The CO2 capture technology is well understood in the oil and gas industry. However, to unlock the Hydrocarbon from an ultra-high CO2 offshore field (more than 70% mol), special attention is needed to capture CO2 for a field development to be economically attractive. Therefore, the current technology inventory needs to be studied to achieve project goals and at the same time achieving Carbon Capture and Storage (CCS) requirements. A hybrid of multiple carbon capture technology will help to improve the hydrocarbon (HC) loss, reduce both operational and capital cost and minimize overall auto consumption. The hybrid of cryogenic distillation (CryoD), membrane and supersonic gas separation (SGS) was studied to explore its feasibility. To enable ease of CO2 transport and handling, CO2 is preferred to be in liquid form. In order to achieve this, CryoD technology is the preferred solution for bulk removal. CryoD is also able to cater to the feed gas fluctuation and becomes a robust candidate for high variance feedstock. However, being dependant on sub zero working temperatures, the system will require larger equipment footprint and tonnage. The focus of the study is to evaluate the sensitivity impact of an operating condition on the Hybrid configuration of CryoD + membrane (CM) and CryoD + SGS (CS. Areas of focus will be equipment tonnage and footprint, power consumption and eventually cost (CAPEX & OPEX). The monetization of ultra-high CO2 gas field is then made feasible by using hybrid Acid Gas Removal Unit (AGRU) to meet sales gas specification. The CryoD + membrane technology is the preferred solution for offshore system.

Natural gas produced from many major reservoirs can contain significant amounts of carbon dioxide (CO2) and must be treated to meet typical specifications for pipelines or liquefaction plant feed. The treatment process selected was low temperature CO2 distillation which involve high pressure operation and formation of highly concentrated CO2 streams. Pressure protection for high pressure, low temperature and high CO2 systems have been challenging to date because of potential solid CO2 formation during pressure let down and the consequent plugging. Blowdown or depressuring of process equipment during an emergency or planned shutdown is a critical process safety operation. It may be necessary in the event of fire, leak, pipe rupture or other hazardous situations, as well as for planned shutdown. Devices such as blowdown valves, relief valves, restriction orifices, rupture disks, and safety valves transfer the potentially hazardous content of process equipment to a safe lower-pressure location or to the flare/vent system for controlled combustion or safe venting. To ensure blowdown will be executed safety and effectively, a number of design concerns must be addressed such as low temperature solid CO2 identification and Minimum Design Metal Temperature (MDMT) for piping and equipment material selection. Rapid depressurizing and gas expansion can potentially put equipment at risk of brittle fracture if the temperature goes below its ductile-brittle transition temperature of the selected material and potential plugging due to solid CO2 formation. In addition, the entire pressure relief system including safety valves, relief orifices, flare piping and knockout drums, must be sufficiently sized to handle the flowrates that occur during blowdown, in addition to the piping and capacity of the flare/vent system. Accurate prediction on the minimum vessel wall temperature during blowdown is important for selecting the appropriate construction material, for reducing overdesign and consequently lowering project cost. Similarly, having an accurate prediction of the maximum flow rate during blowdown reduces overdesign associated with the relief valve/network, without compromising on safety. The paper will address the potential of solid CO2 formation based on proprietary software for blowdown and proposed some mitigation plan with respect to solid CO2 formation within the process piping and equipment.

This paper describes the experience of PETRONAS in sustainable development of a high CO2 gas field. The development project which have a potential of storing 23MTPA of CO2 in a nearby offshore saline aquifer is energy intensive. The operational cost of operating the high duty CO2 capture, transport and reinjection (or CCS) facilities has a negative impact on the overall project economics. As such, optimizing the energy footprint of the CCS facilities is imminent. As a means to achieve the desired duty reduction, the project have identified potential energy recovery from the high pressure well stream via the adiabatic turboexpander gas expansion, deployment and integration of the liquid CO2 pumps as opposed to the conventional higher duty compressor systems and utilizing low BTU gas turbine drivers to avoid the high duty fuel gas separation penalty. The aggregate duty reductions achieved has met the initial project expectation. However, the deployment of these technology is rather new for offshore service and a proper technology qualification exercise is a necessity.