In the last GATEKEEPER, we determined the top of line corrosion (TOLC) rate along with the top of line water condensation rate. Now its time to assess the TOLC risk and the corresponding locations in the system where TOLC may occur. From there we can determine the appropriate mitigation and control strategies.
Integrity Management (IM) planning is a challenge that is currently center-stage with oil and gas operators as the downturn has led to focused attention on extending the life of existing assets while optimizing ongoing operating expenditure. This is particularly true in the deepwater basins of the world, where capital costs are high, the cycle time to deliver new facilities is long, and the life extension of existing assets to support hub and spoke tieback developments is often commercially favorable.
Operating a facility comes with multiple aspects of technical and business goals. One common goal is to maintain production at maximum while minimizing cost, and it is only achievable if the pertinent risks are properly assessed, whether it is aligned with an “operate-to-failure” or a “prevent-at-all-cost” philosophy. Identifying and mapping the risks eliminate having to act without proper knowledge within a limited reaction time. Therefore, a risk based inspection (RBI) can be defined as the control mechanism of a proactive and predictive integrity management of a facility, where proper allocation of resources can be planned and accounted for. This means the inspection strategy is driven by risk and prioritized for the high-risk equipment.
The acids used in downhole treatments are expected to induce severe corrosion attack on production tubing, downhole tools and casing, even though the anticipated contact times are kept short. To reduce the aggressive attack of the acid on tubing and casing materials, corrosion inhibitors are added to the acid solution. Even through inhibitors are known to provide some corrosion protection, they are usually effective only at high concentrations.
Development of an integrity management program is initiated during design phase, which includes selecting the appropriate materials, establishing requirements for corrosion, erosion, flow assurance and process along with associated maintenance, monitoring and surveillance requirements. In this GATEKEEPER, the philosophy around the materials selection and corrosion monitoring is discussed as the primary design barrier to corrosion and cracking in critical parts of a subsea system.
American Petroleum Institute (API) 5CT high strength steels are extensively used for casing strings inwells subjected to high cyclic hydraulic fracturing loads. While non-sour grades of API steel such as P110 casing strings have been used satisfactorily for well construction, standard API P110 connections have seen higher rates of failures than pipe body failures in shale wells that require hydraulic fracturing.
Mercury is commonly found in gas processing systems (midstream) and oil and gas fields throughout the world. Mercury is toxic to life and can have deleterious effects to several alloys commonly used in oil and gas production and refining industries.
Offshore components often suffer from corrosion due to exposure to environments such as seawater, produced water, solvents, oxygen, CO2, H2S and other acids and abrasive particles. To protect equipment from degradation, coatings are applied to internal and external surfaces to provide electrical insulation, physical protection and corrosion and/or chemical resistance. Coatings can also provide thermal insulation, anti-slip, color coding, flame-retardant and anti-bio-fouling qualities to a given surface. This GATEKEEPER provides a general overview of the epoxy coatings used in offshore oil and gas service and discusses common causes of premature coating failure as well as factors affect coating quality.
Triaxial evaluation of wellbore loads is used extensively for casing and tubing string design and analysis. A triaxial based collapse strength method was recently adopted by the American Petroleum Institute (API), and an addendum issued to API Technical Report 5C3 (TR 5C3). The triaxial based collapse formula incorporates internal pressure and axial load into the calculation of casing and tubing collapse strengths. Casing and tubing that are subjected to combined loads have higher collapse strength than previous formulas would predict, permitting the use of thinner walled, or lower strength, pipe than formerly required.
Titanium (Ti) alloys are attractive to subsea oil and gas operators due to their high strength, low density relative to steel, and innate corrosion resistance. The current primary application for Ti alloys has been in tapered stress joints (TSJs). Ti stress joints are a primary and sole barrier to loss of a riser and release of hydrocarbons into the environment. Therefore, the integrity of the TSJ is of utmost importance, and integrity loss of a TSJ carries a very high inherent risk.
Annulus Pressure Management refers to an engineered approach ensure that casing annulus pressures do not challenge the well’s integrity during the life of the well. The aim is to maintain the casing pressure within the well’s mechanical design limits at all times by controlling the ‘A’ annulus pressure.
The ‘A’ annulus is the annular space between the production tubing and the first string of casing (i.e. production casing) as shown in Figure 1. In subsea wells, the ‘A’ annulus is the only annulus that can be monitored and controlled.
The increased use of dynamic risers as an enabling technology for the movement of the oil and gas industry into the deepwater basins of the world has presented new technical challenges related to the prevention of corrosion failures and other forms of degradation. This has been particularly evident when considering production from the next generation of high pressure/ high temperature (HP/HT) subsea developments in locations such as the Lower Tertiary trend in the Gulf of Mexico. In order to avoid potential riser failures or replacement campaigns for anticipated service lives that may extend to 30 years or more, process facility components such as risers and flowline systems must now be subjected to more enhanced integrity monitoring through the whole of their service life.