Deepstar 11901: Subsea Low Salinity Injection Water for Increased Oil Recovery

2014 ◽  
Author(s):  
Stephane Anres ◽  
Thomas Delaplace ◽  
Graeme Skivington ◽  
Khalid Mateen ◽  
Greg Kusinski
Keyword(s):  
Oil Recovery ◽  
Low Salinity ◽  
Injection Water ◽  
Increased Oil Recovery

Interfacial Viscoelasticity of Crude Oil/Brine: An Alternative Enhanced-Oil-Recovery Mechanism in Smart Waterflooding

SPE Journal ◽  
2018 ◽  
Vol 23 (03) ◽  
pp. 803-818 ◽  
Author(s):  
Mehrnoosh Moradi Bidhendi ◽  
Griselda Garcia-Olvera ◽  
Brendon Morin ◽  
John S. Oakey ◽  
Vladimir Alvarado
Keyword(s):  
Crude Oil ◽  
Water Chemistry ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Interaction Mechanism ◽  
Field Trials ◽  
Wettability Alteration ◽  
Low Salinity ◽  
Injection Water

Summary Injection of water with a designed chemistry has been proposed as a novel enhanced-oil-recovery (EOR) method, commonly referred to as low-salinity (LS) or smart waterflooding, among other labels. The multiple names encompass a family of EOR methods that rely on modifying injection-water chemistry to increase oil recovery. Despite successful laboratory experiments and field trials, underlying EOR mechanisms remain controversial and poorly understood. At present, the vast majority of the proposed mechanisms rely on rock/fluid interactions. In this work, we propose an alternative fluid/fluid interaction mechanism (i.e., an increase in crude-oil/water interfacial viscoelasticity upon injection of designed brine as a suppressor of oil trapping by snap-off). A crude oil from Wyoming was selected for its known interfacial responsiveness to water chemistry. Brines were prepared with analytic-grade salts to test the effect of specific anions and cations. The brines’ ionic strengths were modified by dilution with deionized water to the desired salinity. A battery of experiments was performed to show a link between dynamic interfacial viscoelasticity and recovery. Experiments include double-wall ring interfacial rheometry, direct visualization on microfluidic devices, and coreflooding experiments in Berea sandstone cores. Interfacial rheological results show that interfacial viscoelasticity generally increases as brine salinity is decreased, regardless of which cations and anions are present in brine. However, the rate of elasticity buildup and the plateau value depend on specific ions available in solution. Snap-off analysis in a microfluidic device, consisting of a flow-focusing geometry, demonstrates that increased viscoelasticity suppresses interfacial pinch-off, and sustains a more continuous oil phase. This effect was examined in coreflooding experiments with sodium sulfate brines. Corefloods were designed to limit wettability alteration by maintaining a low temperature (25°C) and short aging times. Geochemical analysis provided information on in-situ water chemistry. Oil-recovery and pressure responses were shown to directly correlate with interfacial elasticity [i.e., recovery factor (RF) is consistently greater the larger the induced interfacial viscoelasticity for the system examined in this paper]. Our results demonstrate that a largely overlooked interfacial effect of engineered waterflooding can serve as an alternative and more complete explanation of LS or engineered waterflooding recovery. This new mechanism offers a direction to design water chemistry for optimized waterflooding recovery in engineered water-chemistry processes, and opens a new route to design EOR methods.

Enhancing Heavy-Oil-Recovery Efficiency by Combining Low-Salinity-Water and Polymer Flooding

SPE Journal ◽  
2020 ◽  
pp. 1-17
Author(s):  
Yang Zhao ◽  
Shize Yin ◽  
Randall S. Seright ◽  
Samson Ning ◽  
Yin Zhang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
High Salinity ◽  
Polymer Flooding ◽  
Heavy Oil Recovery ◽  
Sweep Efficiency ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Increased Oil Recovery

Summary Combining low-salinity-water (LSW) and polymer flooding was proposed to unlock the tremendous heavy-oil resources on the Alaska North Slope (ANS). The synergy of LSW and polymer flooding was demonstrated through coreflooding experiments at various conditions. The results indicate that the high-salinity polymer (HSP) (salinity = 27,500 ppm) requires nearly two-thirds more polymer than the low-salinity polymer (LSP) (salinity = 2,500 ppm) to achieve the target viscosity at the condition of this study. Additional oil was recovered from LSW flooding after extensive high-salinity-water (HSW) flooding [3 to 9% of original oil in place (OOIP)]. LSW flooding performed in secondary mode achieved higher recovery than that in tertiary mode. Also, the occurrence of water breakthrough can be delayed in the LSW flooding compared with the HSW flooding. Strikingly, after extensive LSW flooding and HSP flooding, incremental oil recovery (approximately 8% of OOIP) was still achieved by LSP flooding with the same viscosity as the HSP. The pH increase of the effluent during LSW/LSP flooding was significantly greater than that during HSW/HSP flooding, indicating the presence of the low-salinity effect (LSE). The residual-oil-saturation (Sor) reduction induced by the LSE in the area unswept during the LSW flooding (mainly smaller pores) would contribute to the increased oil recovery. LSP flooding performed directly after waterflooding recovered more incremental oil (approximately 10% of OOIP) compared with HSP flooding performed in the same scheme. Apart from the improved sweep efficiency by polymer, the low-salinity-induced Sor reduction also would contribute to the increased oil recovery by the LSP. A nearly 2-year pilot test in the Milne Point Field on the ANS has shown impressive success of the proposed hybrid enhanced-oil-recovery (EOR) process: water-cut reduction (70 to less than 15%), increasing oil rate, and no polymer breakthrough so far. This work has demonstrated the remarkable economical and technical benefits of combining LSW and polymer flooding in enhancing heavy-oil recovery.

scholarly journals Enhanced oil recovery efficiency of low-salinity water flooding in oil reservoirs including Fe2+ ions

2018 ◽  
Vol 37 (1) ◽  
pp. 355-374 ◽  
Author(s):  
Yeonkyeong Lee ◽  
Hyemin Park ◽  
Jeonghwan Lee ◽  
Wonmo Sung
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Water Flooding ◽  
Sulfate Ion ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Low Salinity Waterflooding ◽  
Injection Water ◽  
Salinity Water ◽  
Reservoir Simulator

The low-salinity waterflooding is an attractive eco-friendly producing method, recently, for carbonate reservoirs. When ferrous ion is present in the formation water, that is, acidic water, the injection of low-salinity water generally with neutral pH can yield precipitation or dissolution of Fe-minerals by pH mixing effect. FeSO4 and pyrite can be precipitated and re-dissolved, or vice versa, while siderite and Fe(OH)2 are insoluble which are precipitated, causing permeability reduction. Particularly, pyrite chemically reacts with low-salinity water and release sulfate ion, altering the wettability, favorably, to water-wet. In this aspect, we analyzed oil production focusing on dissolution of Fe-minerals and Fe-precipitation using a commercial compositional reservoir simulator. From the simulation results, the quantities of precipitation and dissolution were enormously large regardless of the type of Fe-minerals and there was almost no difference in terms of total volume in this system. However, among Fe-minerals, Fe(OH)2 precipitation and pyrite dissolution were noticeably large compared to troilite, FeSO4, and siderite. Therefore, it is essential to analyze precipitation or dissolution for each Fe-mineral, individually. Meanwhile, in dissolving process of pyrite, sulfate ions were released differently depending on the content of pyrite. Here, the magnitude of the generated sulfate ion was limited at certain level of pyrite content. Thus, it is necessary to pay attention for determining the concentration of sulfate ion in designing the composition of injection water. Ultimately, in the investigation of the efficiency of oil production, it was found that the oil production was enhanced due to an additional sulfate ion generated from FeS2 dissolution.

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.

Novel Insights into Mechanisms of Oil Recovery by Low Salinity Water Injection

2015 ◽  
Author(s):  
M. Sohrabi ◽  
P. Mahzari ◽  
S. A. Farzaneh ◽  
J. R. Mills ◽  
P. Tsolis ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

Continental-shelf freshwater water resources and improved oil recovery by low-salinity waterflooding

AAPG Bulletin ◽  
2017 ◽  
Vol 101 (01) ◽  
pp. 1-18 ◽  
Author(s):  
Mark Person ◽  
John L. Wilson ◽  
Norman Morrow ◽  
Vincent E.A. Post
Keyword(s):  
Water Resources ◽  
Continental Shelf ◽  
Oil Recovery ◽  
Improved Oil Recovery ◽  
Low Salinity ◽  
Low Salinity Waterflooding

A Numerical Investigation of Low Salinity Polymer Flooding Effects from a Geochemical Perspective

2021 ◽  
Author(s):  
Omar Chaabi ◽  
Emad W. Al-Shalabi ◽  
Waleed Alameri
Keyword(s):  
Aqueous Phase ◽  
Oil Recovery ◽  
Reactive Transport ◽  
History Matching ◽  
Solution Chemistry ◽  
Related Effect ◽  
Exchange Reactions ◽  
Two Phase ◽  
Low Salinity ◽  
Geochemical Reactions

Abstract Low salinity polymer (LSP) flooding is getting more attention due to its potential of enhancing both displacement and sweep efficiencies. Modeling LSP flooding is challenging due to the complicated physical processes and the sensitivity of polymers to brine salinity. In this study, a coupled numerical model has been implemented to allow investigating the polymer-brine-rock geochemical interactions associated with LSP flooding along with the flow dynamics. MRST was coupled with the geochemical software IPhreeqc. The effects of polymer were captured by considering Todd-Longstaff mixing model, inaccessible pore volume, permeability reduction, polymer adsorption as well as salinity and shear rate effects on polymer viscosity. Regarding geochemistry, the presence of polymer in the aqueous phase was considered by adding a new solution specie and related chemical reactions to PHREEQC database files. Thus, allowing for modeling the geochemical interactions related to the presence of polymer. Coupling the two simulators was successfully performed, verified, and validated through several case studies. The coupled MRST-IPhreeqc simulator allows for modeling a wide variety of geochemical reactions including aqueous, mineral precipitation/dissolution, and ion exchange reactions. Capturing these reactions allows for real time tracking of the aqueous phase salinity and its effect on polymer rheological properties. The coupled simulator was verified against PHREEQC for a realistic reactive transport scenario. Furthermore, the coupled simulator was validated through history matching a single-phase LSP coreflood from the literature. This paper provides an insight into the geochemical interactions between partially hydrolyzed polyacrylamide (HPAM) and aqueous solution chemistry (salinity and hardness), and their related effect on polymer viscosity. This work is also considered as a base for future two-phase polymer solution and oil interactions, and their related effect on oil recovery.

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