Unlike most offshore oil plays, the Black Sea provides an unique array of environmental conditions. These features include an anoxic environment below 200 meters, high concentrations of sulfate reducing bacteria (SRBs), methane vents, and geological instabilities. These conditions create diverse challenges to subsea equipment and pipelines that are unique within the offshore oil and gas basins of the world.
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.
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.
The region in which a pipeline transitions from offshore to onshore is called a shore crossing. Often, this shore crossing zone is not very well-defined and there is much uncertainty in terms of scope and responsibilities between onshore and offshore design teams. This inconsistency can lead to issues when designing cathodic protection (CP) systems for near shore and shore crossing areas.
It is often necessary to predict the performance of a specific material in a particular environment to determine the inherent corrosivity of the system. Such tests are often substantially different from those used for corrosion inhibitor qualification, particularly in the case of the corrosion testing of corrosion resistant alloys. Predicting corrosivity is especially important when designing subsea equipment, most of which is extremely challenging to repair or replace once it is installed. Corrosion testing is a widely used method of evaluating a material’s ability to withstand specific environmental conditions.
The first line of defense against microbial proliferation is the measurement of actively growing microorganisms. The medical and food industry have used genetic methods as a means of testing for years to obtain results more efficiently and effectively than culture methods; however, this has not been the case with the oil industry.
NACE TM0194 is the current standard followed by the industry for measuring bacteria in the system. This standard uses the Most Probable Number (MPN) method to quantify the bacteria in the sample. Typically, only a small percentage of the actual bacteria population grows in culture media in a laboratory and the test only quantifies what can grow in the laboratory media instead of what is actually in the sample. Results are obtained 14 to 28 days after the samples are inoculated, a major disadvantage if there is a real problem in the system.
As mentioned in Part 1, pigs are devices that travel through the pipeline and can be used for cleaning or maintenance purposes (utility pigs) as well as for gathering information about the condition, features and integrity of a pipeline (intelligent pigs).
Intelligent pigs are designed to identify different features or abnormalities as they travel through the pipe. Figure 1 briefly lists the functionalities for which intelligent pigs are commonly used. API 1160 and NACE RP0102 provide guidelines for selecting the appropriate tool for a given purpose. In this paper, the most commonly used In-Line Inspection (ILI) techniques, methodology and limitations applicable to detecting metal loss and wall thickness measurements are presented.
Corrosion in MEG systems predominantly results from carbon dioxide (CO2) and hydrogen sulfide (H2S) in the produced gas phase. However, it can also be associated with the presence of dissolved oxygen (O2) in the MEG. Corrosion results in the presence of dissolved iron, which may then deposit as scale. This can plug valves and compromise the performance of heat exchangers and MEG regeneration and reclamation systems.