Analysis of an existing hydrocarbon gas pipeline for conversion to dense phase CO₂ service

Introduction

ExxonMobil established its Low Carbon Solutions (LCS) business to commercialise the company’s extensive lower-emission portfolio with the objective to create long-term shareholder value and support global emissions-reduction efforts. Currently, LCS is focussed on commercialising lower-emission business opportunities in carbon capture and storage (CCUS), hydrogen (H₂) and lower emission fuels, by leveraging the skills, knowledge, and scale of ExxonMobil.

As part of these opportunities, Esso Australia on behalf of the Gippsland Basin Joint Venture (GBJV) is undertaking early feasibility/Front End Engineering Design (FEED) to determine the potential for CCUS to reduce greenhouse gas emissions from multiple industries in the Gippsland Basin. Announced as the South-East Australia Carbon Capture and Storage (SEA CCS) Hub, the project aims to initially take dense phase CO₂ from the Longford Gas Conditioning Plant via pipeline to the Bream A platform in offshore Bass Strait, where the CO₂ will be permanently injected in the Bream reservoir. Ultimately the project aims to reduce large scale emissions in line with ExxonMobil’s and Australia’s carbon emission reduction goals.

The Barracouta 450 mm Gas pipeline to Longford was constructed in 1968 and transports produced gas from Barracouta A platform (BTA) to the Longford Gas Plant for processing and sale to Eastern Australia natural gas customers. In 2021, an additional flowline connection was made via subsea hot tap near BTA to flow the newly developed Barracouta West (BTW) field.

The pipeline is a 450 mm nominal diameter API 5L X52 carbon steel pipeline. The onshore section consists of double submerged arc welded (DSAW) pipe that’s predominantly 10.4 mm thick with short sections of 12.7 mm thick pipe at some road crossings. It’s coated with Coal Tar Enamel (CTE) coating for external corrosion protection which is further complemented via impressed current cathodic protection. It’s a licenced pipeline (PL/1) under the Victorian Pipelines Act.

As part of the SEA CCS feasibility study, an evaluation was made on a section of the BTA450 pipeline between Longford and Valve Site 3 for CO₂ service.

The immediate advantages of this would be to eliminate the need for new pipeline construction and installation, remove associated requirements for a new pipeline right of way/easement, avoid associated environmental disturbances and disruption to landholders, and reduce start-up times for carbon sequestration.

Method

To convert the existing BTA450 pipeline section to CO₂ service, a requalification process was required. This was required for two reasons:

A requalification process for CO₂ service includes several factors (DNV 2021). The process includes evaluation of integrity information, flow assurance and hydraulic analysis and associated safety implications of changing the process fluid to CO₂. Australian Standards (AS/NZS 2018a, 2018b, 2022) are also descriptive of the required changes, in terms of consequence modelling for CO₂ exposure, management of change and fracture control requirements.

The assessment identified a total of 57 high-level items that need to be considered as part of the BTA450 conversion (Table 1). These were assessed using a traffic light ranking system to determine the acceptability of the pipeline for CO₂ service, identify any modifications that are required, and any potential STOP items that would render the pipeline unsuitable for CO₂ service.

Modelling was performed by Esso Australia to demonstrate the difference in relative cooling effects of hydrocarbon gas versus dense phase CO₂. The models attempted to simulate the sudden isentropic decompression of both CO₂ and hydrocarbon gas (90% methane, 5% ethane, 5% propane) process streams from 10,000 kPa to ambient condition through a choked 10 mm hole to determine the degree of temperature drop and thermal energy transfer from the fluid to the surrounding environment (i.e. soil and pipe). The 10 mm choked hole was to simulate a corrosion hole failure scenario.

Discussion/results

The challenges in maintaining ongoing structural integrity of CO₂ pipelines are outlined below.

Low-temperatures (brittle fracture) concerns

CO₂’s significant Joule-Thompson expansion-induced cooling effects can readily induce temperatures as low as −20°C, or theoretically as low as −90°C in the event of a loss of containment and sudden decompression down to ambient pressure (e.g. rupture or emergency blowdown).

As demonstrated from the modelling above (Fig. 1), there can be significant differences in both minimum temperature and heat transfer capacity between a gaseous hydrocarbon leak and a dense phase CO₂ leak. Should this occur on a buried section of an onshore pipeline, there can be significant brittle fracture initiation concerns.

Fig. 1.

Theoretical heat transfer and minimum temperatures on a small leak from a gaseous hydrocarbon pipeline (left) versus a dense phase CO₂ pipeline (right). The results indicate a significant variance in both temperature (−47°C versus −90°C respectively) and overall heat transfer (9.1 × 10⁵ versus 99.9 × 10⁵ kJ/h respectively).

Brittle-to-ductile fracture control concerns

The advent of significant low-temperature excursions that could be reached in a dense phase CO₂ leak can be significant fracture control considerations. Despite this pipeline, like many other pipelines, demonstrating ‘no rupture’ design in accordance with AS/NZS (2022) requirements, the low temperature impacts of a leak of dense phase CO₂ could introduce the possibility of a brittle-to-ductile failure mode.

A flowchart of this potential failure mechanism is detailed below in Fig. 2.

Fig. 2.

Flowchart detailing the possible Brittle-to-Ductile fracture failure mode mechanism within a CO₂ pipeline.

Existing gas hydrocarbon pipelines are generally designed with a −10°C/0°C minimum design temperature, which is verified against Drop Weight Tear Tests (DWTTs). Since CO₂ leaks can generate much colder temperatures, particularly in buried sections, this has the potential to impact the adequacy of this brittle fracture initiation control.

A small pinhole corrosion leak on a buried section of a CO₂ pipeline could induce very low process fluid temperatures. Continued exposure to these very low temperatures for extended periods could cool the line pipe to below its minimum design material temperature (since CO₂ has the potential to introduce temperatures well below typical gaseous hydrocarbon minimum temperatures). This could result in a brittle fracture initiation event.

Brittle fractures are characterised by a rapid propagation of a crack-like flaw within the cooled material. If the flaw length approaches the critical defect length of the pipeline, even if the line pipe is above the Minimum Design Material Temperature (MDMT), this could result in a change in crack propagation from a brittle fracture-driven to a ductile-tearing (fast running) fracture.

Since CO₂ pipelines generally require higher arrest toughness than gaseous hydrocarbon services, it is likely the pipeline may have insufficient toughness to arrest this fracture propagation. This is despite a pipeline typically having sufficient toughness for ductile fracture arrest in gaseous hydrocarbon gas service.

The result of this failure mode would have Safety, Environmental and Supply impacts.

Summary and conclusions

The results of this study identified the risk of a ‘brittle-to-ductile’ fracture failure mechanism in existing hydrocarbon gas pipelines when converted to dense phase CO₂ service. Pipeline engineers and designers involved in conversions of existing hydrocarbon gas pipelines to dense phase CO₂ service should take care of existing brittle and ductile fracture controls and ensure that these controls and their underlying assumptions are confirmed as part of the conversion assessment works.

The selection and adequacy of minimum design material temperatures for line pipe materials for CO₂ service and associated brittle fracture failure modes should be an area of further research, as well as any impacts various pipeline configurations (pressure, temperature, pipe wall thickness, pipe toughness properties, pipe glass-transition temperature limits, fluid composition, un-isolated versus isolated flow, exposure times, etc.) have on brittle fracture initiation control.

Additional research to expand the limits of the DNV (2021) methodologies for fracture control would aid in the conversion assessments of existing pipelines. The current DNV (2021) ductile fracture toughness calculations are limited to specific grades, wall thicknesses, diameters, and other dimensions. Due to the prospects of further conversion assessments across the hydrocarbon industry, a wider range of variables should be qualified.