Bacteria inhabit the vast majority of oilfield water systems. These may either be attached to the pipe wall (i.e. sessile bacteria) or free floating through the system (i.e. planktonic bacteria). Planktonic bacteria do not directly contribute to the microbiologically induced corrosion (MIC) of pipeline systems; however, planktonic bacteria can attach to the pipe wall under the right conditions, becoming sessile bacteria. Consequently, there is some value in monitoring planktonic bacteria activity in a pipeline, although it is substantially less beneficial than monitoring the sessile population activity.
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.
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.
Paraffin precipitation and deposition in flowlines and pipelines is an issue impacting the development of deepwater subsea hydrocarbon reservoirs. The buildup of paraffin deposits decreases the pipeline cross-sectional area, restricts operating capacities, and places additional strain on pumping equipment.
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.
Operators and chemical vendors responsible for chemical delivery to subsea developments are aware that the use of chemicals with unacceptable solids loadings can result in the plugging of injection lines, subsea metering systems, subsea connectors, and downhole injection locations. However, there is relatively little agreement across the industry regarding the exact chemical cleanliness specifications that need to be applied.
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.
As of October 1, 2012, the Environmental Protection Agency (EPA) Region 6 has enacted an update to their National Pollutant Discharge Elimination System (NPDES) general permit for new and existing sources in the western portion of the Outer Continental Shelf (OCS) in the Gulf of Mexico (GoM). The issue date of this GATEKEEPER has been postponed a little to cover this issue, due to the profound impact of environmental discharge legislation on production and water discharge activities. This general permit sets the requirements for all controlled discharges from drilling and production units in the GoM from October 1, 2012, to September 30, 2017. However, Operators have until January 31, 2013 to align their procedures with the new requirements and file a Notice of Intent to the EPA for discharges covered by the permit.
It is frequently necessary to displace the contents of a pipeline or umbilical tube (fluid B) with another fluid (fluid A). If we don’t use a pig to separate the liquids, there will be mixing at the interface (axial mixing). The mixing zone requires us to overflush the line to effectively remove fluid B from the line. Below, we address a method of calculating the length of the mixing zone in order to determine the effective overflush requirement for a given pipeline or umbilical tube.