Subsea Tree Risk Based Inspection

  1. Subsea
  2. Production Facilities
  3. Production Engineering


A subsea tree is critical equipment in the subsea field. It consists primarily of a steel frame structure, connectors, valves, chokes, piping, tubing hanger, control systems, and a cap. The monitor data for a tree focus on the temperature, pressure, and sand conditions. The RBI for a subsea tree can be thought an extension of a pipeline RBI in that the methodology and principles are similar to those of the pipeline RBI. The differences are that the RBI for a tree focuses on the degradation of equipment and the failure analysis of the components according to the inspection data.

Subsea Tree RBI Process

This section gives an example of a subsea tree risk determination based on many assumptions. The following steps are carried out for a subsea tree RBI analysis:

  • Develop risk acceptance criteria.
  • Collect information.
  • Prepare a quantitative risk assessment.
  • Generate an inspection plan.
  • Input data into the inspection management system.

Collection of Information

The information collected for a subsea tree RBI includes design data, operation data, and a corrosion/erosion study report. These data are used to determine the PoF and CoF. These data are also used to predict the risk and establish an optimized inspection plan.

Risk Acceptance Criteria

Similar to the traditional pipeline RBI, the subsea equipment RBI risk bases its quantifications on the aspects of safety, environment, and economy. Most importantly, the safety class dependent on product, manned condition and location class. If the product is toxic or the location is in a sensitive area, then the safety class should be considered to be high. Economic consequences are concerned with repair costs and production losses due to the delay time.

Degradation Mechanisms and Failure Mode

The degradation mechanisms include primarily internal/external corrosion, internal erosion, flow assurance problems, and mechanical damage. In the OREDA database, subsea tree equipment is considered and failure data have been recorded. A subsea tree is divided into the following parts:

  • Chemical injection coupling;
  • Connector;
  • Debris cap;
  • Flow spool;
  • Hose (flexible piping);
  • Hydraulic coupling;
  • Piping (hard pipe);
  • Tree cap;
  • Tree guide frame;
  • Valve, check;
  • Valve, control;
  • Valve, other;
  • Valve, process isolation;
  • Valve utility isolation.


Tubing Hanger

  • Chemical injection coupling;
  • Hydraulic coupling;
  • Power/signal coupler;
  • Tubing hanger body;
  • Tubing hanger isolation plug.


In the OREDA, the failure mode of a tree consists of the following items:

  • External leakage-process medium;
  • External leakage-utility medium;
  • Fail to close/lock;
  • Fail to function on demand;
  • Fail to open/unlock;
  • Internal leakage-process medium;
  • Internal leakage-utility medium;
  • Leakage in closed position;
  • Loss of barrier;
  • Loss of redundancy;
  • No immediate effect;
  • Other;
  • Plugged/choked;
  • Spurious operation;
  • Structural failure.

Subsea Tree Risk Assessment

In subsea tree RBI assessment, the PoF will be determined for different failure mechanisms and consequences can be identified in terms of economic loss according to the repair times and repair costs.

Failure Database from 2002 OREDA Database

The 2002 OREDA database is used as our starting point in calculating PoF. In the OREDA database, the failure rate is presented in form of three categories: lower bound, best estimate, and upper bound. For the process, the table titled “Failure Descriptor versus Failure Mode,Wellhead & Xmas Tree” on page 835 of OREDA should be used as a reference for the failure data of the subsea tree components.

Failure Database Modification

The failure data are statistical results deduced fromthe 2002OREDAdatabase. Note, however, that individual subsea equipment may have quite different histories, properties, characteristics, and functions. Therefore, these values require further modification based on the special conditions and properties of the equipment in question and the experience of the engineer. For example, if the material is high-strength steel, material failure can be neglected. In the process of modification, the corrosion/erosion rate should be calculated. Flow assurance problems and operating conditions should also be analyzed.
Failure Descriptor versus Failure Mode for Christmas Tree

CoF Calculation

The consequence of the failure is mainly the economic loss due to the delay time and the repair costs. The delay time can be determined according to the OREDA database or the experience of the project engineers. In our example, we assume that the delay time is 2 days. Then the total economic loss can be identified according to the daily production capacity and repair costs and in this case the CoF assigned is A. The failure of tree components is unlikely to cause a large quantity of leakage. Leakage is limited by the quick reaction of extensive valves and sensors, so the main consequence is the economic loss due to the delay caused by the repair. The economic CoF of the tree can be analyzed on the base of:

  • Product type;
  • Flow rate;
  • Delay time of production.

Risk Determination

The risk associated with the tree is acceptable according to the assessment results.


Inspection Plan

Once the risk exceeds the acceptance risk, the subsea tree should be inspected according to the risk results. According to the inspection methodology, the failure data in the OREDA database should be modified according to the different operating phase conditions, and a different type of failure rate should be determined for the different operating phases, after which the risk can be identified for the different phases.

References

[1] M. Humphreys, Subsea Reliability Study into Subsea Isolation System, HSE, London, United Kingdom, 1997.

[2] Det NorskeVeritas, OREDA Offshore Reliability Data Handbook, fourth ed., Det Norske Veritas Industri Norge as DNV Technica, Norway, 2002.

[3] Mott MacDonald Ltd, PARLOC 2001, The Update of the Loss of Containment Data for Offshore Pipelines, fifth ed., HSE, London, United Kingdom, 2003.

[4] Norwegian Technology Standards Institution, CO2 Corrosion Rate Calculation Model, NORSOK Standard No. M-506, (2005).

[5] M.H. Stein, A.A. Chitale, G. Asher, H. Vaziri, Y. Sun, J.R. Collbert, Integrated Sand and Erosion Alarming on NaKika, Deepwater Gulf of Mexico, SPE 95516, 2005, SPE Annual Technical Conference and Exhibition, Dallas, Texas, 2005.

[6] O.H. Bjornoy, C. Jahre-Nilsen, O. Eriksen, K. Mork, RBI Planning for Pipelines Description of Approach, OMAE2001/PIPE-4008, OMAE 2001, Rio de Janeiro, Brazil, 2001.

[7] American Society of Mechanical Engineers, Manual for Determining the Remaining Strength of Corroded Pipelines, ASME B31G-1991, New York, 1991.

[8] Det Norske Veritas, Corroded Pipelines, DNV-RP-F101, 2004.


...