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.
Top of line corrosion primarily occurs in wet gas systems when water vapor condenses on the internal walls of the pipeline due to the heat exchange occurring between the pipe wall and the colder ambient medium. As the liquid condenses on the internal pipe wall, the concentration of the acid gases and organic acids (naturally present in the gas stream) in the liquid increases. Thereby the pH value of the condensed water drops turning the water corrosive.
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.
Blockage remediation methods vary widely depending on the nature and location of the blockage, available facilities, targeted outcome(s) and costs involved. In Blockage Remediation Part 1: Blockage Characterization and Detection, we discussed the importance of correctly understanding the nature of a blockage in order to formulate an effective remediation solution.
This GATEKEEPER will focus on commonly applied remediation methodologies used in the industry, as well as discuss the GATE blockage remediation approach.
In spite of robust design, adequate infrastructure and a well planned and executed operating strategy, partial or fully blocked pipelines, with loss of production in many cases, is a reality. This series of two articles discusses the diagnosis, detection and remediation of oil and gas production system blockages in detail. The current issue focusses on blockage characterization and detection.
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.
Liquid loading is one of the major challenges faced by shale gas producers. This phenomenon occurs when the gas in-situ velocity is insufficient to carry the produced liquid, leading to liquid fallback in the wellbore. Liquid Loading can occur during the flowback phase, the phase where the well is producing liquid from hydraulic fracturing, as well as the production phase, and is known to cause premature gas production decline, as shown in Figure 1, as well as production instability and flow assurance issues.
In the previous parts of this series, it was established that wax deposition is an issue that arises whenever an oil composition containing appreciable wax content encounters flow, temperature, and pressure that are conducive for solids formation. The effective development of wax management strategies during Front End Engineering Design (FEED) can serve to mitigate or perhaps even prevent the high costs associated with wax remediation.
Wax deposition modeling is essential to estimate the wax deposit thickness over time in support of wax management strategy development for susceptible systems. The objective of this GATEKEEPER is to provide a high-level overview of the model commonly used in the industry to estimate the wax deposition.