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In continuation of Feb 2023 “Tips of the Month” (TOTM) and given the amount of investment and interest in hydrogen, we have decided to publish a series of TOTM to explore the opportunities, challenges, and potential solutions to hydrogen applications and uses; this is the second paper in the series. As such, we will continue this exploration with hydrogen compression and transportation by transmission pipeline systems – what are the permissible conditions and restrictions? This TOTM does not cover the pipeline materials compatibility issues, which will be a focus of another tip. In terms of the compression characteristics, what are the technical challenges for deployment? Specifically, we explore the possibility of blending a relatively pure hydrogen stream with a natural gas residue to supply 5.65x106 SCMD (standard cube meter per day) or 200 MMSCFD fuel gas to a heavy industrial unit. With the aim of achieving net zero, the objective is to maximize amount of hydrogen in the fuel gas by replacing hydrocarbons while meeting pipeline tariff and sales specifications. [Keep reading]

There are several “non-metallic” options for gas gathering system applications. To a large degree, non-metallics eliminate the corrosion concerns – both internal and external – associated with metallic – typically carbon steel – pipelines. [Keep reading]

Hydrogen sulfide and carbon dioxide are the principal objectionable acid gas components often present in natural gas, synthetic gas, and various refinery gas streams. These acid gas components must be removed for corrosion prevention in gas pipelines, process equipment, and for health and safety reasons. Reference [1] provides current acceptable concentration levels for these acid gases in various gas streams. Hydrogen sulfide removal often requires the production of sulfur in the sulfur recovery units to meet emission limits. Sulfur is a product used to produce sulfuric acid and fertilizers. Carbon dioxide removal is used for enhanced oil recovery and is required for carbon capture and sequestering (CCS) operations. [Keep reading]

In some cases, a choke/line heater is required at the wellsite to deal with the large JT expansion cooling effect experienced by choked high-pressure wells, especially during start-up. This is a somewhat different application than prevention of hydrates in the GGS but there are some common aspects to the equipment utilized. First, the hydrate temperature of the flowing wellstream is estimated. From Figure 1, for 0.65 SG gas and assuming any free water present is condensed/fresh water, the estimated hydrate temp at an assumed average GGS pressure of 1,100 psig is ~ 65 F. [Keep reading]

Part 1 : Shale gas is typically considered an “unconventional” resource, along with tight gas and coalbed methane. Of these three, coalbed methane (CBM) has several characteristics that make it quite different than shale gas and tight gas, including: shallow depth, low pressure and temperature, and the need for a significant early life “de-watering” stage. As a result, CBM developments have some considerably different aspects to them and will not be discussed further in this article. [Keep reading]

Existen tres unidades claves de procesamiento, vis. Unidad de Remoción del Gas Acido (AGRU/URGA), Unidad de Deshidratación por Tamices Moleculares (MSDU/UTMD), y la Unidad de Remoción de Mercurio (MRU/URM) que son comunes tanto en el procesamiento del gas, así como facilidades del GNL. En este Previo del Mes (PDM), se analizaran algunos problemas operacionales asociados con estas unidades de proceso, y las acciones de solución en sitio (troubleshooting) de estas circunstancias operacionales. La clave para lograr una operación exitosa de estas unidades es el entendimiento de los parámetros que ocasionan la problemática operacional y como detectar estos en la fase de diseño del proyecto. [Keep reading]