Identification and management of marine process safety risk exposure is a key focus area on every offshore project. However, there are new and evolving threats that continue to challenge the offshore industry’s ability to deliver incident free projects. Simply stated, these threats are the dilution of skills and limited experience prevalent in a rapidly expanding industry.
The commissioning activities for massive, technically complex offshore facilities often requires years of 24/7-project involvement by hundreds of workers. There is an abundance of time and ample opportunity for accidents to happen with the rapid increase in risk exposure.
Although preventing accidents is the responsibility of every individual worker, HSSE (health, safety, security and environmental) systems employing the right methodology, robust management tools and relevant experience are critical to safety during every work process. Although computers and software cannot produce oil or gas directly, they can help a project team make informed, timely decisions.
In the oil and gas industry, many different approaches have attempted to provide accurate predictions of the hydrodynamics and flow-related characteristics of fluids. However, factors such as modeling the concentration of a dispersed phase, the determination of drag and lift forces and relative motion between phases, and the need to consider particles with ranges of shape, size and density means that the only viable option in many situations is the use of computational fluid dynamics (CFD) to develop accurate solutions for challenging multiphase flow problems.
Efficient production of oil and gas generally requires the use of specialty chemicals to ensure continuous and profitable system operability. The application of these chemicals help mitigate several flow assurance and integrity related challenges including asphaltene and wax deposition, scale build-up, hydrate blockage, corrosion, etc. In offshore applications, particularly in deepwater (DW), where many components of the production system are not easily accessible, it is critical to ensure safe and reliable chemical delivery to obtain maximum recovery without any lost production or asset integrity issues.
Introduction Wells can be organized into three primary categories: production, injection, and conversion/turn-around. Material selection must be tailored to each well type, as each offers unique challenges from a materials performance perspective.
Tubing and casing are critical to the production of oil and gas and well integrity. Reservoir fluids flowing through the production tubing are often corrosive, making necessary the use of corrosion resistant alloys (CRA) offshore.
Is it safe enough? This can be a difficult question. Level of Protection Analysis (LOPA) is a structured method that yields a defendable answer to that question.
LOPA uses conservative, order of magnitude values for initiating event frequency, consequence severity and likelihood of failure of protective layers to approximate a risk level for any given scenario. In rigor, it falls between a typical risk matrix approach (as commonly used in HAZOPs) and a quantitative method (QRA). A LOPA is frequently performed after a HAZOP to further investigate significant findings.
This GATEKEEPER focuses on Amine Systems, one of the most commonly used regenerative H2S scavengers in the Oil & Gas industry.
Amines are organic compounds derived from ammonia with substitution of one or all of the hydrogens with alkyl or aryl groups, retaining a basic nitrogen atom with one lone pair of electrons. They can be classified as Primary, Secondary, Tertiary, or Cyclic.
H2S scavenging, or “gas sweetening,” is both a safety-critical and economic concern for ensuring trouble free upstream and downstream operations. This GATEKEEPER will discuss the use of triazine as a liquid H2S scavenger. Focal points include method of scavenging, application limits, treatment efficiency, production systems, downstream risks, as well as environmental impacts.
Hydrogen sulfide (H2S) scavenging, or “gas sweetening,” is a crucial aspect in ensuring trouble free upstream and downstream operations. This GATEKEEPER presents different methods of H2S scavenging, including scavenging mechanisms, application considerations, and advantages & disadvantages for each method.
Natural gas is considered sour if it contains significant amounts of H2S, generally 4 parts per million (ppm) or greater. Sour gas is caused due to development of shale oil & gas plays, efforts to increase field life, and the use of Enhanced Oil Recovery (EOR) methods like water injection often result in reservoir souring. High H2S concentrations in produced gas creates safety hazards for operations, increases corrosion and sulfide-stress-cracking risks, and results in an export gas of lower value. To minimize these factors, various H2S removal methods can be utilized.
Corrosion modeling is a vital tool in the pre-Front End Engineering Design (pre-FEED), FEED, and operational stages of the life of pipeline and equipment systems. Corrosion and materials engineers often rely on corrosion prediction models to select appropriate materials for construction, incorporate sufficient corrosion allowance into a design, and evaluate chemical corrosion inhibitor requirements or recommend other corrosion mitigation methods.
Corrosion modeling is a vital tool in the pre-Front End Engineering Design (FEED), FEED, and operational stages of the life of pipeline and flowline systems. Corrosion and materials engineers often rely on corrosion prediction models to select appropriate materials for construction, incorporate sufficient corrosion allowance into a design, and establish the need for chemical corrosion inhibitors or other corrosion mitigation methods.
Subsea Integrity Management is defined as the management of a subsea system or asset to ensure that it delivers the design requirements while not adversely affecting life or the health of the environment throughout the required life of the field¹.