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.
Top of Line (TOL) corrosion occurs in multiphase wet gas systems when water vapor contained in the gas phase condenses on the internal upper pipe walls. This happens due to the heat exchange occurring between the pipe and colder surroundings (river water, seawater or cold air) if the pipe is not thermally insulated or buried at a reasonable depth. The condensed liquid then becomes enriched by the corrosive species naturally present in the gas stream and assumes a low pH because it does not contain any buffering species such as bicarbonate or iron. The predominant concern is carbon dioxide (CO2), which reacts with water to form carbonic acid (H2CO3), although hydrogen sulfide (H2S) can also present significant challenges. As TOL corrosion occurs in wet gas lines operated in stratified flow, the corrosion inhibitor or other corrosion protection chemicals such as mono-ethylene glycol (MEG) injected into the system remain at the bottom of the line and are not able to protect the top of the line.
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.
A great deal of work goes into making operating procedures accurate, but a procedure that is accurately written may be implemented incorrectly.
Studies suggest that humans conducting simple, mundane tasks make an error roughly 1% of the time. Error rates for complex tasks are much higher. Some procedures are more error-prone than others. It is incumbent upon us to write procedures that are not only accurate, but that are likely to be implemented without error.
The airline industry has dramatically decreased the incidence of human error, in part by focusing on development of effective procedures and on instilling a culture in which the procedures are actually used. We can do the same in the oil industry.
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.
It comes up very often in projects—”Why can’t the construction team do the commissioning”. On smaller projects this may be acceptable with an experienced team and involvement with operations, but for major capital projects it pays to have a dedicated seasoned commissioning team to execute pre-commissioning and commissioning work.
Asphaltenes are large, complex organic components present in the oil phase, along with resins, aromatic hydrocarbons, and alkanes (saturated hydrocarbons). Resins play an important role in stabilizing asphaltenes in crude oil. When the resins get destabilized, (under unfavorable pressure-temperature conditions) asphaltenes can agglomerate and deposit.
Produced water overboard discharge is permitted in much of the world, but is subject to discharge limits. In the Gulf of Mexico (GoM), oil and grease (O&G) in produced water is limited to 29 mg/l average and 42 mg/l for excursions. Similar limits are in place in much of the rest of the world. O&G consists mainly of dispersed organics, but some organics dissolve in water in measurable concentrations. Produced water separation systems focus on removing dispersed oil via gravity-based separation methods. These work effectively on dispersed, O&G; however, these systems do not effectively remove water soluble organics (WSOs). Where WSOs exist in concentrations greater than 29 mg/l, conventional produced water treating systems cannot achieve GoM overboard discharge limits.
Methanol (MeOH) is widely used in multiple applications in the offshore oil and gas industry. MeOH has three primary applications offshore:
- Hydrate inhibition during well start-up.
- Displacement of trees, well jumpers and well tubing (bullheading) for hydrate inhibition during shutdown operations.
- To equalize differential pressure across subsea valves.
The target MeOH concentration required to inhibit hydrates is commonly 25 to 50% by volume in produced water (0.5 to 1 barrel MeOH per barrel water).
It is typical practice for offshore oil production facilities to treat and dispose of produced water via overboard discharge, making MeOH one of the highest volume discharges of production-treating chemicals. Considering the significant volumes and concentrations described above, it becomes necessary for every asset to consider the environmental effects of MeOH overboard discharge and to assess appropriate mitigation strategies, as required.
Hydrates and hydrate plugs can restrict flow, damage equipment, and potentially jeopardize the safety of personnel. Hydrates are formed as a result of the bond between gas and water molecules that occur at high-pressure, low-temperature environments. In deepwater, hydrates can form at temperatures higher than the ambient seabed temperature; hence, prevention and remediation of hydrates is a serious concern for deepwater operators.
The difficulty in selecting the materials of construction for the topsides portion of seawater injection systems is associated with uncertainty around the reliability and performance of their associated oxygen removal systems.
Common material selection options for seawater injection systems include carbon steel, stainless steels, copper-based alloys, and composites. Other materials, such as titanium and high nickel alloys, may be used in niche applications, but their increased cost ensures that these are not the first line materials of choice.