Study Investigates Hydrate Formation Risk in WAG Changeover Operations
Authors: Carpenter Chris 
Published: November 2024

_
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 218101, “Investigating the Effect of Carbon Dioxide Concentration on Hydrate Formation Risk From Water-Alternating-Gas (WAG) Changeover Operations,” by Farzan Sahari Moghaddam, SPE, Majid Abedinzadegan Abdi, SPE, and Lesley A. James, SPE, Memorial University of Newfoundland. The paper has not been peer reviewed.

_
Hydrate formation is a flow-assurance challenge for offshore oil and gas operations with subsea pipelines, wells, and tiebacks. In water-alternating-gas (WAG) operations, hydrates can form within the injection wells when switching from water to gas and vice versa. This study investigates hydrate formation in a WAG injection well under water-to-gas and gas-to-water changeover operations.

Introduction
Few previous studies have focused on hydrate formation in gas injection and production wells. Hydrate formation in a gas well under particular enhanced oil recovery techniques requires more attention. This study aims to investigate the changeover operations of water-to-gas and gas-to-water (well depth: 4096 m) and the effects of gas composition changes in terms of CO2 content (5–44 wt%) and thermodynamic inhibition (5 m3 methanol) after water injection. In terms of flow rates, injection rates of 2300–3800 m3/d for water and 1 million std m3/d for gas, which are applicable for offshore Newfoundland and Labrador (NL), are studied. The complete paper includes a discussion of past studies on hydrate formation in production and injection-gas systems.

Methodology
Two scenarios were simulated: water-to-gas changeover and gas-to-water changeover over a range of CO2 concentrations of 5–44 wt%. For operational parameters, up to 3 days of shut-in period was considered for the changeover operations. The water injection rate of 2300 m3/d and gas injection rate of 1 million std m3/d were considered. The rate was increased to find the injection rate that could provide full displacement of the water phase within less than 1 hour from a water-to-gas changeover operation. The same injection rate is maintained for other natural-gas cases with increased CO2 content by changing the compressor injection pressure.
After modeling the fluid with an appropriate cubic equation of state, the fluid model file was imported to the dynamic multiphase flow simulator. A sample WAG well from offshore NL where hydrate formation was experienced was considered for the simulations. After finalizing the setup of the well, the simulation scenario was finalized according to the changeover operation and the operating conditions. A sensitivity analysis was conducted on various concentrations of CO2 (5–44 wt%) followed by conducting both water-to-gas and gas-to-water changeover operations in the transient multiphase simulator. Finally, hydrate formation in presence of methanol was simulated, and the resulting profiles of hydrate formation temperature minus fluid temperature, known as DTHYD, were compared.
The well depth is 4096 m from the seabed, and tubing internal diameter is 0.16 m. The seabed depth is 124 m below mean sea level. The bottomhole is known as the zero depth on the DTHYD, holdup, density, and pressure profiles, and the wellhead is considered to be 4096 m above the bottomhole depth in these profiles. A methanol slug was injected directly into the well under a sea temperature of 3°C at the end of water injection and before the shut-in duration.