Interpretation of Cone Penetration Test Data of an Embankment for Coupled Numerical Modeling

The Nerang Broadbeach Roadway (NBR) embankment in Australia is founded on soft clay deposits. The embankment sections were preloaded and surcharged-preloaded to limit the post-construction deformation and to avoid stability failure. In this paper, we discuss the NBR embankment’s geology, geotechnical properties of the subsurface, and long-term field monitoring data from settlement plates and piezometers. We demonstrate a comparison of cone penetration test (CPT) and piezo cone dissipation test (CPT-u) interpreted geotechnical properties and the NBR embankment’s foundation stratification with laboratory and field measured data. We also developed two elasto-viscoplastic (EVP) models for long-term performance prediction of the NBR embankment. In this regard, we considered both the associated and the non-associated flow rule in the EVP model formulation to assess the flow rule effect of soft clay. We also compared EVP model predictions with the Modified Cam Clay (MCC) model to evaluate the effect of viscous behavior of natural Estuarine clay. Both EVP models require six parameters, and five of them are similar to the MCC model. We used the secondary compression index of clay in the EVP model formulations to include the viscous response of clay. We obtained numerical models’ parameters from laboratory tests and interpretation of CPT and CPTu data. We observed that the EVP models predicted well compared with the MCC model because of the inclusion of soft clay’s viscosity in the EVP models. Moreover, the flow rule effect in the embankment’s performance predictions was noticeable. The non-associated flow rule EVP model predicted the field monitoring settlement and pore pressure better compared to the MCC model and the associated flow EVP model.

Challenges of Hydrate Risk Management at Low Water Cuts Using Anti-Agglomerants

BWOLF (DH 180/185) flowlines, in the deepwater Gulf of Mexico, were being treated continuously with LDHI to manage hydrate risk. Application of the Anti-Agglomerant (AA) was being utilized to treat the asset under the initial conditions, including water cuts up to 20%, for potential unplanned shut ins. Due to a well zone change, water cut dropped from 20% to <1%. The assumption was that chemical treatment volumes for hydrate management would decrease based on water volume. However, at these lower water cuts, it was determined that higher by volume of water treatment dosing was required to provide adequate hydrate risk protection. Additionally, dead-oil circulations were periodically being used to address some pressure build up and return the system back to baseline pressures. Rocking cell testing was conducted to determine the optimal chemical treating doses using AA alone, as well as AA + MeOH as options. However, the rocking cell equipment limitation for water cuts is ~10%, below which results have previously not been trusted. Extrapolation for estimated dosages were needed for the lower water cuts observed in the field. Autoclave tests were done at higher water cuts (30 and 50%) to also provide data for curve fitting to confirm whether the increase need for LDHI at lower water cuts was indeed exponential in nature. Field monitoring of flowline pressures was conducted to determine treatment effectiveness. Additionally, field monitoring of water cut over time was also observed and related back to how the chemical treatment behaved in relation. After the well zone change, application of the AA alone was not enough to effectively address the hydrate risk and resulted in gradual build up of hydrate within the system. Periodic MeOH pills were applied to reduce delta pressure, but care was necessary to avoid reaching MeOH limitations within the crude. Additionally, this method did not effectively remove hydrate formation in the flowline. Less frequently, but when necessary, dead oiling was utilized to remove the build up quite effectively. This was not ideal due to down time and deferred production. It's felt that Webber et al. correctly described the significant increase of AA dosing requirements at very low water cuts (<5%) resulting in a power function relationship. This creates further challenges such as cost of chemical treatment due to higher dosing requirements and potential water quality issues topsides when higher doses of AA are used. The data and results within confirm limited examples of where lower water cut can result in significantly increased dosing requirements for AAs and why a power function relationship should be considered when extrapolating treatment recommendations at 5% or below. There is interest in further understanding the AA requirements at low water cuts and the effectiveness of deal oiling on hydrate build up going forward. This data is particularly relevant for new deepwater projects that consider chemical use as one of the primary options for hydrate management.