In this Case Study, AFS examines the impact of water salinity, water cut and hydrocarbon fluids on low dosage hydrate inhibitor (LDHI) performance using high pressure rocking cells. This overview summary is based on the paper “Early Project LDHI Dosage Assumptions versus an Extensive Laboratory Study” originally presented at the Offshore Technology Conference (OTC-OTC-28935-MS-MS).
Due to the challenges posed by adopting a “hydrate avoidance” approach to hydrates in traditional flow assurance (high CAPEX, lost production, logistical challenges), many projects are moving to a “hydrate management” approach when appropriate. A large portion of the hydrate risk management based approaches utilize LDHIs, in particular anti-agglomerates (AAs). AAs operate by allowing smaller hydrate particles to form while dispersing them into the oil phase, creating a transportable hydrate slurry. This study demonstrates the variability of AA performance with system parameters and underlines the importance of using laboratory performance tests with fluids close to expected field conditions in the project planning phase to accurately determine the selection of an AA and its viability for hydrate risk management.
Rocking cell tests are an industry accepted method for hydrate risk evaluation and inhibitor assessment. Due to the low shear environment in which hydrates are formed, they are considered one of the more conservative hydrate evaluation methods. For the rocking cell tests, a commercially available sapphire rocking cell (Figure 1) was loaded with brine, hydrocarbons, gas and AA.
Figure 1: Sapphire Rocking Cell
The following range of fluids and operating conditions were used to simulate multiple field operation scenarios (eg. steady state, shut-in, restart) in a rocking cell to examine the performance of two commercially available AAs:
– Fluids: One gas (Green Canyon gas), two hydrocarbons (2 crude oils)
– Operating conditions: Varying salinities (0 – 200,000 mg/L) and water cuts (10 – 80 %)
LDHI performance was studied for a range of salinities at a fixed water cut of 40%, which is considered mid-life field conditions. The results for selected tests performed are summarized in Figure 2.
Figure 2: Summary – Effect of Salinity on Required AA Dose Rates
Results show that:
– Salt acts as a thermodynamic inhibitor, and the “point of self-inhibition” (salinity at which no AAs required to prevent hydrate formation) varied for all hydrocarbons studied.
– The required dose rate for the two AAs in condensed water (0 mg/L) varies from 4 – 6 % for the crude oils.
– Decreasing the density of the hydrocarbons (Crude Oil 2 < Crude Oil 1) increases the AA dose rate required in condensed water.
– However, when salinity is added, lower AA dose rates are required for Crude Oil 2 as compared to Crude Oil 1. While unclear why this occurs, it underlines the importance of AA testing with fluids consistent with field conditions.
In summary, this study evaluated AA performance and dose rate for a range of salinity and water cuts for multiple hydrocarbon systems. Results showed that the required AA dose rates decreased with increasing salinity and increased with increasing water cuts, as expected. Importantly, the hydrocarbon phase used had a major impact on the AA performance and required dose rates. The study demonstrates the variability of AA performance with system parameters; hence laboratory performance tests are recommended during the planning phases of development. The use of actual fluids will provide the most accurate assessment of hydrate blockage risks and the viability of the AA as a potential solution for hydrate management.