Flow assurance issues associated with deepwater flowlines and pipelines remain central to cost-effective field developments. Wax, asphaltene and hydrate plug formation comprise the key concerns; corrosion, erosion and chemical incompatibility issues also fall within the flow assurance umbrella. Driven by the high cost of remediation, including deferred production, operators typically specify development schemes focused on ensuring high tolerance to production chemistry and operational upsets. Confident predictions of operating envelopes assuring a clear flow path appear commonplace; efforts to broaden these envelopes may lead to less costly development schemes and higher degrees of operating freedom.
Flow assurance, broadly defined, concerns the ability of a production system to transport produced fluids from the bottom of the tubing through the sales pipeline in a predictable manner over the life of a project. Plugging due to gas hydrates, wax and asphaltenes degrades this capability, as does loss of integrity due to corrosion, erosion or mechanical stresses induced by unexpected fluid slugging. Secondary issues involving the failure of control systems to deliver chemicals to the system similarly impair deliverability.
Profitability in deepwater developments often hinges on the ability of the designers to ensure consistent and controllable flow - interventions require costly equipment, and equally costly downtime. Additionally, deepwater operations amplify environmental and safety concerns due primarily to inaccessibility of the flowline or pipeline.
In spite of the significant complexity of interactions driving these situations, much empirical and theoretical understanding of the phenomena exists; and techniques for identifying, assessing, controlling and remediating flow assurance problems have evolved to meet local needs.
This paper focuses on the challenges associated managing hydrates, wax and asphaltene deposition in the flowlines and pipelines associated with deepwater producing facilities. Many successful techniques for plug formation avoidance exist; these, along with prediction tools form the basis for many flow assurance strategies. Along with highlighting these successes, identified opportunities for expanding the operating envelope follow.
Natural gas hydrates, whether occurring in gas/condensate or oil systems, often represent the most dramatic flow assurance problem for a deepwater project. In many cases, ambient water temperatures surrounding flowlines and pipelines fall below those needed to prevent hydrate crystal growth in hydrocarbons for the (typically) high flowing pressures, leading to potential for forming large, solid plugs.
Identification of pressure and temperature conditions conducive to hydrate formation is a mature technology, with abilities to accurately model impact of dissolved salts and inhibitors available in many commercial simulation packages.
Control of hydrate formation in gas systems typically involves injection of methanol or glycol at a location where the fluids are above the hydrate formation temperature, with downstream separation and recycling common for glycols.
Control of hydrate formation in oil systems typically requires heat-conserving flowlines, with special procedures for transient operations (e.g., cold start-up). Continuous methanol injection, due primarily to the preference of the methanol for the oil vs. water phases, remains uneconomic for most oil systems due to large dosage requirements.