Monitoring Cathodic Protection System Performance in Deep Water Production Systems (Part 2)
by Jim Britton (2005)
This paper was originally written for the Corrosion 89 conference, put on by NACE. It was subsequently published in Materials Performance in 1990. In 2005, Mr. Britton wrote an update to address the changes in corrosion control technology for deep water production equipment that had taken place in the interim.
Increasing interest in deep water offshore areas has presented a whole set of new unsolved problems to the corrosion industry. Several programs are in progress which are attempting to formulate revised cathodic protection design criteria for the deep ocean. The lack of historical data, combined with the increased criticality of accurate corrosion control design in these areas, serve to accentuate the need to be able to monitor the performance of the cathodic protection system once installed. The structural designs being considered for deep water production also present new problems which cannot always be addressed with standard monitoring methods and technologies. This paper will identify some of these problems and offer some generic solutions which should serve to increase the overall reliability of future deep water corrosion control systems.
The Key Differences With Deep Water Operations
In many cases it is not the actual water depth but rather the nature of the production hardware that determines optimum maintenance and inspection strategies. For example truly deepwater fields (> 1000 M) there are two basic options for hardware selection:
1. Use “wet trees” and send production back through flow lines to a host production facility (Floater or Fixed Platform).
2. Use “dry trees” produce from floater in relatively close proximity to wells.
In either event there will be one thing in common, ROV’s will be the main tool for the majority of corrosion related subsea inspection and monitoring tasks. Thus we must determine where they can best interface into the scheme.
If a floater, which could be anyone of a number of configurations, is used. There will normally be additional classing society regulated inspection requirements. These will include hull integrity monitoring requirements not found on fixed production systems. Part if this process, normally termed In-Service Inspection, is a periodic “UWILD” or Underwater Inspection In-Lieu of Dry-docking. It is these regulated inspections where most hull and mooring system CP monitoring is achieved. These inspections are normally performed with an ROV, even though they are largely in diver depth range. The reason for this being overall efficiency of using a machine rather than a person.
Basic Monitoring Options
As with any other cathodic protection or corrosion monitoring application there are two general strategies, the most successful programs incorporate a combination of the two.
1. Portable Monitoring - Measurements made using portable instrumentation.
2. Permanent Monitoring - Measurements made with permanently mounted sensors.
There are a host of pros and cons between the two methods . But lets focus on the true strengths of each method.
Can provide a comprehensive survey of CP status, at time of inspection, over a large percentage of the structure where access with a portable device is practical. This is the preferred method for the following applications:
1. Baseline Surveys
2. Calibration of Permanent Devices
Provides the ability to remotely monitor system status, on a time base, with absolute point repeatability. This adds a predictive value to the data allowing trends to be more meaningfully tracked. The monitoring exercise is largely de-skilled with permanent systems giving a generally higher level of data reliability. Human and/or instrument calibration errors are eliminated. Having set the stage a quick review chronology of key advances (and dead ends) in the Offshore CP Monitoring business would be as listed below. Many of these innovations are described in greater detail  .
Brief Chronology of CP Monitoring of Offshore Corrosion
Circa 1972 First permanent monitoring systems (hard wired) installed on offshore structures. Mainly just reference electrodes. North Sea.
Circa 1975 First attempts to use acoustically linked data transmission. Never really practical due to battery life and cost. North Sea.
Circa 1979 First practical ROV’s with CP inspection capability and useful operational reliability. Main interest is on pipeline inspection to provide alternate to trailing wire inspections, known to be inaccurate. Early Probes were interesting affairs. North Sea.
Circa 1980 First three electrode survey performed on an offshore pipeline. This became survey method of choice for offshore pipelines, still in use today. North Sea.
Circa 1984 Improved contact ROV probes allow direct interface without digitizing. Gulf Of Mexico.
Circa 1985 First permanent offshore current density sensors deployed Gulf of Mexico.
Circa 1986 The first self bleed Zn – SW permanent reference electrode was installed. Reliability improved dramatically. Gulf of Mexico.
Circa 1988 First twin element probes put into service. Still the most widely used contact probe for ROV. Gulf of Mexico.
Circa 1990 First reliable anode current monitors and current density sensors deployed on deep fixed offshore structures. Gulf of Mexico.
Circa 1997 First Deepwater Self Contained ROV CP measurement system. Gulf of Mexico.
Circa 1998 Systems installed using subsea modems to transmit data in offshore pipelines.
Circa 2000 Self Contained ROV CP Measurement System modified to present form. Gulf of Mexico.
Circa 2000 The ultra-rugged reference electrode conductor was developed. Gulf of Mexico.
Circa 2004 The invention of the solar powered subsea test station. Gulf of Mexico.
Most of the instrumentation used for portable surveys is confined to the use of reference electrodes for potential or field gradient monitoring. The present systems used for ROV interface can be broadly divided into two types; Integrated and Self Contained.
An integrated instrument will send data to the surface as an analog or digital signal to be read on a surface instrument or logging system. This is the basis of most subsea pipeline inspection systems and much general purpose CP probes (Figure 1).