Corrosion Assessment Guideline for Wellhead Facilities

For large number of wellhead facilities, the focus of corrosion management is to categorise the well according to the corrosion risks. The typical surface facilities associated with a well consist of the well head separator skid, associated measurement and control devices, relief and safety devices, and the fuel/instrument gas filtration systems, as well as all pipings. This includes well head separators, piping and valves starting from wing valves, which include service for

• gas stream,
• water stream, and
• gas/water stream.

The purpose of categorisation is to identify and group the surface facilities with similar corrosion environment for further corrosion management practices, i.e., monitoring practice, mitigation practice and risk based inspection practice. This step is to rank the equipment in relation to their corrosion environment and make it possible to identify options to assess, mitigate or manage the risks. This is a necessary precursor to strategic planning.

The corrosion assessment is to provide guideline on  category of well head surface facilities:

Corrosion Category = Process Corrosion Category X Field Factor

In which, process corrosion category is an empirical judgement based on model calculation, field history and operation experience. Location factor is a factor of field feature, which covers potential impact from both location and subsurface environment.

Flow Assisted Failure, parameter A

Assessment tools

• De Waard 95 model or its BP variant Cassandra 98 Model is used for FAC assessment
• DNV RPO501(DNV, 2007) is utilised as an assessment tool for mechanical metal loss

Process corrosion categories are assessed to determine the fluid corrosivity in a particular well head according to the following table.

Table Assesment points for corrosion mechanisms

	Erosion/FAC: Parameter A	MIC: Parameter B	Fluid Chemistry: Paramte rC
Location of Assessment
	piping bend in gas/water service	separator sediment and water outlet	upstream of choke valve in gas service for CO2
	downstream of chocking valve

Corrosion subcategories are defined through the combination of different level of process corrosion parameters. These subcategories are further combined into 4 process corrosion categories. A further 5^th corrosion process corrosion category is defined for well experiencing long term shut-in, work over or using corrosive fraccing fluid . Each wellhead surface facility is rated accordingly.

Criteria

Fluid velocity parameter incorporates the function of velocity, solids erosion, piping size and angle of impingement.

Level 1: Stratify flow

In this management plan, the flow causing following situation is taken as level 1 of parameter A:

• Predicted metal loss less than designed corrosion rate by De Waard 93 model (C de Waard U. L., 1993)or its BP variant Cassandra 98 (A J McMahon, 1997)(Hedges, 2005)
• Metal loss less than designed corrosion rate (both long-term corrosion rate and short-term corrosion rate) measured by on stream inspection

This is a velocity for lower water and/ or low gas production wells. In this flow condition, flow velocity neither cause metal loss nor accelerate metal loss. However, It may also prompt some types of corrosion locally such as TLC and MIC

Level 2: FAC range

In this management plan, level 2 FAC range is a dynamic range, in which CO2 corrosion rate under flow condition is over 0.05 mm/yr.

In this range, the velocity itself won’t cause significant metal loss. However, it is an accelerating factor on any existing corrosion mechanism, such as oxygen pitting, CO2 corrosion, galvanic corrosion, etc.

De Waard Milliams 95 model(C de Waard U. L., 1991 (47)) or its BP variation(A J McMahon, 1997) (Cassandra 98)(Hedges, 2005) will be utilised to assess the flow assisted corrosion.

Level 3: Erosive range

In this management plan, velocity causing metal loss over designed corrosion rate, which is taken as a Level 3: erosive range. In this level, the metal loss is considered as significant even there is no existence of other corrosion mechanisms. As the matter of fact, metal loss in a system has a tendency of acceleration due to surface roughening.

DNV RPO501(DNV, 2007) is utilised as an assessment tool for mechanical metal loss, in which factors such as fluid velocity, viscosity, solid content, PSD and piping materials will be taken into consideration. The erosive threshold is a well specific dynamic value, due to:

• Well configuration,
• Piping spec,
• Water rate,
• Gas rate,
• Solid content,
• Valve choking.

MIC status, parameter B

Assessment tool

MIC is the major concern for wells and well head surface facilities, the MIC status in this management is assessed based on results of testing, either by

1. ATP testing,
2. SRB, APB incubation tests,
3. The opportunistic inspection result with the wiping testing.This is a direct evidence of microbial status; even it cannot be obtained very frequently.

Criteria

Level 1: Negative MIC status

Evidence of the following items can be taken as MIC negative status for this management purpose:

• APN/SRB testing below 10³,
• ATP testing negative;
• Microbial sample from opportunistic inspection with negative results,
• Under regular biocide treatment schedule. High water velocity could not be taken as an evidence of negative MIC status since the existence of low velocity part in the system (dead end).

Level 2: Positive MIC status

One or more of following items with no biocide treatment can be taken as a positive MIC status for this management purpose:

• Well head water sample APB/SRB testing over2( incl);
• ATP testing with positive,
• biofilm is spotted during opportunistic inspection,
• Wiping sample from opportunistic inspection with positive results,
• Positively identification of corrosion caused by microbial activities.

Fluid chemistry, parameter C

Assessment tool

De Waard Milliams 93 model(C de Waard U. L., 1993) or its BP variant Cassandra 98 is utilised as an assessment tool for fluid chemistry.

Both gas chemistry and water chemistry are considered in this assesement.CO2 corrosion will be the major materials deterioration mechanism for CSG well head facilities based on the current experience of production. H2S will be a monitoring item only.

Criteria

Level 1: Non corrosive service

The general metal loss rate less than design corrosion rate (based on results of De Waard Milliams 93 model(C de Waard U. L., 1993)) is considered as non corrosive service in this management plan. The De Waard Milliams 93 model only considers the metal loss caused by fluid corrosivity with minimum influence of flow effects. The overall metal loss rate with flow effect is assessed in Fluid velocity.

Level 2: Corrosive service

The general metal loss over design corrosion rate (base on results of De Waard Milliams 93 model) is considered as a level 2, corrosive service in this management plan by considering CO2 partial pressure, H2S partial pressure in gas stream and pH in produced water stream.

The De Waard Milliams 93 model (C de Waard U. L., 1993)was utilised to assess the overall fluid corrosivity, in which CO2 partial pressure, H2S partial pressure and pH in the produced water are taken into consideration for corrosivity. These factors are fed into De Waard Milliams 93 model for further calculation of metal loss. The pH of produced water in wellhead is calculated based on model of IAEA (Mook, 2000) and verified with USGS PHREEQC program(David L. Parkhurst, 1999)

Other localise corrosion, parameter D
Assessment tool
a)    Document review,
b)    Inspection results review,
c)    Field operation experience review.
Criteria
Other localised factors include any non systematic issues around the system.

Level 1

• lower impact on localised corrosion factors,
• This is a default situation with no evidence of localised corrosion specified in level 2.

Level 2

• Higher impact on localised corrosion factors,
• Any of the following situations will be considered as higher impact in this management plan,
• Scheduled chemical injection in production, including antiscalant, biocide or corrosion inhibitor injection,
• Evidence of imperfect welding by QC report or baseline survey,
• Opportunistic inspection,
• Root cause analysis and metallurgical analysis,
• Visual inspection for geometry intrusion,
• Potential of oxygen ingression,
• Threaded connection,
• Misalignment of flange,
• Geological fault.