Natural gas produced from underground reservoirs varies in its composition depending on the type, depth, and location of the underground deposit and the geology of the area. Natural gas is usually considered sour if the hydrogen sulphide (H2S) content exceed a certain threshold. And the term acid gas is usually used if it contains acidic gases e.g. carbon dioxide (CO2). Natural gas is called sweet gas when it is relatively free of H2S and CO2. The contaminants in natural gas needs to be treated or maintained within a certain limit as per the required pipeline quality for exports and sales. In Sarawak Gas Operations, the contaminants is being managed by means of integrated gas blending. Field B is one of the deepest platform-type carbonate gas reservoir in Central Luconia Province, offshore Sarawak with highest level of contaminants i.e. 40 mol% of CO2 and 2800 ppm of H2S. Sampling at more frequent interval of twice a year is implemented to monitor the trending of the contaminants level which will give perception on the effective blending management and maximum gas recovery. The strategy to produce as much as sour gas first while ample sweet gas is available to achieve maximum overall gas recovery is well understood. Observation on the trending for more than 10 years suggest that the level of contaminants is increasing by time and the field is souring. This finding is supported by the understanding of CO2 and H2S solubility in water which is higher as compared to hydrocarbon gases. The suspected mechanism for the reservoir souring is the changes in CO2 and H2S solubility in water with pressure change. This paper summarises the main issue of increasing contaminants level and effort to maximise gas recovery from the souring reservoir and discusses on the results from contaminants level trending and example from analogue field.
When the oil and gas price was declining rapidly in 2016, it is prudent for global oil operator to identify opportunity to reduce the development cost. This is where all form of cost optimisation and holistic design approach have to be conducted, especially when dealing with High Pressure and High Temperature (HPHT) pipeline which normally requires higher CAPEX. Referring to a field case example from one of PETRONAS’s HPHT pipeline project in Malaysia waters, initial analysis had identified that a 24-inch subsea FWS HPHT pipeline with 40mm concrete coating thickness (for its on-bottom stability requirement), requires three numbers of ‘buckle trigger’s in order to manage the pipeline lateral buckling issues. Hence, a holistic design approach had been conducted to re-evaluate such requirement, commenced with detail assessment to look for all possible opportunities to reduce the pipeline temperature, one of it is to have a greater heat transfer from the pipeline. This exercise had landed into detail assessment on the pipeline on-bottom stability requirement which resulted in indication that the 24-inch FWS pipeline, that have a thicker wall thickness at the upstream portion, would be self-stabled - no requirement for concrete weight coating. Thus, benefitting from the results, further detail analysis had been conducted to assess the overall heat transfer from the pipeline as well as the impact towards the pipeline lateral buckling design, which lead to elimination of lateral buckling mitigation requirement. Unfortunately, further analysis had shown that in the absent of concrete weight coating, the pipeline un-concrete weight coated section i.e. hot end area and the field joints, would have rapid condensation and exposed to the intolerable top of line corrosion risk. Also, based on past experience with local installation contractor, there will be possibility of installation issue for the un-concrete coated pipeline with the tapered bracelet anode. Following that, thorough analysis had been performed and successfully mitigated the issue by applying field joint coating material with U-Value of 52 W/m2K to the 3LPP-Coated linepipe. As for the subsea flange connection, it is covered with thermal insulation, whereas the anode at the un-concrete coated section utilized anode sled mechanism. This holistic design approach had successfully reduced the project cost in line with PETRONAS’ aspiration i.e. low cost development project; and most importantly the ‘body of knowledge’ i.e. experiences, lessons learnt and good practices are captured in PETRONAS Technical Standard for future replication
PETRONAS had been notified by its pipe mill that some of the linepipe supplied by the mill were found to be non-compliance with agreed manufacturing process specification (MPS) and inspection & test plan (ITP). The non-conformances happened during longitudinal weld seam repair at the manufacturing stage. The notification has put PETRONAS on high alert as the affected linepipes have already been installed and commissioned as part of gas pipelines i.e. Pipeline 1 and Pipeline 2 supplying to onshore customer. This paper will discuss the investigation strategies implemented by PETRONAS' investigation team which include 1) multidisciplined investigation team, 2) Technical Safety Review, 3) Desktop Review and 4) Repair Simulation and Material Verification Testing. The paper also details out the type of non-conformance and associated hazards with corresponding action plan to address them. Engineering Criticality Assessment (ECA) was one of the critical processes in the investigation where simulated longitudinal weld samples from the linepipe underwent Crack Tip Opening Displacement (CTOD) test. The test provided fracture toughness value of the weld sample and became the main input in the ECA study. The objective of the ECA is to provide defect/ crack acceptance criteria based on methodology specified by BS7910. During ECA, the respective weld sample was analyzed against pipeline operating parameters coupled with fatigue stress mainly contributed by pressure variations. Crack growth was studied and compared against defect/ crack critical dimensions i.e. height, and length. Given all the investigations carried out combined with ECA experts review, the pipelines were proven safe and reliable to operate. The investigation outcomes have saved PETRONAS commercially while maintaining good safety record.
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