查看更多>>摘要：Gas driving water can decrease the gas-phase effective permeability at the displacement front and block the coalbed methane (CBM) output during CO2-ECBM. However, for low-permeability coal reservoirs, there remain a lack of systematic and in-depth understandings of the inhibition process and quantification. In this work, based on a numerical model of an exploited low permeable coal reservoir, the impact of the injection rate and time on CO2-ECBM was investigated. The CH4 output inhibition mechanism in poorly permeable reservoirs was revealed, the inhibition process was quantified for the first time, and the influence of injection-drainage elements on the process was examined. Eventually, specific findings were confirmed in a field trial. The results demonstrated that (1) CO2 injected into the exploited reservoir could further enhance the CH4 output. The CH4 output rate significantly increased with increasing injection rate and time. (21 For poorly permeable reservoirs, the inhibition effect became more notable because a water-rich bank seemed to be a barrier, which trapped the injected and displaced gas, and free water contained in such media cannot be drained efficiently in a relatively short period. Conversely, it was the barrier that shielded the efficient CO2 storage. The storage efficiency reached as high as 99.9%. (3) The effect was only manifested at a specific stage, and the inhibition duration (T_I) and inhibition level (Dj) could be considered to characterize the effect. Increasing the injection rate, enhancing the bottom-hole pressure (BHP) drop, and prolonging the injection duration could promote fluid migration (especially fracture water) and further mitigate the effect, with the former two better than the latter one. (4) The hypothesis of homogeneous permeable reservoirs might result in an overestimate of the inhibition duration and inhibition level. A field trial confirmed the existence of the staged inhibition effect, with the inhibition time of three months and the inhibition level of roughly 5%. These findings pave the way to study the complex fluid migration for CO2-ECBM.
查看更多>>摘要：Field development studies require the knowledge of well clustering. In this paper, a novel automatic well clustering approach is proposed. This approach can be applied to recognize effective well clusters and extract strong rules among reservoir data. The proposed procedure combines a classical clustering algorithm with the genetic algorithm (GA) or the particle swarm optimization (PSO) algorithm. This modified algorithm is used to improve the stability criteria and also to reduce the dependency of final results on the initialization criteria. The results indicate that PSO is much faster than GA in both the initialization and convergence steps; therefore, the PSO algorithm is implemented for the clustering study. The production history of 24 wells of an oil reservoir is investigated, and the type of decline curve is determined. Subsequently, the modified algorithm is implemented to classify production wells. In the end, the Apriori algorithm, as an associate rule mining procedure, is applied to discover and present frequent patterns based on support, confidence, and lift factors and extract important rules among wells. Overall, we proposed a novel approach for well clustering. The proposed procedure, which leads to high stability in results, is a proper alternative for conventional supervised or unsupervised well clustering methods. The proposed procedure is beneficial to obtain reliable results for reservoir management studies.
查看更多>>摘要：A small concentration of organic acid in carbon dioxide (CO2) storage formations and caprocks could significantly alter the wettability of such formations into less water-wet conditions, decreasing the CO2-storage potentlal and containment security. Recent studies have attempted to infer the influence of the organic acid concentration on the wettability of rock-CO2-brine systems by measuring advancing and receding contact at gles. However, no studies have investigated the influence of organic acid contamination on CO2-storage capacifies from rock-fluid interfacial tension (IFT) data because solid-brine and solid-CO2 IFT values cannot be experimentally measured. Equilibrium contact angles and rock-fluid IFT datasets were used to evaluate the viability of CO2 storage in storage rocks and caprocks. First, the contact angles of rock in brine-CO2 systems ware measured to compute Young's equilibrium contact angles. Subsequently, rock-brine and rock-gas IFT values at CO2 geo-storage conditions were computed via a modified form of Neumann's equation of state. For two storage-rock minerals (quartz and calcite) and one caprock mineral (mica), the results demonstrated high CO2-brine equilibrium contact angles at high pressure (0.1-25 MPa) and increasing concentrations of stearic acid (10~(-5) to 10~(-2) mol/L). Rock-brine IFT increased with the increased stearic acid concentration but remained constant with increased pressure. In all conditions, the order of increasing hydrophobicity of the mineral surfaces is calcite > mica > quartz. At 323 K, 25 MPa, and a stearic acid concentration of 10~(-2) mol/L, quartz became intermediate-wet with a CO2-brine equilibrium contact angle of 89.8°, whereas mica and calcite became CO2-wet with CO2-brine equilibrium contact angles of 117.5° and 136.5°, respectively. This work provides insight into the effects of organic acids inherent in CO2 geo-storage formations and caprocks on rock wettability and rock-fluid interfacial interactions.
查看更多>>摘要：The selection of miscible or immiscible injection methods depends on the desired thermodynamic and operating conditions. However, gas injection alone does not increase reservoir replacement for various reasons. The reason for this is the greater mobility of gas than oil and gravitational separation. These reasons cause the injected gas to not have a favorable effect on the reduction of residual oil and causes early breakthroughs. To solve this problem, the researchers changed the method of gas injection, in which different methods such as continuous water and gas injection, foam gas injection and water and gas combination injection were proposed. The use of a combination of carbon dioxide and produced water is due to the higher solubility of this gas in water than other gases in nature and, the lower miscibility pressure. Also, the availability of this gas and the effective environmental effect of using this gas, has caused the research conducted to dissolve gas in water on the issue of combining carbon dioxide with added water. In this article, we will review the research on carbonated water injection as an enhanced oil recovery; provide challenges, solutions, and determining suitable conditions for injection. Also the number of studies conducted in recent years and important topics are mentioned.
查看更多>>摘要：Polymer flooding improves the mobility ratio by mainly increasing the injected water viscosity. Typically, these projects minimize the volume of polymer due to economic aspects since the polymer cost significantly affects operation expenditures. However, the injection of a single slug sometimes produces an abrupt viscosity transition at the slug tail, and the chase water forms fingers that can bypass the slug, destroying its integrity. Injecting gradually more dilute slugs mitigates viscous fingering and reduces polymer mass. The scarce field applications, scarce testing at laboratory scale, and the absence of simulations discussion drove the interest in the subject. This study implements and evaluates a numerical simulation by integrating laboratory scale data - bulk rheology, single- and two-phase core floodings - and then history matching graded viscosity core flooding. The results were compared using performance indicators and validated with three laboratory experiments from the literature. The experiments consist of one continuous injection core flood and two core floods using grading viscosity with similar polymer injected mass, one with two slugs and another with three polymer slugs. Experimental and simulated history data for oil recovery and cumulative water matched with less than 5% of normalized error. Events such as water and polymer breakthroughs were well represented. The performance indicators revealed the three slugs test showed the best polymer utility factor for oil/water and best injectivity. On the other hand, the two slugs test reached higher final incremental oil recovery. This work contributes to data integration and extended discussions necessary to enable tailoring and motivating applications of polymer viscosity grading, to save polymer mass and reduce the produced water.
查看更多>>摘要：Understanding fluid mobility during spontaneous imbibition (SI) and flooding is important for the enhancement of oil recovery. Many researches on SI, water flooding (WF), and N2 flooding (NF) have been published, but an indepth understanding of the oil mobility at the pore scale is still inadequate in low-permeability reservoirs. To solve this problem, SI, WF, and NF experiments were performed on the low-permeability conglomerates of the Baikouquan Formation and the Urho Formation in the Mahu Sag. Moreover, online NMR was introduced to monitor the oil volume in pores with different sizes in real-time. Considering the wettability, mineral compositions, and pore structure, we established a schematic diagram to reveal the fluid mobility mechanism. The results show that the micropores in the low-permeability conglomerates are more hydrophilic, whereas the other pores are more lipophilic. During SI, the movable oil is mainly distributed in the micropores in the form of clay-bound oil (CBO), which is discharged from the rock through the meso/macropores. High hydrophilicity contributes to a high imbibition rate and oil recovery from SI, while the pore structure only affects the imbibidon rate. During WF, the movable oil is contributed by CBO in the micropores and free oil (FO) in the pores controlled by throats >0.3 μm. During NF, the movable oil is mainly distributed in the pores controlled by > 0.1 μm throats, existing as FO and part capillary-bound oil (CAO). The results demonstrate that NF is effective to enhance the oil recovery of tight reservoirs, while WF is only effective for tight reservoirs with better pore structure (high V_r > 0.3 μm).
查看更多>>摘要：The injection of low-salinity water into carbonate oil-reservoirs has been the subject of much interest as a potential method to enhance oil recovery (EOR). Low salinity water injection has been shown to alter the geochemical equilibrium in the reservoir, and consequentially potentially change the surface wettability of the reservoir rocks. Nevertheless, the geochemical reaction pathways during low salinity water flooding in carbonates remain poorly understood. In order to provide a more comprehensive insight into the geochemical reaction pathways, a series of batch and core-flooding experiments have been performed at 70 °C. The experiments made use of analogous and authentic reservoir material from the Danish North Sea oil reservoirs, and brines with chemical composition similar to the formation water and injection water available in offshore flooding operations. Results show that both mineral dissolution and the precipitation of new secondary phases can accurately describe the geochemical changes observed in the experimental effluents during the course of a low-salinity water core-flooding scenario. The dissolution of amorphous silica (SiO2) present in the chalk, and the precipitation of a Mg-Si clay mineral, identified here as sepiolite, are key reactions that take place during low-salinity water core-flooding in chalks. The suggested geochemical pathway was successfully fitted by a simplified geochemical simulation which can accurately describe the experimental observations. Surface reactions which take place during modified-salinity water flooding were put into perspective by quantifying their contribution to the overall effluent composition.
查看更多>>摘要：The current study investigates the synergistic/antagonistic effect of cationic (octyl pyridinium chloride [C8Py] [Cl]), anionic (sodium lauryl sulfate (SLS)), and nonionic (octyl phenol ethoxylate (Triton-X100)) surfactants on the interfacial tension (IFT) reduction. The performance of the mixture of surfactants in the presence of different electrolytes on the IFT values of five crude oil samples are evaluated. To better understand the molecular interaction between surfactant solutions and oil samples, the important parameters such as °API, total acid and base numbers, asphaltene and resin weight percent, resin to asphaltene ratio, weight percent of oxygen, nitrogen and sulfur elements, and aromaticity of asphaltene and resin fractions are thoroughly examined. It is found that the synergistic effect between crude oil and surfactant solutions depends on the crude oil and surfactant types and salinity of brine. In this way, the mixture of anionic-cationic had the best results with an IFT value lower 0.1 mN/m. Although no specific trend was observed for the effect of oil type on the IFT of mixtures, the results showed that the ionic strength and surfactant type had a more dominant effect than the oil type. The mechanisms of IFT reduction for each binary mixture are also thoroughly discussed.
Ranel I. GaleevBoris V. SakharovNailia M. Khasanova
13页
查看更多>>摘要：In the oil industry, there is a need for fast and non-invasive methods for determining the bitumen content and group composition in rock samples. Determination of bitumen saturation of reservoir or source rocks has some difficulties due to existing methods limitations. For this purpose, the novel method is based on a combination of free induction decay (FID) and modified Carr-Purcell-Meilboom-Gill (CPMG) measurements using a low-frequency nuclear magnetic resonance (NMR) relaxation technique was developed. It allows obtaining the content and group composition (SARA fractions) of bitumen directly in the porous media without extraction. FID data fitting based on a combination of Voigt and exponential functions for liquid phase, as well as Abragam and exponential functions for solid phase components respectively was proposed. The developed method was tested on 20 rock samples collected from the productive formation (horizon M) located at the depth of 601-708 m of the wellbore 3001 of the Boca de Jaruco oilfield (Republic of Cuba). The bitumen content in the samples was obtained and compared with data determined by thermogravimetric analysis (TGA) and Rock-Eval pyrolysis. A good agreement of NMR results with TGA and pyrolysis was shown (R~2 = 0.99 and 0.97 respectively). The values of liquid HC components (saturates, aromatics and resins) and solid HC components (asphaltenes) were compared with TGA data (R~2 = 0.97 and 0.98 respectively). Finally, the proposed NMR method was applied to determine the SARA composition of the bitumen in the samples. To assess the accuracy of determining the SARA composition by the NMR method, SARA analysis (ASTM D4124-09) of extracts from the samples 632, 638, 658, 676, 689, 708 was carried out. NMR and conventional SARA analysis showed close results. To assess the completeness of the bitumen extraction from the mineral matrix, microCT and FIB-SEM were performed before and after extraction. It was found that after extraction the part of the bitumen remains in the pores, which distorts the results of SARA analysis. The proposed NMR method can be used to calculate the bitumen saturation and SARA composition for characterization of bitumen, selecting and modeling the effectiveness of applying the optimal EOR without destroying the samples. Also, the method is promising for the operational control of technological processes of oil production.
Kwang Hoon BaekMingyan LiuFrancisco J. Arguelles-Vivas
13页
查看更多>>摘要：This paper presents an experimental study of low-tension polymer (LTP) flooding with a short-hydrophobe surfactant as a sole additive. Such a simple surfactant makes low-tension displacement fronts in polymer flooding (e.g., 10~(-2) mN/m) without involving micro-emulsions of ultra-low interfacial tension (IFT). The envisioned application of LTP flooding is to enhance the displacement of a continuous oil phase with such a moderate reduction in IFT as an effective improvement of polymer flooding. In our previous research, 2-ethylhexanol-7PO-15EO (2-EH-7PO-15EO) was selected as an optimal short-hydrophobe surfactant that resulted in the lowest TFT between polymer solution and oil, and achieved the greatest final oil recovery. However, this paper presents the effect of surfactant partition coefficients on the LTP flooding as an additional important factor for surfactant optimization. A series of LTP floods showed that the IFT primarily affected the final oil recovery when the sandpack was swept sufficiently by LTP. Comparison of two cases with similar IFT values (2-EH-4PO-15EO and 2-EH-7PO-25EO) showed that the surfactant partition coefficient affected the oil recovery through its impact on the surfactant in-situ propagation. The case with 2-EH-7PO-25EO resulted in a greater oil recovery because the surfactant propagated more efficiently with a smaller partition coefficient than 2-EH-4PO-15EO. Results collectively showed that optimization of 2-EH-xPO-yEO for LTP flooding involves two competing factors. One is to minimize the water/oil IFT for increasing the local oil displacement efficiency, and the other is to minimize the partition coefficient for more efficient in-situ propagation of the surfactant. It is critical to take a balance between these two factors for the surfactant used for LTP flooding. The importance of the surfactant partition coefficient became more obvious when a limited amount of surfactant was injected.
NSTL