Laboratory Investigation of the Impact of Injection-Water Salinity and Ionic Content on Oil Recovery From Carbonate Reservoirs

2011 ◽  
Vol 14 (05) ◽  
pp. 578-593 ◽  
Author(s):  
Ali A. Yousef ◽  
Salah Hamad Al-Saleh ◽  
Abdulaziz Al-Kaabi ◽  
Mohammed Saleh Al-Jawfi
Keyword(s):  
Laboratory Investigation ◽  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Water Salinity ◽  
Ionic Content ◽  
Injection Water ◽  
The Impact

An experimental study for carbonate reservoirs on the impact of CO2-EOR on petrophysics and oil recovery

Fuel ◽  
2019 ◽  
Vol 235 ◽  
pp. 1019-1038 ◽  
Author(s):  
Mohamed Khather ◽  
Ali Saeedi ◽  
Matthew B. Myers ◽  
Michael Verrall
Keyword(s):  
Experimental Study ◽  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Co2 Eor ◽  
The Impact

scholarly journals Oil recovery for fractured-vuggy carbonate reservoirs by cyclic water huff and puff: performance analysis and prediction

2019 ◽  
Vol 9 (1) ◽  
Author(s):  
Daigang Wang ◽  
Jingjing Sun
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
High Efficiency ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Production Performance ◽  
Quantitative Prediction ◽  
Attractive Alternative ◽  
Marquardt Algorithm ◽  
The Impact

Abstract Cyclic water huff and puff (CWHP) has proven to be an attractive alternative to improve oil production performance after depletion-drive recovery in fractured-vuggy carbonate reservoirs. However, due to the impact of strong heterogeneity, multiple types of fractured-vuggy medium, poor connectivity, complex flow behaviors and oil-water relationship, CWHP is merely suitable for specific types of natural fractured-vuggy medium, usually causing a great difference in actual oil-yielding effect. It remains a great challenge for accurate evaluation of CWHP adaptability and quantitative prediction of production performance in fractured-vuggy carbonate reservoir, which severely restricts the application of CWHP. For this study, we firstly enable the newly developed fuzzy grey relational analysis to quantify the adaptability of CWHP. With production history of several targeted producers, the accuracy of the proposed method is validated. Based on the traditional percolation theory and waterflood mechanisms in various types of fractured-vuggy medium, a quantitative prediction model for cyclic water cut fwp and increased recovery factor ΔR is presented. The CWHP production performance is discussed by using the Levenberg-Marquardt algorithm for history matching. With a better understanding of the fwp ~ ΔR curve characteristics in different types of fractured-vuggy medium, proper strategies or measures for potential-tapping remaining oil are provided. This methodology can also offer a good basis for engineers and geologists to develop other similar reservoirs with high efficiency.

Successful in the Lab, Not as Effective in the Field? Uncertainties in the Field Observations of Low Salinity Water Flooding in Sandstone and Carbonate Reservoirs-A Critical Analysis

2021 ◽  
Author(s):  
Navpreet Singh ◽  
Hemanta Kumar Sarma
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Experimental Studies ◽  
Carbonate Reservoirs ◽  
Water Flooding ◽  
Water Salinity ◽  
Field Scale ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water

Abstract Low salinity waterflooding has been an area of great interest for researchers for almost over three decades for its perceived "simplicity," cost-effectiveness, and the potential benefits it offers over the other enhanced oil recovery (EOR) techniques. There have been numerous laboratory studies to study the effect of injection water salinity on oil recovery, but there are only a few cases reported worldwide where low salinity water flooding (LSW) has been implemented on a field scale. In this paper, we have summarized the results of our analyses for some of those successful field cases for both sandstone and carbonate reservoirs. Most field cases of LSW worldwide are in sandstone reservoirs. Although there have been a lot of experimental studies on the effect of water salinity on recovery in carbonate reservoirs, only a few cases of field-scale implementation have been reported for the LSW in carbonate reservoirs. The incremental improvement expected from the LSW depends on various factors like the brine composition (injection and formation water), oil composition, pressure, temperature, and rock mineralogy. Therefore, all these factors should be considered, together with some specially designed fit-for-purpose experimental studies need to be performed before implementing the LSW on a field scale. The evidence of the positive effect of LSW at the field scale has mostly been observed from near well-bore well tests and inter-well tests. However, there are a few cases such Powder River Basin in the USA and Bastrykskoye field in Russia, where the operators had unintentionally injected less saline water in the past and were pleasantly surprised when the analyses of the historical data seemed to attribute the enhanced oil recovery due to the lower salinity of the injected water. We have critically analyzed all the major field cases of LSW. Our paper highlights some of the key factors that worked well in the field, which showed a positive impact of LSW and a comparative assessment of the incremental recovery realized from the reservoir visa-a-vis the expectations generated from the laboratory-based experimental studies. It is envisaged that such a comparison could be more meaningful and reliable. Also, it identifies the likely uncertainties (and their sources) associated during the field implementation of LSW.

Sequential Coupling of Geochemical Reactions With Reservoir Simulations for Waterflood and EOR Studies

SPE Journal ◽  
2012 ◽  
Vol 17 (02) ◽  
pp. 469-484 ◽  
Author(s):  
Lingli Wei
Keyword(s):  
Water Chemistry ◽  
Oil Recovery ◽  
Reactive Transport ◽  
Produced Water ◽  
Mineral Dissolution ◽  
Individual Species ◽  
Chemical Changes ◽  
Injection Water ◽  
Geochemical Reactions ◽  
The Impact

Summary Many waterflood projects now experience significant amounts of water cut, with more water than hydrocarbon flowing between the injectors and producers. In addition to the impact on water viscosity and density that results from using different injection-water sources during a field's life, water chemistry itself may impact oil recovery, as demonstrated by recent research on low-salinity water-injection schemes. It is also known that water chemistry has a profound impact on various chemical enhanced-oil-recovery (EOR) processes. Moreover, the effectiveness and viability of such EOR schemes is strongly dependent on reservoir-brine and injection-water compositions. In particular, the presence of divalent cations such as Ca+2 and Mg+2 has a significantly adverse effect for chemical EORs. Using new developments in reservoir simulation, this paper outlines a method to couple geochemical reactions in a reservoir simulator in black-oil and compositional modes suitable for large-scale reservoir models for waterflood and EOR studies. The new multicomponent reactive-transport modeling capability considers chemical reactions triggered by injection water and/or injected reactive gases such as CO2 and H2S, including mineral dissolution and precipitation, cation exchange, and surface complexation. For waterflood-performance assessment, the new modeling capability makes possible a more-optimum evaluation of petrophysical logs for well intervals where injection-water invasion is suspected. By modeling transport of individual species in the aqueous phase from injectors to producers, reservoir characterization can also be improved through the use of these natural tracers, provided that the compositions of the actual produced water are used in the history matching. The simulated water compositions in producers can also be used by production chemists to assess scaling and corrosion risks. For CO2 EOR studies, we illustrate chemical changes inside a reservoir and in the produced water before and after CO2 breakthrough, and discuss geochemical monitoring as a potential surveillance tool. Alkaline-flood-induced water chemical changes and calcite precipitation are also presented to illustrate applicability for chemical EOR with the new simulation capability.

Could Atomic-Force Microscopy Force Mapping Be a Fast Alternative to Core-Plug Tests for Optimizing Injection-Water Salinity for Enhanced Oil Recovery in Sandstone?

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 0720-0729 ◽  
Author(s):  
T.. Hassenkam ◽  
M. P. Andersson ◽  
E.. Hilner ◽  
J.. Matthiesen ◽  
S.. Dobberschütz ◽  
...  
Keyword(s):  
Atomic Force Microscopy ◽  
Double Layer ◽  
Oil Recovery ◽  
Water Salinity ◽  
Core Material ◽  
Force Microscopy ◽  
Low Salinity ◽  
Atomic Force ◽  
Force Mapping ◽  
Injection Water

Summary Core tests demonstrated that decreasing the salinity of injection water can increase oil recovery. Optimizing injection-water salinity, however, would offer a clear economic advantage for several reasons. Too-low salinity risks swelling of the clays that would lead to permanent reservoir damage, but evidence of effectiveness with moderate-salinity solutions would make it less difficult to dispose of produced water. The goal is to define boundary conditions so injection-water salinity is high enough to prevent reservoir damage and low enough to induce the low-salinity (LS) effect, while keeping costs and operational requirements at a minimum. Traditional core-plug testing for optimizing conditions has some limitations. Each test requires a fresh sample; core-testing requires sophisticated and expensive equipment; and reliable core-test data require several months because cores must be cleaned, restored, and aged before the tests can begin. It is also difficult to compare data from one core with results from another because no two cores are identical, making it difficult to distinguish between effects resulting from different conditions and effects resulting from different cores. Gathering statistics is limited by the time required for each test and the fact that core material is in short supply. Thus, our aim was to explore the possibility of a less-expensive, faster alternative by probing the fundamental chemical mechanisms behind the LS effect. We developed a method that uses atomic-force microscopy (AFM) to investigate the relationship between the wettability of pore surfaces and water salinity. We functionalize AFM tips with organic molecules and use them to represent tiny oil droplets of nonpolar molecules, and we use sand grains removed from core plugs to represent the pore walls in sandstone. We bring our “oil”-wet tip close to the sand-grain surface and measure the work of adhesion between the tip and the surface. Repeated probing of the surface with the tip produces data that one can convert to maps of adhesion, and we can estimate contact angle. Adhesion work is proportional to wettability and is directly correlated with the salinity of the fluid in contact with the tip and the particle surface. From our measurements, the threshold values for the onset of the LS response are 5,000 to 8,000 ppm, which benchmark remarkably well with observations from core-plug tests. From a mechanistic perspective, the correlation between salinity and adhesion provides evidence for the role of electrical-double-layer (EDL) expansion in the LS response; expansion of the double layer decreases oil wettability. Because AFM experiments can be performed relatively quickly on very little material, they give the possibility of testing salinity response on many samples throughout a reservoir and for gathering statistics. Our approach provides a range of data that one can use to screen conditions to maximize the value of the core-plug testing and to provide extra data that would be too time consuming or too expensive to gather with traditional methods alone. Thus, AFM force mapping is an excellent complement to traditional core-plug testing.

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