Analysis of the effect of residual oil on particle trapping during produced water reinjection using X-ray tomography

2009 ◽  
Author(s):  
Alok Saraf ◽  
Bert-Rik de Zwart ◽  
Peter K. Currie ◽  
Mohammad A.J. Ali
SPE Journal ◽  
2010 ◽  
Vol 15 (04) ◽  
pp. 943-951 ◽  
Author(s):  
A.. Saraf ◽  
A.H. de Zwart ◽  
Peter K. Currie ◽  
Mohammad A.J. Ali

Summary Recently, it has been shown that the presence of residual oil in a formation can have a considerable influence on the trapping mechanisms for particles present in reinjected produced water (Ali 2007; Ali et al. 2005, 2007, 2009). This article reports on a further set of extensive coreflow experiments that confirm and extend these results. The tests were conducted in a computerized-tomography (CT) scanner, allowing direct observation of the buildup of particle deposition along the core. These experiments are relevant to operational issues associated with produced-water reinjection (PWRI). In many cases, produced water is injected into formations containing oil, so reduced oil saturation is achieved rapidly in the area around the well. Even if the well is outside the oil zone, trapped oil droplets are always present in produced water, and a residual-oil zone will gradually build up around the well. Major differences are found between the deposition profiles for fully water-saturated cores and the cores having residual-oil saturation. In particular, particles penetrate deeper into the core with residual-oil saturation, and considerably more particles pass completely through the core without being trapped. The X-ray technique allows direct observation during the experiment of the deposition process inside the core, eliminating the complicating effect of any external filter cake. As a result, an analysis can be performed of the deposition parameters relevant inside the core using deep-bed-filtration theory, and the results of this analysis are presented. In particular, it is shown that the values of the filtration function determined from the CT-scan (X-ray) data are consistent with those obtained from analysis of the effluent concentration. Moreover, both methods of analysis find quite clearly that the filtration coefficient increases with decreasing flow rate. The results indicate that formation damage near a wellbore during water injection will be reduced by the presence of residual oil, and that particles will penetrate deeper into the formation. The result is also relevant to injection under fracturing conditions because particle deposition in the wall of the fracture (where residual oil may be present) is one of the mechanisms governing fracture growth.


Talanta ◽  
2008 ◽  
Vol 74 (5) ◽  
pp. 1231-1235 ◽  
Author(s):  
P.M. Pimentel ◽  
M.J. Anjos ◽  
D.M.A. Melo ◽  
M.A.F. Melo ◽  
L.M. Gonçalves Jr. ◽  
...  

Author(s):  
Raymond Kuriger ◽  
David Young ◽  
Malcolm Mackenzie ◽  
Hamid Sarv ◽  
Jason Trembly

Scale buildup on water-side heat transfer surfaces poses a potential operating challenge for steam-assisted gravity drainage (SAGD) boilers used in the production of bitumen since produced water, which has a high dissolved solid content, is recycled. Scale from deposition of dissolved solids on boiler tubes acts as a thermal insulating layer, decreasing heat transfer and lowering boiler efficiency. Understanding scale deposit composition on heat transfer surfaces is beneficial in the determination of adequate boiler maintenance practices and operating parameters. This research determined the effect of feedwater pH (7.5, 9.0, and 10.0) on scale composition resulting from deposition of dissolved solids under commercially relevant boiler operating conditions at 8.96 MPa (1300 psig) and 37.86 kW/m2 (12,000 Btu/h ft2). Scale deposits were analytically investigated using scanning electron microscopy coupled with energy dispersive X-ray spectroscopy (SEM/EDS), powder X-ray diffraction (XRD), and Raman spectroscopy. At feedwater pH values of 7.5 and 9.0, anhydrite (CaSO4), xonotlite (Ca6Si6O17(OH)2), and pectolite (NaCa2Si3O8(OH)) were detected. At the pH of 10.0, xonotlite and pectolite were identified in the absence of anhydrite. Furthermore, the magnesium silicate phase, serpentine (Mg3Si2O5(OH)4), was also postulated to be present.


2006 ◽  
Author(s):  
A.S.L. Vaz ◽  
Pavel G. Bedrikovetsky ◽  
Claudio Jose Alves Furtado ◽  
Alexandre Guedes Siqueira ◽  
Antonio Luiz Serra de Souza
Keyword(s):  

2021 ◽  
Author(s):  
Jawaher Almorihil ◽  
Aurélie Mouret ◽  
Isabelle Hénaut ◽  
Vincent Mirallès ◽  
Abdulkareem AlSofi

Abstract Gravity settling represents the main oil-water separation mechanism. Many separation plants rely only on gravity settling with the aid of demulsifiers (direct or reverse breakers) and other chemicals such as water clarifiers if they are required. Yet, other complementary separation methods exist including filtration, flotation, and centrifugation. In terms of results and more specifically with respect to the separated produced-water, the main threshold on its quality is the dispersed oil content. Even with zero discharge and reinjection into hydrocarbon formations, the presence of residual oil in the aqueous phase represents a concern. High oil content results into formation damage and losses in injectivity which necessitates formation stimulations and hence additional operational expenses. In this work, we investigated the effects of different separation techniques on separated water quality. In addition, we studied the impact of enhanced oil recovery (EOR) chemicals on the different separation techniques in terms of efficiency and water quality. Based on the results, we identified potential improvements to the existing separation process. We used synthetic well-characterized emulsions. The emulsions were prepared at the forecast water: oil ratio using dead crude oil and synthetic representative brines with or without the EOR chemicals. To clearly delineate and distinguish the effectiveness of different separation methods, we exacerbated the conditions by preparing very tight emulsions compared with what is observed on site. With that, we investigated three separation techniques: gravity settling, centrifugation, and filtration. First, we used Jar Tests to study gravity settling, then a benchtop centrifuge at two speeds to evaluate centrifugation potential. Finally, for filtration, we tested two options: membrane and deep-bed filtrations. Concerning the water quality, we performed solvent extraction followed by UV analyses to measure the residual oil content as well as light transmission measurements in order to compare the efficiency of different separation methods. The results of analyses suggest that gravity settling was not efficient in removing oil droplets from water. No separation occurred after 20 minutes in every tested condition. However, note that investigated conditions were severe, tighter emulsions are more difficult to separate compared to those currently observed in the actual separation plant. On the other hand, centrifugation significantly improved light transmission through the separated water. Accordingly, we can conclude that the water quality was largely improved by centrifugation even in the presence of EOR chemicals. In terms of filtration, very good water quality was obtained after membrane filtration. However, significant fouling was observed. In the presence of EOR chemicals, filtration lost its effectiveness due to the low interfacial tension with surfactants and water quality became poor. With deep-bed filtration, produced water quality remained good and fouling was no longer observed. However, the benefits from media filtration were annihilated by the presence of EOR chemicals. Based on these results and at least for our case study, we conclude that centrifugation and deep-bed filtration techniques can significantly improve quality of the separated and eventually reinjected water. In terms of the effects of EOR chemicals, the performance of centrifugation is reduced while filtrations are largely impaired by the presence of EOR chemicals. Thereby, integration of any of the two methods in the separation plant will lead to more efficient produced-water reinjection, eliminating formation damage and frequent stimulations. Yet, it is important to note that economics should be further assessed.


2019 ◽  
Vol 10 (4) ◽  
pp. 1591-1601 ◽  
Author(s):  
Kalpajit Hazarika ◽  
Subrata Borgohain Gogoi

Abstract The effect of alkali on immiscible alkali–surfactant (AS) flooding is studied by injecting surfactant individually and surfactant along with alkali. First, reservoir core samples were characterized with the help of X-ray diffraction (XRD), scanning electron microscope (SEM) and thin slide analysis. Based on the clay content of the reservoir, surfactant was selected. Second, AS formulations were designed through dynamic interfacial tension (IFT) and wettability alteration analysis. Third, adsorption of surfactant on porous media was studied with or without alkali to find out the amount of surfactant adsorbed along with the isotherm mechanism. Fourth, core flooding experiments were conducted to find out the recovery efficiency after secondary brine flooding. XRD, SEM and thin slide analysis showed the presence of kaolinite, smectite, illite, silica, quartz in the rock sample. Based on the clay types, sodium dodecyl sulfate (SDS) was selected as surfactant for this study. Ultra-low dynamic IFT in the range of 10−3 was observed with SDS. Addition of alkali further reduced the IFT of the system. Initially, wettability of the reservoir under study was toward water wet, but during AS flooding it was altered to strongly water wet. Adsorption of surfactant on the porous media was reduced by the application of alkali. During secondary brine flooding, maximum recovery was found to be 49% of Initial Oil in Place. Another 14% of residual oil after secondary flooding was achieved by AS flooding.


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