Carbon Emission Reduction via HNGLRP CC&S Technology

2021 ◽  
Author(s):  
Sultan Ahmari ◽  
Abdullatef Mufti
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Water Reuse ◽  
Carbon Emission ◽  
Ventilation System ◽  
Acid Gas ◽  
Gas Removal ◽  
Saudi Aramco ◽  
Supercritical Phase ◽  
Incineration Process

Abstract The paper objective is to present the successful achievement by Saudi Aramco gas operations to reduce the carbon emission at Hawyiah NGL Recovery Plant (HNGLRP) after successful operation & maintainability of the newly state of the art Carbon Capture & Sequestration (CC&S) technology. This is in line with the Kingdom of Saudi Arabia (KSA) 2030 vision to increase the resources sustainability for future growth and part of Saudi Aramco circular economy in action examples. Saudi Aramco CC&S started in June 2015 at HNGLRP with main objective to capture the carbon dioxide (CO2) from Acid Gas Removal Units (AGRUs) and then inject an annual mass of nearly 750 Kton of carbon dioxide into oil wells for sequestration and enhanced oil recovery maintainability. This is to replace the typical acid gas incineration process after AGRUs operation to reduce carbon footprint. CC&S consists of the followings: integrally geared multistage compressor, standalone dehydration system using Tri-Ethylene Glycol (TEG), CO2 vapor recovery unit (VRU), Granulated Activated Carbon (GAC) to treat water generated from compression and dehydration systems for reuse purpose, and special dense phase pump that transfers the dehydrated CO2 at supercritical phase through 85 km pipeline to replace the typical sea water injection methodology in enhancing oil recovery. CC&S has several new technologies and experiences represented by the compressor capacity, supercritical phase fluid pumping, using mechanical ejector application to maximize carbon recovery, and CO2/TEG dehydration system as non-typical dehydration system. CC&S design considered the occupational health hazards generated from the compressor operation by installing engineering enclosure with proper ventilation system to minimize the noise hazard. CC&S helped HNGLRP to reduce the overall Greenhouse Gas (GHG) emission resulted from typical CO2 incineration process (thermal oxidizing). (2) The total GHG resulted from combustion sources at HNGLRP reduced by nearly 30% since CC&S technology in operation. The fuel gas consumption to run the thermal oxidizers in AGRUs reduced by 75% and sent as sales gas instead. The Energy Intensity Index (EII) reduced by 8% since 2015, water reuse index (WRI) increased by 12%. In conclusion, the project shows significant reduction in the carbon emission, noticeable increase in the production, and considerable water reuse.

Amine-Based Carbon Dioxide Capture: Densities of CO2-Loaded Monoethanolamine Aqueous Solution at 10 to 90 °C

2021 ◽  
Vol 319 ◽  
pp. 47-51
Author(s):  
Sholeh Ma'mun ◽  
Afif Dwijayanto
Keyword(s):  
Carbon Dioxide ◽  
Aqueous Solutions ◽  
Excess Molar Volumes ◽  
Pure Component ◽  
Average Error ◽  
Molar Volumes ◽  
Acid Gas ◽  
Volumetric Expansion ◽  
Gas Removal ◽  
High Concentrations

The global warming phenomenon has led to world climate change caused by high concentrations of greenhouse gases (GHG) especially carbon dioxide (CO2) in the atmosphere. Carbon dioxide is produced in large quantities from fuel combustions, gas sweetening processes, etc. Since its emission rises annually, some efforts to reduce the emission are, therefore, required. Monoethanolamine (MEA), a primary amine, has been widely used for many years for acid gas removal. To get a better column performance, an accurate physical properties measurement, such as density, needs to be conducted. This study aims to measure the densities of 10 wt.% MEA aqueous solutions at temperatures from 10 to 90 °C and CO2 loadings up to 0.417 mol CO2/mol MEA. The results show that the higher the concentration of CO2 the higher the density at a constant temperature, while the densities decrease as temperatures increase due to volumetric expansion. Besides, an expression to correlate the densities of 10 wt.% MEA aqueous solutions was also developed based on the pure-component molar volumes together with the excess molar volumes. The average error of the measurement was found to be 0.18%.

Rancang Bangun Sistem Pengendalian Level pada Knock Out Gas Drum Menggunakan Pengendali PID di Plant LNG

2019 ◽  
Vol 20 (1) ◽  
pp. 1
Author(s):  
Paisal Tajun Aripin ◽  
Erna Kusuma Wati ◽  
V. Vekky R. Repi ◽  
Hari Hadi Santoso
Keyword(s):  
Carbon Dioxide ◽  
Hydrogen Sulfide ◽  
Steady State ◽  
Control Valve ◽  
Knock Out ◽  
Acid Gas ◽  
Gas Removal

Proses AGRU (Acid Gas Removal Unit) yaitu suatu pemisahan H2S<br />(Hydrogen Sulfide) dan CO2 (Carbon Dioxide) yang terkandung didalam gas dengan<br />menggunakan larutan amine melalui proses absorsi. Adapun peralatan penyusun proses<br />tersebut adalah absorber, regenerator, reboiler, condenser, cooler dan reflux drum. Dalam<br />penalaan kontrol PID ada beberapa metode yang digunakan seperti, Ziegler – Nichols dan<br />Tyreus – Luyben, metode ini memiliki dua cara metode kurva reaksi dan osilasi. Nilai set<br />point 0.21m dan maximum overshot (Mp = 9.75%). Sistem sudah dimasuki keadaan steady<br />pada titik ke – 5.54 (time setting) dengan Error Steady State (Ess) ± 0%, inilah osilasi<br />terbaik berdasarkan keriteria performansi dan pengaruhnya terhadap respon control valve,<br />maka parameter controller yang cocok untuk sistem pengendalian level pada liquid tank<br />adalah nilai parameter yang didapatkan dengan tuning menggunakan fungsi pidtune matlab.<br />Berdasarkan simulasi terakhir yang dilakukan dapat dilihat bahwa tuning dengan fungsi<br />pidtune matlab memberikan nilai Kp, Ki, dan Kd pada kontroler PID yang paling baik jika<br />dibandingkan dengan metode Ziegler – Nichols. Selain itu tuning dengan fungsi pidtune<br />matlab juga dapat dilakukan dengan proses yang lebih mudah dan sederhana.

Hexapod Pilot Tests Determine the Influence of 3D Motions on the Performance of an Amine-Based Acid Gas Removal Unit Installed on a Floating Support

2016 ◽  
Author(s):  
Perdu Gauthier ◽  
Salais Clément ◽  
Carlier Vincent ◽  
Prosernat S. A Weiss Claire ◽  
Maubert Thomas ◽  
...  
Keyword(s):  
Acid Gas ◽  
Gas Removal ◽  
Pilot Tests

scholarly journals Laboratory evaluation of hybrid chemical enhanced oil recovery methods coupled with carbon dioxide

2021 ◽  
Vol 7 ◽  
pp. 960-967
Author(s):  
Mohammad Hossein Ahmadi ◽  
S.M. Alizadeh ◽  
Dmitry Tananykhin ◽  
Saba Karbalaei Hadi ◽  
Pavel Iliushin ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Laboratory Evaluation ◽  
Recovery Methods

Simulation of an Acid Gas Removal Unit Using a DGA and MDEA Blend Instead of a Single Amine

2020 ◽  
Vol 0 (0) ◽  
Author(s):  
Umer Zahid
Keyword(s):  
Energy Savings ◽  
Circulation Rate ◽  
Inlet Temperature ◽  
Acid Gas ◽  
Gas Processing ◽  
Gas Removal ◽  
Processing Plants ◽  
Operational Energy ◽  
Commercial Process ◽  
The Impact

AbstractMost of the industrial acid gas removal (AGR) units employ chemical absorption process for the removal of acid gases from the natural gas. In this study, two gas processing plants operational in Saudi Arabia have been selected where two different amines n1amely, diglycolamine (DGA) and monoethanol amine (MDEA) are used to achieve the sweet gas purity with less than 4 ppm of H2S. This study performed a feasibility simulation of AGR unit by utilizing the amine blend (DGA+MDEA) for both plants instead of a single amine. The study used a commercial process simulator to analyze the impact of process variables such as amine circulation rate, amine strength, lean amine temperature, regenerator inlet temperature, and absorber and regenerator pressure on the process performance. The results reveal that when the MDEA (0–15 wt. %) is added to DGA, marginal energy savings can be achieved. However, significant operational energy savings can be made when the DGA (0–15 wt. %) is blended with MDEA being the main amine.

Weibull Statistical Analysis of Pulsed Breakdown Voltages in High-Pressure Carbon Dioxide Including Supercritical Phase

2011 ◽  
Vol 39 (8) ◽  
pp. 1729-1735 ◽  
Author(s):  
Tsuyoshi Kiyan ◽  
Takeshi Ihara ◽  
Suguru Kameda ◽  
Tomohiro Furusato ◽  
Masanori Hara ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
High Pressure ◽  
Statistical Analysis ◽  
Weibull Statistical Analysis ◽  
Supercritical Phase

Saturated carbon dioxide nanofluids enhanced oil recovery in carbonate reservoir cores using nuclear magnetic resonance

2021 ◽  
Author(s):  
Yongsheng Tan ◽  
Qi Li ◽  
Liang Xu ◽  
Xiaoyan Zhang ◽  
Tao Yu
Keyword(s):  
Carbon Dioxide ◽  
Nuclear Magnetic Resonance ◽  
Magnetic Resonance ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Residual Oil ◽  
Core Flooding ◽  
Nuclear Magnetic

&lt;p&gt;The wettability, fingering effect and strong heterogeneity of carbonate reservoirs lead to low oil recovery. However, carbon dioxide (CO&lt;sub&gt;2&lt;/sub&gt;) displacement is an effective method to improve oil recovery for carbonate reservoirs. Saturated CO&lt;sub&gt;2&lt;/sub&gt; nanofluids combines the advantages of CO&lt;sub&gt;2&lt;/sub&gt; and nanofluids, which can change the reservoir wettability and improve the sweep area to achieve the purpose of enhanced oil recovery (EOR), so it is a promising technique in petroleum industry. In this study, comparative experiments of CO&lt;sub&gt;2&lt;/sub&gt; flooding and saturated CO&lt;sub&gt;2&lt;/sub&gt; nanofluids flooding were carried out in carbonate reservoir cores. The nuclear magnetic resonance (NMR) instrument was used to clarify oil distribution during core flooding processes. For the CO&lt;sub&gt;2&lt;/sub&gt; displacement experiment, the results show that viscous fingering and channeling are obvious during CO&lt;sub&gt;2&lt;/sub&gt; flooding, the oil is mainly produced from the big pores, and the residual oil is trapped in the small pores. For the saturated CO&lt;sub&gt;2&lt;/sub&gt; nanofluids displacement experiment, the results show that saturated CO&lt;sub&gt;2&lt;/sub&gt; nanofluids inhibit CO&lt;sub&gt;2&lt;/sub&gt; channeling and fingering, the oil is produced from the big pores and small pores, the residual oil is still trapped in the small pores, but the NMR signal intensity of the residual oil is significantly reduced. The final oil recovery of saturated CO&lt;sub&gt;2&lt;/sub&gt; nanofluids displacement is higher than that of CO&lt;sub&gt;2&lt;/sub&gt; displacement. This study provides a significant reference for EOR in carbonate reservoirs. Meanwhile, it promotes the application of nanofluids in energy exploitation and CO&lt;sub&gt;2&lt;/sub&gt; utilization.&lt;/p&gt;

A Laboratory Investigation of the Effect of Ethanol-Treated Carbon Dioxide Injection on Oil Recovery and Carbon Dioxide Storage

SPE Journal ◽  
2021 ◽  
pp. 1-17
Author(s):  
Saira ◽  
Emmanuel Ajoma ◽  
Furqan Le-Hussain
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Molar Fraction ◽  
Co2 Injection ◽  
Carbon Dioxide Injection ◽  
Treated Carbon ◽  
Carbon Dioxide Co2 ◽  
And Storage ◽  
Experimental Runs

Summary Carbon dioxide (CO2) enhanced oil recovery is the most economical technique for carbon capture, usage, and storage. In depleted reservoirs, full or near-miscibility of injected CO2 with oil is difficult to achieve, and immiscible CO2 injection leaves a large volume of oil behind and limits available pore volume (PV) for storing CO2. In this paper, we present an experimental study to delineate the effect of ethanol-treated CO2 injection on oil recovery, net CO2 stored, and amount of ethanol left in the reservoir. We inject CO2 and ethanol-treated CO2 into Bentheimer Sandstone cores representing reservoirs. The oil phase consists of a mixture of 0.65 hexane and 0.35 decane (C6-C10 mixture) by molar fraction in one set of experimental runs, and pure decane (C10) in the other set of experimental runs. All experimental runs are conducted at constant temperature 70°C and various pressures to exhibit immiscibility (9.0 MPa for the C6-C10 mixture and 9.6 MPa for pure C10) or near-miscibility (11.7 MPa for the C6-C10 mixture and 12.1 MPa for pure C10). Pressure differences across the core, oil recovery, and compositions and rates of the produced fluids are recorded during the experimental runs. Ultimate oil recovery under immiscibility is found to be 9 to 15% greater using ethanol-treated CO2 injection than that using pure CO2 injection. Net CO2 stored for pure C10 under immiscibility is found to be 0.134 PV greater during ethanol-treated CO2 injection than during pure CO2 injection. For the C6-C10 mixture under immiscibility, both ethanol-treated CO2 injection and CO2 injection yield the same net CO2 stored. However, for the C6-C10 mixture under near-miscibility,ethanol-treated CO2 injection is found to yield 0.161 PV less net CO2 stored than does pure CO2 injection. These results suggest potential improvement in oil recovery and net CO2 stored using ethanol-treated CO2 injection instead of pure CO2 injection. If economically viable, ethanol-treated CO2 injection could be used as a carbon capture, usage, and storage method in low-pressure reservoirs, for which pure CO2 injection would be infeasible.

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