Testing of Snorre Field Foam Assisted Water Alternating Gas (FAWAG) Performance in New Foam Screening Model

Spirov, Pavel; Rudyk, Svetlana Nikolayevna

doi:10.2516/ogst/2013193

Cited by 13 publications

(8 citation statements)

References 13 publications

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“…7 Commonly used foaming agents (e.g., SDS, AOS) can hardly meet the high temperature and high salinity reservoir conditions in foam flooding projects. 8,9 For example, the apparent viscosity of AOS foam decreases by 50% as the temperature increases from 20 to 80 °C in a sandstone porous medium with coinjection of foam. 2 Levitt et al describes that the presence of the sulfonate unit in the compound increases the surfactant long-term stability at higher temperature and makes the internal olefin sulfonate (IOS) stable at temperatures up to 200 °C.…”

Section: Introductionmentioning

confidence: 99%

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Internal Olefin Sulfonate Foam Coreflooding in Low-Permeable Limestone at Varying Salinity

et al. 2019

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Effects of salinity, total flow rate, and gas flow rate on the foam generation using internal olefin sulfonate (IOS) surfactant were investigated. The compatibility tests performed at 1−11% NaCl at a room temperature of 22 °C showed that the volume of foam on the surface of the liquid increased with salinity increase from 1% to 11% NaCl, indicating that the foamability did not reduce but solubility of surfactant in brine decreased with increasing salinity. The surfactant precipitation on the bottom of the test tubes occurred starting from 6% NaCl at 22 °C and from 8% NaCl at 60 °C. However, surfactant emerged to the surface at 9−11% NaCl because of the increased brine density. The foam scans using 0.5% IOS surfactant were carried out at a salinity of 1, 5, and 8% NaCl through an Indiana limestone core sample of 50 mD at 60 °C. Two total flow rates of 0.4 mL/min and 0.3 mL/min, superficial velocities of 4.39 *10 −6 m/s and 5.88 × 10 −6 m/s, respectively, were used to simulate flow rates typically applied at the oil fields at 400 and 500 psi. Generally, the differential pressure decreased in the order of gas flow rate decrease while apparent viscosity was higher at lower total flow rate. The apparent viscosity at 5% NaCl were higher than at 1% NaCl at 0.3 mL/min and similar or lower at 0.4 mL/min. The shape of apparent viscosity curves changed from typical for shear-thinning fluids at 1% and 5% NaCl to linearly decreasing at 8% NaCl. The typical increase of apparent viscosity in a low flow regime observed by many authors was very gentle because of the low total flow rates compared to that previously published. The fine foam was observed at the outlet of the system at 1 and 5% NaCl at all foam qualities (gas fractions). At 8% NaCl, the foam was observed at 0.3 and 0.4 foam qualities while only bubbles were formed at 0.5−0.9. In a low foam quality regime, the foam viscosity at the outlet of the system indicated by the length of foam drop before fall decreased at increasing gas fraction while the apparent viscosity was constant. This showed that the foam mobility and volumes of arrived foam could be underestimated by using apparent viscosity. The shape of apparent viscosity curves at low total flow rates and difference between actual viscosity and apparent viscosity should be considered in practical use and numerical simulations.

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Section: Introductionmentioning

confidence: 99%

“…Commonly used foaming agents (e.g., SDS, AOS) can hardly meet the high temperature and high salinity reservoir conditions in foam flooding projects. , For example, the apparent viscosity of AOS foam decreases by 50% as the temperature increases from 20 to 80 °C in a sandstone porous medium with coinjection of foam …”

Section: Introductionmentioning

confidence: 99%

Internal Olefin Sulfonate Foam Coreflooding in Low-Permeable Limestone at Varying Salinity

et al. 2019

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“…The largest full-scale demonstration of FAWAG was carried out in 1997 in the Snorre field in the North Sea (see Table 6) with the aim of improving the gas sweep efficiency. WAG was the first EOR scheme in the Snorre field in 1994, but was later changed to FAWAG scheme after 3 years (Spirov and Rudyk 2015). During WAG, there was an observed tendency of gas channelling to the high permeability zones and getting trapped.…”

Section: Foam and Water Alternating Gas (Fawag) Methodsmentioning

confidence: 99%

A review of gas enhanced oil recovery schemes used in the North Sea

Gbadamosi

Kiwalabye

Junin

et al. 2018

J Petrol Explor Prod Technol

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The rate of replacement of produced oil and gas reserves by new discoveries is in a state of steady decline. Instead of searching for rare new oil fields, it is more economically justified to improve production from the existing and known fields. This is often achieved using enhanced oil recovery (EOR) technologies. The application of EOR in the North Sea dates to the mid-1970's with most of the fields being flooded with gas due to their light oils. Following a critical review of relevant published literature, the EOR methods in the past five decades are: water alternating gas (WAG), miscible gas injection (MGI), foam assisted water alternating gas (FAWAG), simultaneous water and gas (SWAG), and microbial enhanced oil recovery. The first part of this paper explores the advantages and limitations of the field implementation of gas EOR methods in North Sea oil fields. In the second part, new screening criteria of WAG, SWAG, MGI and FAWAG were developed by performing statistical analysis of the data from the past field experiences, especially in the North Sea. The screening criteria of the future methods are clearly documented in the literature and therefore not covered in this study. From the screening criteria, it has been identified that most North Sea fields qualify for WAG. This explains why WAG has been the most common scheme in the North Sea. FAWAG should also be implemented either after WAG or SWAG when the residual oil saturation is < 20%.

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“…The main technologies of enhanced oil recovery (EOR) in carbonate reservoirs are CO 2 , N 2, and hydrocarbon gas injections (Memon et al 2020). Gas fingering and early gas breakthrough can be prevented by injecting a foamy surfactant solution to reduce gas mobility and redirect gas flow (Spirov and Rudyk 2015).…”

Section: Impact Of Salinity On Foamability and Foam Stabilitymentioning

confidence: 99%

Effects of water salinity on the foam dynamics for EOR application

Rudyk

Al-Khamisi

Al-Wahaibi

2021

J Petrol Explor Prod Technol

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Factors limiting foam injection for EOR application are exceptionally low rock permeability and exceedingly high salinity of the formation water. In this regard, foam formation using internal olefin sulfonate is investigated over a wide salinity range (1, 5, 8, 10, and 12% NaCl) through 10 mD limestone. The relationships between pressure drop (dP), apparent viscosity, liquid flow rate, total flow rate, salinity, foam texture, and length of foam drops at the outlet used as an indicator of viscosity are studied. Foaming is observed up to 12% NaCl, compared to a maximum of 8% NaCl in similar core-flooding experiments with 50 mD limestone and 255 mD sandstone. Thus, the salinity limit of foam formation has increased significantly due to the low permeability, which can be explained by the fact that the narrow porous system acts like a membrane with smaller holes. Compared to the increasing dP reported for highly permeable rocks, dP linearly decreases in almost the entire range of gas fraction (fg) at 1–10% NaCl. As fg increases, dP at higher total flow rate is higher at all salinities, but the magnitude of dP controls the dependence of apparent viscosity on total flow rate. Low dP is measured at 1% and 10% NaCl, and high dP is measured at 5, 8, and 12% NaCl. In the case of low dP, the apparent viscosity is higher at higher total flow rate with increasing gas fraction, but similar at two total flow rates with increasing liquid flow rate. In the case of high dP, the apparent viscosity is higher at lower total flow rate, both with an increase in the gas fraction and with an increase in the liquid flow rate. A linear correlation is found between dP or apparent viscosity and liquid flow rate, which defines it as a governing factor of foam flow and can be considered when modeling foam flow.

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Testing of Snorre Field Foam Assisted Water Alternating Gas (FAWAG) Performance in New Foam Screening Model

Cited by 13 publications

References 13 publications

Internal Olefin Sulfonate Foam Coreflooding in Low-Permeable Limestone at Varying Salinity

Internal Olefin Sulfonate Foam Coreflooding in Low-Permeable Limestone at Varying Salinity

A review of gas enhanced oil recovery schemes used in the North Sea

Effects of water salinity on the foam dynamics for EOR application

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