SPE 123790 - Planning and Procedures for the Initial Startup of Subsea Production Systems

2010 Summary, H.J. Duhon, J.L. Garduno, and N.A. Robinson, GATE

Projects progress through phases of design, construction, installation, commissioning, initial startup, and operations. This paper addresses issues that arise at initial startup. Initial startup is defined here as the period when reservoir hydrocarbons are produced for the first time.

Initial startup of a subsea development is one of the most challenging periods in the operational life of the facility. Many issues complicate this period, including

People issues. Many people from many teams are required to execute a startup; roles and responsibilities may be unclear and will change over the course of the startup; persons-onboard (POB) issues limit the number of people who can participate; personnel involved may not be fully trained in the operation of the facility.

This will be the first time much or all of the equipment is used in live hydrocarbon service. Design flaws, commissioning omissions, and infant mortalities will reveal themselves.

Preserving completion integrity requires low rates and slow bean-ups during initial startup because of high formation skin. Chokes designed for high rates and low pressure drops may not be capable of controlling the well at low rates. Also, topside systems designed for peak rates may not function well at low flow rates.

Low flow rates and low initial temperatures result in hydrate risk, which may challenge the flow-assurance strategy.

Completion and stimulation fluids returned during the initial well cleanup are corrosive and are difficult to treat. Typically, specialized water-treatment equipment is installed temporarily at topside to treat these fluids. The flowback fluids may also contain solids from the reservoir and from construction debris that may cause problems such as plugging small ports in control valves.

Source: SPE Projects, Facilities & Construction, Volume 5, Number 4, December  2010

Copyright 2010. Society of Petroleum Engineers

SPE 120735 - Why We Don't Learn All We Should From HAZOPs

2010 Summary, Howard J. Duhon, SPE, GATE, and Ian Sutton, AMEC Paragon

During the last 15 years, the process industries have made dramatic improvements in occupational safety. Recordable injury rates have dropped by close to an order of magnitude (Pitlblado 2008). Accurate information pertaining to progress in process safety in the same time period is not available. However, it is likely that improvements in process safety are not nearly so great (Sutton 2010).

From its beginnings in the late 1980s and early 1990s, hazards analysis has been a key item in all process safety programs. After all, if hazards are not identified, they cannot be remediated. Of the various hazards-analysis techniques, the Hazard and Operability Method (HAZOP) has probably gained the greatest acceptance. Therefore, if the process industries are to achieve the same levels of success in process safety as they have in occupational-safety improvements, the effective use of HAZOPs is probably going to be of central importance.

This paper discusses some of the cognitive, social, organizational, and procedural factors that limit the effectiveness of projects in general and of HAZOPs in particular. From this discussion, insights can be developed that can provide ideas for improving the HAZOP process and process-safety-management systems in general.

Source: SPE Projects, Facilities & Construction, Volume 5, Number 2, June  2010


SPE 125785 - Effect of THPS on Discharge Water Quality: A Lessons Learned Study

2010 Abstract, Karthik Annadorai, SPE; Adam Darwin, GATE, LLC

Biocides typically have an adverse impact on overboard water. THPS (tetrakishydroxymethyl phosphonium sulfate), one of the most commonly used biocides offshore has a similar effect on produced water. The effect of THPS on seawater used for hydrotesting and bulk storage is seldom studied and rarely documented. The effect of temperature, pH, water depth, dissolved oxygen concentration and various ions in the system is important to note. Once a certain volume of water is treated with any chemical, it is now deemed to be chemically treated seawater which cannot be discharged unless verified using the NOEC (No Observable Effect Concentration) testing method.

This experience will provide a detailed understanding of the discharge of chemically treated seawater as well as the interaction of THPS with potential ions in the matrix. Additionally, regular sampling and associated analyses will be presented that demonstrate the degradation and half-life of the THPS molecule in varying temperatures.

Periodic sampling of the THPS chemical in the seawater has provided a detailed understanding of the half-life degradation of the chemical. The interaction of the chemical with the cations present in the system and subsequent aversion to the neutralization reaction with hydrogen peroxide has also been studied and presented.

Source: SPE International Conference on Health, Safety and Environment in Oil and Gas Exploration and Production, 12-14 April 2010, Rio de Janeiro, Brazil

Copyright 2010. Society of Petroleum Engineers

NACE 10401 - Prevention Of Corrosion In Carbon Steel Pipelines Containing Hydrotest Water - An Overview

2010 Abstract, Adam Darwin, Karthik Annadorai, Gibson Applied Technology and Engineering, LLC; Krista Heidersbach, Chevron Energy Technology Center

A critical step in proving a pipeline is fit for operational use is the hydrostatic test, in which it is filled with water and pressurized to 125% of its Maximum Allowable Operating Pressure (MAOP). The water that is used in this testing can cause corrosion of the pipe, potentially leading to failure early in its operating life. Failures have occasionally been reported even before a pipeline enters service.

The most common mechanisms by which carbon steel pipelines may undergo corrosion on exposure to hydrotest water are Microbially Induced Corrosion (MIC), oxygen-related corrosion, galvanic corrosion and under-deposit corrosion. An overview of these mechanisms is presented, along with a discussion of the influence of different environmental factors on them. Factors considered include water source, degree of filtration, exposure period and temperature, air pockets, presence of internal pipe coatings and future pipeline service conditions.

Maintaining the risk of pipe corrosion from hydrotest water within acceptable limits is discussed. Factors considered are:

How long the untreated water may be allowed to be present in the pipeline.

Should water treatment be required, what must be used?

Disposal requirements for the treated water, including chemical treatments.

Source: CORROSION 2010, March 14 - 18, 2010 , San Antonio, TX

Copyright 2010. NACE International