Carbon Emission Reduction via HNGLRP CC&S Technology

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.

Optimizing Location of CO2 Recovery Units

In line with ADNOC Sustainability policy, reduction of GHG emissions, AGP has initiated projects for recovery of CO2 from existing plants. The extracted CO2 is planned to be used for Enhanced Oil Recovery. The current paper highlights method used for evaluation of various location and technology options for implementation of the new CO2 recovery units, considering existing plants flow schemes along with their interfaces and associated challenges. Key Performance Indicators (KPIs) were identified based on Inherent Safety, Economics, Technology Maturity, Product Quality, Operability / Flexibility, Constructability. Identified options were further developed and subsequently evaluated based on preliminary economic analysis and available technical information. Accordingly, weighted scores of the KPIs developed for option selection. Major criteria used for ranking were unit cost of CO2 product, adherence to required H2S and COS specifications, technology maturity and deployment in industry.For one location, the options considered included installation of new Acid Gas Removal Unit (AGRU) upstream of existing AGRU, revamp of existing Acid Gas Enrichment Unit (AGEU), new AGEU, and direct feed of Acid gas to new CO2 recovery unit to supplement falling upstream reservoir profile.For another location, the options included new CO2 recovery plant upstream of existing Sulphur Recovery Unit (SRU) or downstream of existing Tail Gas Treatment Unit (TGTU), compression of TGTU gases upstream of proposed CO2 recovery unit, installation of new unit downstream of existing incinerators, combination of CO2 recovery units of both plants, were also assessed.In addition, new CO2 Dehydration and Compression units considered to meet CO2 product specifications and B/L requirements. Based on project requirements, physical methods of CO2 removal like membranes and molecular sieves deemed unsuitable. Further to discussions with various licensors, emphasis remained on chemical and physical solvent technologies. Based on assessment, solvent swap for AGEU (upstream of existing SRUs) with reduced lean solvent temperature at one location, solvent swap in TGTU followed by a new polishing unit at another location combined with common high pressure compression facility, was selected for engineering development.

Tertiary Amine-Mediated Polyvinyl Alcohol Membrane Over the Porous Support of Polyvinyl Chloride Membrane for CO2 Separation

Great attention has been paid to membrane-based separation technology in various separation fields, including gas separation. It provides the benefits of energy efficiency, environmental friendliness, easy scale-up, and convenience in operation. Different division advancements are being utilized for the expulsion of acid gas carbon dioxide (CO2). The aim of this work is to synthesis the membrane using polyvinyl alcohol (PVA) with treatment (WT) and without treatment (WOT) of the additive that is triethanolamine (TEA), to study the effect of additive on the permeance of membrane towards CO2 and the morphology changes of each membrane. In this research, virgin PVA and PVA with TEA were cast upon the porous support membrane of polyvinyl chloride (PVC). PVA was used as the polymer matrix, and TEA was used as a CO2 facilitating agent. Distilled water was used as a solvent for TEA and PVA in preparing the solution. Dimethyl acetamide (DMAc) and Tetrahydrofuran (THF) were used as solvents for PVC porous membranes. These membranes were tested on CO2 to find out the permeability and flux rates (J). For the morphology of the membrane, we performed SEM; for thermal analysis, we performed DSC and TGA, and for the strength, we performed the tensile test. The results reveal that the presence of TEA changes the morphology and thermal behavior increases the strength and the permeability of CO2. In a nutshell, the presence of TEA enhanced the performance and the morphology of the membrane.

Analisis dan Optimasi Pengaruh Suhu Gas Umpan Pada Kinerja Acid Gas Removal Unit

The Gas Gathering Station (GGS) in field X processes gas from 16 (sixteen) wells before being sent as selling gas to consumers. The sixteen wells have decreased in good pressure since 2011, thus affecting the performance of the Acid Gas Removal Unit (AGRU). The GGS consists of 4 (four) main units, namely the Manifold Production/ Test, the Separation Unit, the Acid Gas Removal Unit (AGRU), the Dehydration Unit (DHU). The AGRU facility in field X is designed to reduce the acid gas content of CO2 by 21 mol% with a feed gas capacity of 85 MMSCFD. A decrease in reservoir pressure caused an increase in the feed gas temperature and an increase in the water content of the well. Based on the reconstruction of the design conditions into the simulation model, the amine composition consisting of MDEA 0.3618 and MEA 0.088 wt fraction to obtain the percentage of CO2 in the 5% mol sales gas. The increase in feed gas temperature up to 146 F caused foaming due to condensation of heavy hydrocarbon fraction, so it was necessary to modify it by adding a chiller to cool the feed gas to become 60 F. Based on the simulation, the flow rate of gas entering AGRU could reach 83.7 MMSCFD. There was an increase in gas production of 38.1 MMSCFD and condensate of 1,376 BPD. Economically, the addition of a chiller modification project was feasible with the economical parameters of NPV US$ 132,000,000, IRR 348.19%, POT 0.31 year and PV ratio 19.06.

PENGARUH LAJU ALIR ABSORBEN DAN WAKTU KONTAK K2CO3 TERHADAP PENYERAPAN CO2 YANG TERKANDUNG DALAM GAS ALAM

Gas CO2 atau gas asam (sour gas) merupakan salah satu kandungan dari gas alam yang sifatnya sebagai kontaminan. Adanya kandungan gas CO2 yang tinggi didalam gas alam perlu dilakukan treatment khusus dalam menghilangan kandungan gas asam (sour gas) tersebut dari gas alam dimana proses penghilangan gas asam dari gas alam disebut proses Sweetening. Proses Absorspi gas CO2 merupakan metode yang sering dilakukan. Penelitian ini bertujuan mengetahui pengaruh laju alir absorben dan waktu kontak terhadap konsentrasi CO2 yang di serap. Metode yang dilakukan dalam penelitian ini yaitu dengan perancangan alat yang bisa menunujukan proses absorpsi CO2. Variabel penelitian yang digunakan memvariasikan laju alir absorben 4,95 ml/s, 7,26 ml/s, 10,75 ml/s serta waktu kontak 2,4,6,8 menit dengan menggunakan absorben K2CO3 dan Gas alam yang digunakan compress Natural Gas CNG. Dari hasil penelitan laju alir Absorbenyang paling baik didapat pada 10,75 ml/s dengan penyerapan CO2 sebesar 69,45 %. Waktu kontak pada setiap waktu tidak berpengaruh banyak terhadap konsentarsi CO2 yang terserap . Kata kunci: absorben, Sour gas, gas alam, laju alir AbstractCO2 gas or acid gas (sour gas) is one of the contents of natural gas which is a contaminant. The presence of high CO2 gas content in natural gas requires special treatment to remove the sour gas content from natural gas where the process of removing acid gas from natural gas is called the Sweetening process. The CO2 gas absorption process is a method that is often used. This study aims to determine the effect of absorbent flow rate and contact time on the absorbed CO2 concentration. The method used in this research is to design a tool that can show the CO2 absorption process. The research variables used varied the absorbent flow rate of 4.95 ml/s, 7.26 ml/s, 10.75 ml/s and a contact time of 2,4,6,8 minutes using K2CO3 absorbent and natural gas used compressed Natural CNG gas. From the research results, the best absorbent flow rate was obtained at 10.75 ml/s with CO2 absorption of 69.45%. Contact time at any time did not have much effect on the concentration of CO2 absorbed. Keywords: absorbent, sour gas, natural gas, flow rate

The Overlooked Perils of Heterogeneous Oil and Gas

Chapter 2 details the differences and similarities among twenty-first-century petroleum resources and distinguishes conventional from unconventional resources. The chapter argues that, while these definitions are muddled, there is value to understanding and parsing unconventional oil and gas. Numerous different oil and gas resources are then surveyed, including shale gas, ultradeep gas, Arctic gas, tight gas, coalbed methane, biogas, acid gas, geopressurized gas, methane hydrates, condensates, light tight oil, extra-heavy oil, ultradeep oil, Arctic oil, depleted oil, kerogen, biofuels, gas-to-liquids, and coal-to-liquids. Estimates are provided of cumulative industry greenhouse gas emissions for conventional versus unconventional oil and gas resources. The chapter concludes with a discussion of hydrogen—the ultimate unconventional resource—and its production pathways.