4/8/2014
Pre-commissioning and Commissioning of Pipeline
Saurabh Sharma 500042965
TABLE OF CONTENTS
1.
INTRODUCTION
2.
PRE-COMMISSIONING
2.1 Filling 2.2 Pipeline Cleaning 2.3 Pipeline Gauging 2.4 Hydro-testing 2.5 Points to Note 3.
COMMISSIONING
3.1 Dewatering 3.2 Drying 3.2.1 Air Drying 3.2.2 Vacuum Drying 3.2.3 Liquid Swabbing 4.
PRODUCT INTRODUCTION
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PRE-COMMISSIONING AND COMMISSIONING
1. INTRODUCTION Soon after the installation of a pipeline system and prior to introduction of hydrocarbon product, the system has to go through a pre-commissioning and commissioning phases. Pre-commissioning involves cleaning and confirmation of the pipeline system’s mechanical strength and integrity. Pipeline system then undergoes a commissioning phase that involves flushing and drying the pipeline and finally introducing the product. Specialist contractors perform work for both phases.
2. PRE-COMMISSIONING Pipeline pre-commissioning relates to activities that start with pipeline cleaning and testing. These activities are normally carried out soon after pipeline installation and continue until the pipeline integrity has been established. The main aim of this phase is to ensure that the pipeline is not damaged during installation and that it has the required mechanical strength. The pre-commissioning activities include the following: • • • •
Filling with inhibited water Cleaning Gauging Hydro-testing
When the pipeline is laid, the start-up and lay-down heads usually co ntain a number of pigs. The type and number of pigs are determined by the requirements of pre-commissioning activities. In some situations, a pipeline is installed in one construction season and tie-ins are performed later. It is advisable to carry out the pre-commissioning activities on that pipeline section soon after installation.
2.1 Filling After the pipeline is installed on the seabed, it is generally fil led with clean water (filtered water) that is mixed with corrosion inhibitors and a fluorescent dye as per project specifications. The type and amount of inhibitors depend on pipe material, local environment and duration for which the seawater will stay in the pipeline. The specialist pipeline hydro-testing contractors determine these chemicals and the quantities. The fluorescent dye is introduced to facilitate detection of a leak.
2.2 Pipeline Cleaning Pipeline internal cleaning is generally performed soon after filling the pipeline with the inhibited clean water. The pipeline ends are attached with start-up and laydown heads that may contain a variety of pigs. These pigs are pushed, by inhibited clean water, from one end of the pipeline and push all debris, etc., towards the other end. If the pipe internal surface is coated, scrapper or brush pigs should not be used. Instead of water, special gels or chemicals may also be used depending the conditions but these are very costly and rarely used only for short length pipelines.
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An Example of Pipeline Cleaning
2.3 Pipeline Gauging Initially, the pipeline is gauged during installation to check if it is dented during installation using a gauging pig. During pre-commissioning, another gauging pig is run through the pipeline to confirm the pipeline condition. The gauging pig fitted with a pinger is generally launched into the pipeline after the third cleaning pig. The diameter of the gauging plate is generally 95% of the nominal inside diameter of the pipeline.
A Typical Gauging Pig
2.4 Hydro-testing After the completion of cleaning and gauging operations, the pipeline is subjected to a hydrostatic test to confirm the strength and integrity of the completed pipeline. Hydro -test consists in testing the pipeline by subjecting it to an internal pressure much higher than the design pressure for certain duration. During hydro-test, the pipeline is pressurised to a level that would generate a pipe wall hoop stress of at least 90 % of the specified minimum yield strength of the pipe material based on the un-corroded wall thickness. If the wall thickness is based on an allowable hoop stress of 72 % of the specified
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minimum yield strength, the corresponding hydro-test pressure will be 1.25 times the design pressure. Hydro-test pressure must satisfy the applicable design co de requirements. The foregoing test pressure is based on BS PD 8010 and ASME B31.3/31.8. The test pressure requirements may be different in other codes so one must determine it for the applicable design code. Since a riser is designed for a hoop stress of 60% of SMYS, the corresponding test pressure for the riser only will be 150% of design pressure. The internal pressure in the pipeline is raised in several stages to the pre-calculated level. This is to allow all the entrenched air to be pushed out completely. The internal pressure is continuously monitored and allowed to be stabilised at each stage. After the internal pressure has stabilised at the hydro-test pressure, the pressure is maintained for at least 24 hours. Variations in the ambient temperature can affect the internal pressure. Therefore, the pressure and temperature are continuously monitored at close intervals of time as per the specifications. If a drop in pressure is observed that is in excess of that expected due to the temperature variations, the cause of such pressure drop is thoroughly investigated. The pressure drop could occur due to malfunctioning of test equipment or from a leak in the pipeline. If the drop is caused due to a leak in the pipeline, the leak is detected by searching for the fluorescent dye and the pipeline is de-pressurised, repaired and rehydro-tested.
2.5 Points to Note As was pointed out earlier in this section, pre-commissioning activities are carried out by specialist contractors. However, the design engineer specif ies the requirements and provides the necessary data including the hydro-test pressure. Following points may be noted • • •
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• •
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All chemicals used during pre-commissioning must be environmentally friendly and should not harm the sea life. A chemical that can harm the pipeline system must not be used. In certain circumstances, pipeline may have to be left full of water until tie-in is completed; this period may as long as 12 or more months. Ensure that the water has sufficient quantity of appropriate inhibitors. Installation contractors do not accept responsibility for a pipeline if there are long delays between installation and tie-ins. Client must take on responsibility for the installed pipeline only after the contractor has proven pipeline integrity by hydro-testing the pipeline. Tie-in completions after long time gaps will make it necessary to hydro-test the completed pipeline system. If each component of a pipeline system is individually hydro-tested and the tie-ins are performed by ‘golden welds’, full hydro-test of the completed system may not be necessary if tie-ins are completed soon after the hydro-test of the components. A system test may be required at 110% design pressure. A contractor may offer to perform a single hydro-test of the completed pipeline system in order to reduce costs and schedule. This may be evaluated with full consideration given to liabilities. A pipeline system may contain components of different strength. For example, the subsea pipeline is designed for an allowable hoop stress factor of 0.72 while the riser design factor may be 0.6. The test pressure must be based on a pressure that produces a hoop stress of 90 % of specified minimum yield strength in the weaker section, i.e., the pipeline. If the riser is
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tested on its own, the test pressure could be 1.5 times the design pressure while for the combined riser and for subsea pipeline, it will be 1.25 times the design pressure. If the actual wall thickness is greater than the design wall thickness, it is justifi able to test the pipeline at a higher pressure.
3. COMMISSIONING Before the hydrocarbons can be introduced into a pipeline system, the water remaining in the pipeline system must be removed and the pipeline dried internally to a certain level as determined by the pipeline operational criteria. The pipeline commissioning c omprises the following three stages: • • •
Dewatering Drying Introduction of product
The commissioning activities are again performed by specialist contractors who should be fully involved in planning the whole o peration. It is pointed out that gas pipeline commissioning is generally more hazardous compared to an oil pipeline.
3.1 Dewatering Dewatering is normally carried out by propelling a train of pipeline pigs through the pipeline using air or some inert gas. The type and size of pumps and other equipment to push the pigs with air depends on the pipe size and pipeline length. The number of pigs in a train or how many times the pig trains are run depends on the drying requirements in general. A film thickness of 0.05 mm to 0.2 mm is often left on the inside surface of the pipeline without the internal coating. Thinner film thickness is expected in an internally coated pipe. Disposal o f water will be subject to approval o f local and federal regulations. Inhibited seawater is generally discharged into the sea but environmental considerations may require it to be discharged at least 2 km away from the shore. Therefore, it is a common practice to push the dewatering pigs from onshore if the pipeline is between an offshore facility and an o nshore facility. Seabed undulations can cause water to collect in the low spots of the pipeline leading to difficulties in achieving the required dryness in the pipeline. In such cases, foam pigs may be used. The selection of pigs to be used for dewatering is important in reducing the amount of water left in the pipeline.
3.2 Drying The degree of dryness of the internal surface prior to the introduction of the product depends on the product to be piped. For gas pipelines, the dryness levels are generally higher. For example, the usual requirement for gas pipeline transporting dry gas, is that water content should not exceed 4 lb/MMSCF at the design pressure and for a dew point of –2o C, and also at the atmospheric pressure and a dew point of –47o C. For oil pipelines, further drying of pipeline after the removal of all free water may not be required. However, further drying of gas pipelines is necessary unless the pipeline is to carry multi-phase wet mainly gas product. 5
Three methods are generally used for drying gas pipelines: • • •
Air drying Vacuum drying Liquid Swabbing
A variation of the third method involves dewatering and drying by liquid swabbing in a single pass. The selection of a suitable method depends on several factors: • • • • • • • •
System design Location Level of dryness required Facilities available Environmental concerns Timing Logistics Cost effectiveness
For gas pipeline, after the pipeline is dried to the required level, it is filled with nitrogen that is an inert gas. It is advisable to dry the pipeline shortly before the product is to be introduced to minimise the possibility of condensation. Commissioning contractor determines the size of pumps and other equipment. Preliminary studies must be done at the design stage to determine possible methods for drying in consultation with specialist contractors.
3.2.1 AIR DRYING The method involves the vaporisation of the remaining thin water layer after the dewatering by pushing dry air through the pipeline using air compressors and dryers. Dry air is pushed through one end of the pipeline and vapours are evacuated through the o ther end. During the air drying o perations, foam pigs are periodically passed through the pipeline to remove free water and to distribute the residual water to improve evaporation. Some of the advantages/disadvantages of the air drying method are: ADVANTAGES: • •
Generally cheaper and could be quicker than other methods Independent of the requirement of hydrocarbon product
DISADVANTAGES: • • • • • •
Difficult to assess free water that may be remaining in the pipeline Extensive spread required including the large compressors and other equipment with a substantial need of space and fuel Dew point reading can be difficult to interpret reliably Large amounts of nitrogen required to purge the pipeline, particularly for gas pipelines Very noisy due to large air compressors, environmental problems could occur. Not suitable if dew point temperature is below –25° C, particularly in tropical areas
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3.2.2 VACUUM DRYING In this method, vaporisation is achieved by lowering the pressure inside the pipeline to a level where the water starts to boil at the ambient temperature of the environment. Boiling of a liquid occurs when the saturation vapour pressure exceeds the external pressure. The amount of water removed through this process depends on the lowest pressure that the vacuum generation equipment can create. It is pointed out that the internal pressure cannot lowered to a level where the external pressure due to the hydrostatic head will lead to pipeline collapse. Drying of the pipeline does not occur uniformly or simultaneously along the whole length; it takes place in a drying front that moves down along the pipeline towards the outlet. ADVANTAGES: • • • •
More reliable than the air drying method Commonly used Independent of the product More suitable than air drying if very low dew point temperature is required
DISADVANTAGES: • • • • • •
Lengthy procedure Very time consuming particularly for long large diameter pipelines Large area required for equipment High noise levels due to pumps and compressors Nitrogen purging may be required if the product is not introduced in the pipeline within a short period of drying Initial air drying may be required to reduce the amount of water to be evaporated by vacuum drying
3.2.3 LIQUID SWABBING Liquid swabbing is commonly used for drying onshore pipelines. In this method, the water film remaining in the pipeline is removed by diluting it with a solvent. The solvents used commonly are methanol or glycol. The pipeline is swabbed by a series of solvent batches contained between pigs and driven by dry nitrogen or compressed dry air. If dry air is used, purging of the pipeline with nitrogen may be required if the product to be transported is dry gas. This method does not remove all of the free water but prevents hydrate formation due to a heavy dose of de-hydrate chemicals in the thin film that might remain. The remaining water is picked up by the dry product over a period o f operation. A variation of the liquid swabbing method was used in a large diameter gas pipeline. After hydrotesting, simultaneous dewatering and liquid swabbing was carried out. The f irst train of pigs comprised series dewatering pigs followed by batches of swabbing liquid. This was followed by batches of nitrogen and lastly the transported gas. ADVANTAGES: • •
Faster method than air or vacuum drying Independent of product
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DISADVANTAGES: • • • • • • • •
Not commonly used for offshore pipelines Does not remove all free water Difficult to recover solvents Glycol is difficult to distribute Glycol is expensive but can be recycled Methanol is less expensive than glycol but cannot be recycled Methanol is very volatile Large amount of nitrogen may be required
4. PRODUCT INTRODUCTION After the pipeline has been dewatered and dried to the requisite level, preparations are made for the introduction of hydrocarbons usually from the producing offshore facility. The hydrocarbons to be introduced could be highly inflammable or hydrates may form during the filling operations. A hydrocarbon such as the gas can cause explosion if it comes into contact with ai r, so it is advisable to introduce a batch of inert gas such as nitrogen in front of the product. This is a definite requirement for gas or gas/condensate pipelines. The product is introduced in stages. The product injection rates are controlled to minimise transients and that pressure and temperature do not exceed allowable limits for the pipeline material or the dew point conditions. The injection rates are determined during hydraulic analysis for start-up.
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