon (TOC). The formations encountered in the Western Basin, which have various ages within the Cretaceous Period , show a good to very good possibility of producing hydrocarbon with mainly kerogen type II/III and some amount of type I in certain formations. The majority of the Cretaceous ages fall in the early mature to peak maturity zone, with Campanian and Santonian considered as additional hydrocarbon sources to the Albian, Cenomanian, and Turonian. Pearson coefficient showed that TOC has a strong positive correlation with S2, positive correlation with S1 and HI, and negative correlation with Tmax. Two-Step and K-means clustering on the studied samples show that TOC, S2, and S3 are the major parameters for source rock potential prediction. Factor analysis gave three factors affecting source rock evaluation. Factor 1 highlights TOC, S1, and S2 as the parameters for identifying the quantity and quality of organic matter. This is confirmed by factor 2, which identifies HI and OI as the determining variables. Factor 3 identifies PI and Tmax as indicators of the thermal maturity of the source rock.
As an important tool for tripping of a drill-string, a drill-pipe (DP)-slip system directly affects both the service life of a DP and the target depth it can reach. In this paper, a finite element (FE) model programmed in ABAQUS is used to simulate interactions within a DP-slip system. For this model, materials, geometric dimensions, loads, and boundary conditions were determined from an actual DP-slip system. A special attention has been paid on the stress field of the slip insert and the DP focusing on the geometric parameter optimization of the slip insert with regards to the stress distribution, wherein factors like a longitudinal groove number in slip insert, a number of slip inserts, and a number of row spacing of slip inserts are considered. Numerical results show that the circumferential stress distribution and stress distribution in the direction of DP axis change for both the DP and slip insert and that the stresses of the inner surfaces are higher than that of the outer surfaces. Effects of geo-metric parameters of the slip insert on the stress distributions of both DP and slip insert are studied and the corresponding optimized values are obtained, which can be used when designing slip insert tools.
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.
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.
Pressure pulse telemetry as a novel and effective method of communication has received more and more attention in the field of separate layer water injection for the intelligent oilfield, and identification of the effective pulses and their positions is one of the key technologies. For the logging while drilling process, the fixed threshold method is widely used to identify the pressure pulse. However, in the process of water injection, the amplitude of pressure pulse changes with the change of flowrate controlled by process, which will lead to low recognition rate of traditional fixed threshold pressure pulse. Therefore, a pressure pulse recognition method based on flow-adaptive double threshold with fixed time window is proposed. The packet length of instructions and responses is designed to be short and fixed in order to reduce communication time and failure cost, and the fixed time window method is adopted to improve the decoding efficiency of for a frame of data. The pressure pulse recognition method based on flow-adaptive double threshold is used to identify the effective pulses and their positions to adapt to the change of pressure pulse amplitude induced by different flowrates. The first threshold which is set to fixed and lower than the pulse peak with minimum possible flowrate, is used to filter the most of noise and catch the effective pulses with little noise pulses. The second threshold which is adaptive to changes of the flowrates, is determined by average of three maximum peaks of caught pulses from the first threshold, and is used to identify the effective pulses and their positions. In the experimental well with 2000 m deep, the test results show that the error rate of pulse recognition reduce to 0.003% and communication success rate significantly increase from 50% to more than 96.5%. It means that the proposed double threshold method can be adaptive to identify effective pressure pulse under different flowrates, and then can significantly reduce the error rate of pulse recognition and improve two-way communication performance between the wellhead controller and downhole distributors.
We present an integrated field development planning framework that bridges the integration gap through concurrently optimizing well placement, well trajectory, and facility layout. The novel algorithms implemented in the proposed framework break organizational silos between the reservoir, wells, and facility domains and provide reservoir engineers, drilling engineers, facility engineers, and economists with a shared planning platform. The presented solution is modular, flexible, and allows for multiple layers of granularity and, hence, a spectrum of solutions with different trade-offs between accuracy and efficiency needed as the field development plan is refined through its history. Multiple scenarios and example cases are presented illustrating the features of the integrated optimization framework and their applicability in different potential onshore and offshore oil and gas field development projects. A novel machine learning based optimization algorithm for well trajectory design is presented and achieves significant improvements in computational time compared to traditional optimization approaches. Using a machine learning model to design a well trajectory was three orders of magnitude faster than the differential evolution algorithm which, in turn, was the fastest among the different optimization algorithms that we have tested. The proposed machine learning model drastically reduced the CPU requirements of the integrated solution and enabled the modeling of complex cases of hundreds of wells and associated facility building blocks.
Understanding the effects of temperature and pressure on the supercritical CO2 degradation of wellbore cement with NaCl content is essential for cementing oil wells in Brazil's deepwater pre-salt basin. The behavior of the cement paste used in cementing oil wells in this environment is very complex, with significant amounts of CO2 and a thick salt layer that requires a high demand on special wellbore cement capable of adequately sealing and assuring stability to the oil wells. For these reasons, the objective of this study was to investigate the effect of NaCl in cement on oil wells exposed to supercritical CO2 simulating pre-salt reservoir conditions. Cement slurry samples were prepared using Class G Portland cement (API 10 A), NaCl, water-to-cement (w/c) ratio of 0.46, and deionized water with (0 and 10% NaCl content). Supercritical CO2 experimental runs were carried out under different conditions for 7 h. Before and after exposure to CO2, the material was characterized by multiple analytical techniques. The results indicate that salt under temperature and pressure and the scCO2 environment accelerates the carbonation process by decomposing the hydrated product, increasing the CaCO3 content. In this scenario, investigations of the effect of adding NaCl to cement pastes are limited.
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 cavi-tating 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.
Chang 7 shale reservoir of Ordos Basin has characteristics of low porosity, ultra-low permeability, and low formation pressure coefficient. After hydraulic fracturing, the production of shale oil declines rapidly, and it has no solutions to replenish the formation energy. Currently, a nano variable-viscosity slickwater (named: NSI) is being used in the field for fracturing production. Compared with conventional fracturing fluid systems, the NSI system can increase production of oil wells by more than 4 times, and its economic benefits are very remarkable. The lab experiment shows that NSI system after the gel breaking has ability of enhanced imbibition oil recovery (EIOR), which may be an important stimulation mechanism of the NSI system. However, the contribution of EIOR to oil production is still unclear, and the corresponding mechanism and model are still lacking. Therefore, the fracturing parameters of Changqing Chang 7 reservoir were firstly optimized without considering the imbibition, and two wells were used to carry out field experiments with NSI and conventional slickwater. Then, commercial software is used to predict oil production. It was found that the actual production was higher than the predicted production. To explain this phenomenon, the effect of imbibition on enhanced oil recovery was investigated experimentally under reservoir temperature and pressure. The NMR T2 spectrum was quantitatively analyzed to clarify the variation of oil and water distribution in different pores of core. The results showed that capillary force was dominant in the small pores of core, and small pores were the main positions of EIOR. Water film was formed in large pores, which increases the migration resistance of the liquid, and allowed gravity to play an obvious role. Finally, based on the modified Aronofsky index model, an EIOR model suitable for the Changqing Chang 7 reservoir was proposed, which achieved a better match between actual production and simulated production of horizontal wells.
In recent years, the Shunbei karst-carbonate reservoirs becomes a huge productivity oilfield, which produced over one million tonnes crude oil annually. However, there are difficulties in understanding production contribution of each fault-karst branch in reservoirs, which significantly impacts the efficient development. Multibranched fault-karst reservoirs in the Shunbei have an obvious tree-shaped geostructure, in which the natural fractures and eroded cave develop along multiple large-scale faults. The existing models for pressure transient analysis (PTA) were mainly established for fracture-cave reservoirs only with single fault, which cannot be applicable to characterize the multibranched fault-karst reservoir. To fill this gap, a novel analytical PTA model for horizontal commingled production well in the multibranched fault-karst reservoir was established to describe pressure response and identify flow regimes. First, our model includes the Darcy flow with the fluid compressibility effect in fracture region, and the large-scale vertical storage flow in cave region as well as the horizontal laminar flow in the horizontal wellbore. Then, the accuracy of this PTA model is verified by comparing it with the existing single branch fault-karst pressure model. Further, we applied the model to analyze the Shunbei oilfield case data. Last, the effect of boundary type, fluid compressibility effect, fracture physical properties, and cave spatial distribution on the pressure response are discussed in detail. The sensitivity analysis results show (a) the cave storage flow regime exhibits an obvious unit-slope-line on pressure derivative curve, at the time the skin transient flow constitutes a V-shape characteristic. (b) The number of fracture-cave branches can be directly obtained by counting the number of V-shaped appearances on the pressure derivative curve. (c) The fluid compressibility effect leads to an upward trend on the pressure and its derivative, reservoir engineers should be cautious to explain that characteristic as a closed boundary effect. (d) The cave volume and cave position control the timing of the V-shape occurring. As the cave volume increases, the linear flow regime lasts longer and the V-shaped feature becomes apparent. With the cave distance and cave depth increasing, the V-shape characteristic comes later. This work can provide technical support for accurate characterization of multibranched fault-karst reservoirs, and give a type curve analysis method for rapidly diagnosing the spatial location of each karst cavity by analyzing bottom-hole pressure.
Movable fluid content and permeability are important reference factors for reservoir quality evaluation and recovery enhancement. In this study, based on multiple experimental results, 10 typical samples from a tight sandstone gas reservoir in the coal measure strata of the Shanxi Formation along the southeastern margin of the Ordos Basin were divided into three lithofacies to discuss the factors influencing movable fluid content and permeability. The results show that the fluid has a strong seepage capacity and a high degree of mobility in relatively large pore throats. The relatively large pores in the study area are secondary dissolved pores of various origins. High quartz and feldspar contents are conducive to the formation of secondary pores, while the presence of carbonate minerals and clay minerals play an inhibitory role. The pore throat size range of 0.05-0.1 mu m is the critical interval for the conversion of bound fluid to movable fluid. The movable fluid saturation and movable fluid porosity are affected by submicron-and micron-scale pore throats of >0.1 mu m, while the permeability is controlled by micron-scale pore throats sizes of >1 mu m. The volumetric proportion of the relatively large pore throats is influenced by the mineralogical composition of the rock, the size of the pore throats, and the degree of sorting, which further control the amount of moveable fluid and its percolation capacity. The highest movable fluid content and permeability appear in the massive gravel-bearing coarse to medium sandstone lithofacies (Lm) with a high proportion of submicron-and micron-scale pore throats, whereas the lowest occurs in parallel bedding or ripple laminations,medium to fine sandstone lithofacies (Lpr) with a high proportion of nano-scale pore throats. The lithofacies with cross bedding and medium sandstone (Lc) is also dominated by nano-scale pore throats, which shows the characteristics of low movable fluid content and medium permeability due to the retention of some micron-scale pore throats. This study describes the mobility of fluids with different pore throat sizes in detail and determines the pore throat size range corresponding to the transition from bound fluid to movable fluid, which can provide a reference for the evaluation of movable fluid seepage in other regions.
The occurrence characteristics of shale oil have a significant impact on its mobility and the ultimate oil recovery. How to quantitatively characterize the occurrence and distribution characteristics of shale oil is a challenging task. Accordingly, the laser scanning confocal microscopy (LSCM) combined with saturated oil experiment is used to quantitatively characterize the pseudo in-situ occurrence characteristics of light and heavy components of shale oil in sub-micron scale in Fengcheng Formation of Mahu Sag. Furthermore, the main controlling factors of light and heavy components' occurrence characteristics are comprehensively investigated in this study. The results show that: (1) Shale wettability significantly affects the occurrence state of shale oil. The heavy components are prone to exist on the surface of oil-wet minerals and organic matter of shale compared with light components. (2) Shale oil is relatively rich in bright laminas and the content of light components is higher in contrast to dark laminas. (3) The temperature has a greater impact on the heavy components and pressure has a multistage impact on the occurrence state of shale oil. The microscopic preferential fluid occurrence index, Δ∅H−L, is proposed to interpret the microscopic occurrence mechanism of the light and heavy components under different pressure conditions, which provides a new perspective on the shale oil occurrence mechanism. (4) Shale oil is not easy to be enriched in dolomitic lumps and alkaline minerals due to their low pore development level. Overall, the outcomes of this study are of great significance to the understanding of shale oil enrichment mechanism.
Oil and gas exploration increasingly requires high-resolution imaging of small, irregularly shaped, and highly heterogeneous well-side complex and abnormal geo-bodies. Conventional borehole acoustic imaging is often unable to accurately obtain the position and azimuth of small-scale abnormal geo-bodies. This study presents an inversion method that uses scattered waves for borehole 3D acoustic imaging and an implementation scheme that combines plane and spherical scanning imaging. The finite-difference time-domain method was used to simulate the acoustic fields for borehole azimuthal acoustic imaging of one and two caves next to a well. The proposed inversion method of 3D spatial scanning based on multi-mode wave information was validated through numerical simulations investigating the effect of different parameters on the imaging results. The simulation results show that the cave-scattered waves include the PP-, PS-, SP-, and SS-waves. When plane scanning imaging is performed based on a single wave mode, the other wave modes become interference factors. After the weighted processing of the PP-, PS-, SP-, and SS-waves, plane scanning imaging based on multi-mode scattered acoustic waves is shown to weaken pseudo-solutions, enhance the signal-to-noise ratio, and improve the radial and axial positioning accuracy of scatterers. When the scatterer is close to the borehole axis, the echo received by the receiver is not a real plane wave. In contrast with the 3D slowness time coherence (STC) and beamforming methods, spherical scanning imaging based on single-mode scattered acoustic waves completely considers this fact, which improves its azimuth positioning accuracy. Furthermore, spherical scanning imaging based on multi-mode scattered acoustic waves accurately estimates the azimuth of caves beside a well with a high imaging resolution. Finally, numerical simulation results were validated using the field measurement data of a well, and the actual imaging effect of the new method was tested. Therefore, rather than using single-mode reflected waves with limited information, the proposed method of scanning imaging using scattered acoustic waves can substantially improve the imaging resolution and positioning accuracy of small-scale abnormal geo-bodies beside a well and enhance the detection range.
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 at-mospheric 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 degrees), and stronger oil-displacing effect. Under a reservoir pressure of 20 MPa, the surfactant had lower re-covery 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.
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.
