Impact of H2S in Predicting the Storage Efficiency of CO2 Injection in a High Pressure High Temperature (HPHT) Carbonate Aquifer - A Case Study in a Sarawak Offshore High CO2 Gas Field, Malaysia

Zaidin, Mohd Fakrumie; Chapoy, Antonin; Coquelet, Christophe; Valtz, Alain; Raub, Mohd Razib Abd; Kantaatmadja, Budi Priyatna

doi:10.2139/ssrn.3366049

Cited by 5 publications

(1 citation statement)

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“…The rising demand for oil and gas led to the search for complicated sources including shale gas, tight reservoir and highly contaminated gas & oil fields (Ibrahim and Saleh, 2020;Tewari and Sedaralit, 2021). In Malaysia, there has been an emphasis to reduce CO 2 emission from high CO 2 offshore gas fields by re-injecting the produced CO 2 after its separation from the gas stream into available saline aquifers (Jalil et al, 2012;Md Yusof et al, 2021;Zaidin et al, 2018). An estimated 37 Tscf of natural gas remains undeveloped in Malaysia's gas fields, in which the CO 2 contents exceed 10% by volume of produced acid gas (Sukor et al, 2020).…”

Section: Introductionmentioning

confidence: 99%

Experimental study of CO2 injectivity impairment in sandstone due to salt precipitation and fines migration

Yusof

Neuyam

Ibrahim

et al. 2022

J Petrol Explor Prod Technol

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Re-injection of carbon dioxide (CO2) in deep saline formation is a promising approach to allow high CO2 gas fields to be developed in the Southeast Asia region. However, the solubility between CO2 and formation water could cause injectivity problems such as salt precipitation and fines migration. Although both mechanisms have been widely investigated individually, the coupled effect of both mechanisms has not been studied experimentally. This research work aims to quantify CO2 injectivity alteration induced by both mechanisms through core-flooding experiments. The quantification injectivity impairment induced by both mechanisms were achieved by varying parameters such as brine salinity (6000–100,000 ppm) and size of fine particles (0–0.015 µm) while keeping other parameters constant, flow rate (2 cm3/min), fines concentration (0.3 wt%) and salt type (Sodium chloride). The core-flooding experiments were carried out on quartz-rich sister sandstone cores under a two-step sequence. In order to simulate the actual sequestration process while also controlling the amount and sizes of fines, mono-dispersed silicon dioxide in CO2-saturated brine was first injected prior to supercritical CO2 (scCO2) injection. The CO2 injectivity alteration was calculated using the ratio between the permeability change and the initial permeability. Results showed that there is a direct correlation between salinity and severity of injectivity alteration due to salt precipitation. CO2 injectivity impairment increased from 6 to 26.7% when the salinity of brine was raised from 6000 to 100,000 ppm. The findings also suggest that fines migration during CO2 injection would escalate the injectivity impairment. The addition of 0.3 wt% of 0.005 µm fine particles in the CO2-saturated brine augmented the injectivity alteration by 1% to 10%, increasing with salt concentration. Furthermore, at similar fines concentration and brine salinity, larger fines size of 0.015 µm in the pore fluid further induced up to three-fold injectivity alteration compared to the damage induced by salt precipitation. At high brine salinity, injectivity reduction was highest as more precipitated salts reduced the pore spaces, increasing the jamming ratio. Therefore, more particles were blocked and plugged at the slimmer pore throats. The findings are the first experimental work conducted to validate theoretical modelling results reported on the combined effect of salt precipitation and fines mobilisation on CO2 injectivity. These pioneering results could improve understanding of CO2 injectivity impairment in deep saline reservoirs and serve as a foundation to develop a more robust numerical study in field scale.

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