Subsea Sulfate Removal and Low Salinity Plant Membrane Life Prediction for IOR and EOR

2021 ◽  
Author(s):  
Ojonimi Samuel Haruna ◽  
Torbjørn Hegdal ◽  
Xiaofei Huang
Keyword(s):  
Oil Recovery ◽  
Life Prediction ◽  
Water Injection ◽  
Full Scale ◽  
Lessons Learned ◽  
Design Parameters ◽  
Permeate Flux ◽  
Low Salinity ◽  
Operation Conditions ◽  
Sulfate Removal

Abstract Subsea water treatment technology for water injection provides a solution for an optimized water injection strategy on both green and brownfield applications. There are no space and weight constraints on the seabed, which enables simple, flexible, and reliable designs. A full-scale sulfate removal and low salinity plant designed for seabed operation with minimum maintenance intervention has been in operation for ten months without any chemical cleans. This paper reviews the performance results used to predict the life and longevity of a subsea sulfate removal unit (SRU) for a field application in the North Sea. The ability to reliably predict the potential risks and serving life of a system is crucial for the success of subsea processing equipment. Results from a test conducted over ten months evaluated the key design parameters such as SRU membrane permeate flux, recovery rate, and analyzed membrane fouling behavior during the test period. Lessons learned from the testing are incorporated into the model for more accurate and reliable membrane life prediction. Field data was analyzed to extrapolate aging factors that are used in the membrane design projection software. The projection software simulated aging performance of the membrane over the membrane lifespan under subsea operation conditions, and the results were applied to determine operating philosophy, maintenance, and intervention interval for the subsea plant. Lessons learned from this field study were discussed and used as guidelines for the next phase full-scale design and practice. This novelty field practice establishes a break-through step towards full implementation of subsea seawater treatment and injection for increased oil recovery (IOR) and enhanced oil recovery (EOR) purposes. This firsthand data helps the operators to optimize the operation on the seabed, which minimizes the downtime and demonstrates promising advantages of CAPEX and OPEX saving in the long run.

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

scholarly journals Impact of Low Salinity Water Injection on CO2 Storage and Oil Recovery for Improved CO2 Utilization

2021 ◽  
Vol 229 ◽  
pp. 116127
Author(s):  
Krishna Raghav Chaturvedi ◽  
Durgesh Ravilla ◽  
Waquar Kaleem ◽  
Prashant Jadhawar ◽  
Tushar Sharma
Keyword(s):  
Oil Recovery ◽  
Co2 Storage ◽  
Water Injection ◽  
Co2 Utilization ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

Opportunity of Enhanced Oil Recovery Low Salinity Water Injection: From Experimental Work to Simulation Study up to Field Proposal

2013 ◽  
Author(s):  
Chiara Callegaro ◽  
Martin Bartosek ◽  
Franco Masserano ◽  
Marianna Nobili ◽  
Valerio Parasiliti Parasiliti Parracello ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Simulation Study ◽  
Experimental Work ◽  
Water Injection ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

scholarly journals Enhanced Wettability Modification and CO2 Solubility Effect by Carbonated Low Salinity Water Injection in Carbonate Reservoirs

2017 ◽  
Vol 2017 ◽  
pp. 1-10 ◽  
Author(s):  
Ji Ho Lee ◽  
Kun Sang Lee
Keyword(s):  
Oil Recovery ◽  
Saline Water ◽  
Water Injection ◽  
Carbonate Reservoirs ◽  
Viscosity Reduction ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Geochemical Reactions ◽  
Salinity Water ◽  
Low Salinity Water Injection

Carbonated water injection (CWI) induces oil swelling and viscosity reduction. Another advantage of this technique is that CO2 can be stored via solubility trapping. The CO2 solubility of brine is a key factor that determines the extent of these effects. The solubility is sensitive to pressure, temperature, and salinity. The salting-out phenomenon makes low saline brine a favorable condition for solubilizing CO2 into brine, thus enabling the brine to deliver more CO2 into reservoirs. In addition, low saline water injection (LSWI) can modify wettability and enhance oil recovery in carbonate reservoirs. The high CO2 solubility potential and wettability modification effect motivate the deployment of hybrid carbonated low salinity water injection (CLSWI). Reliable evaluation should consider geochemical reactions, which determine CO2 solubility and wettability modification, in brine/oil/rock systems. In this study, CLSWI was modeled with geochemical reactions, and oil production and CO2 storage were evaluated. In core and pilot systems, CLSWI increased oil recovery by up to 9% and 15%, respectively, and CO2 storage until oil recovery by up to 24% and 45%, respectively, compared to CWI. The CLSWI also improved injectivity by up to 31% in a pilot system. This study demonstrates that CLSWI is a promising water-based hybrid EOR (enhanced oil recovery).

Chelating-Agent Enhanced Oil Recovery for Sandstone and Carbonate Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (03) ◽  
pp. 483-495 ◽  
Author(s):  
M. A. Mahmoud ◽  
K. Z. Abdelgawad
Keyword(s):  
Zeta Potential ◽  
Oil Recovery ◽  
Chelating Agents ◽  
Water Injection ◽  
Chelating Agent ◽  
Carbonate Reservoirs ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Core Permeability

Summary Recently low-salinity waterflooding was introduced as an effective enhanced-oil-recovery (EOR) method in sandstone and carbonate reservoirs. The recovery mechanisms that use low-salinity-water injection are still debatable. The suggested possible mechanisms are: wettability alteration, interfacial-tension (IFT) reduction, multi-ion exchange, and rock dissolution. In this paper, we introduce a new chemical EOR method for sandstone and carbonate reservoirs that will give better recovery than the low-salinity-water injection without treating or diluting seawater. In this study, we introduce a new chemical EOR method that uses chelating agents such as ethylenediaminetetraacetic acid (EDTA), hydroxyethylethylenediaminetriacetic acid (HEDTA), and diethylenetriaminepentaacetic acid (DTPA) at high pH values. This is the first time for use of chelating agents as standalone EOR fluids. Coreflood experiments, interfacial and surface tensions, and zeta-potential measurements are performed with DTPA, EDTA, and HEDTA chelating agents. The chelating-agent concentrations used in the study were prepared by diluting the initial concentration of 40 wt% with seawater and injecting it into Berea-sandstone and Indiana-limestone cores of a 6-in. length and a 1.5-in. diameter saturated with crude oil. The coreflooding experiments were performed at 100°C and a 1,000-psi backpressure. Low-salinity-water and seawater injections caused damage to the reservoir because of the calcium sulfate scale deposition during the flooding process. The newly introduced EOR method did not cause calcium sulfate precipitation, and the core permeability was not affected. The core permeability was measured after the flooding process, and the final permeability was higher than the initial permeability in the case of chelating-agent injection. The coreflooding effluent was analyzed for cations with the inductively coupled plasma (ICP) spectroscopy to explain the dissolution-recovery mechanism. The effect of iron minerals on the rock-surface charge was investigated through the measurements of zeta potential for different rocks containing different iron minerals. HEDTA and EDTA chelating agents at 5 wt% concentration prepared in seawater were able to recover more than 20% oil from the initial oil in place from sandstone and carbonate cores. ICP measurements supported the rock-dissolution mechanism because the calcium, magnesium, and iron concentrations in the effluent samples were more than those in the injected fluids. The IFT-reduction mechanism was confirmed by the low IFT values obtained in the case of chelating agents. The type and concentration of chelating agents affected the IFT value. Higher concentrations yielded lower IFT values because of the increase in carboxylic-group concentration. We found that the high-pH chelating agents increased the negative value of zeta potential, which will change the rock toward more water-wet.

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