The Flow Assurance strategy is crucial in the early stages of development of subsea gas fields. The key questions in early development are an optimal tradeoff between managing risk effectively while ensuring deliverability and keeping CAPEX within acceptable project economic limits. The Flow Assurance plan addresses the interaction between production chemistry and multiphase flow and the resulting effects on operability, deliverability, and system performance.
This paper focuses on two key aspects of the flow assurance plan for subsea gas developments, the strategies for managing hydrates and the wax deposition. Hydrate management strategy must focus on preventing blockages versus preventing hydrate formation. To this end the engineer must evaluate flow conditions, system geometry, and production profiles, in addition to temperature and pressure conditions. In particular, a realistic water production profile during field life is needed to frame a workable hydrate management strategy. While continuous injection of thermodynamic inhibitor is the traditional solution, thermal management may be deployed effectively for certain fields, resulting in lower CAPEX and OPEX. Operability at restart must also be evaluated, focusing again on preventing blockage rather than preventing hydrate formation.
In several Indonesia deepwater gas developments, as well as elsewhere in Southeast Asia, gas condensate systems have a relatively high amount of wax (>2 w/w%). This high wax content indicates wax problems may occur during production operations. Thermal management may help solve potential deposition problems. The pour point and the wax appearance temperature indicate the potential temperature for stock tank condensate gelation and the highest temperature that the wax typically deposits. These transition temperatures can also be reduced to manageable levels through solution gas content in the produced fluid. For example, typical simulation tools forecast wax deposition with gas condensates, but these deposits are seldom realized.