Flow Assurance During Deepwater Gas Well Testing: When and Where Hydrate Blockage Would Occur

Abstract

Abstract The current dominant method to handle hydrate associated problems during deepwater gas well testing is injecting massive inhibitors (e.g. methanol and glycol). This technique is uneconomical and environmentally harmful. A model is established to assess when and where a hydrate blockage would occur in the testing tubing. The characteristics of gas hydrate formation and deposition in the testing tubing are analyzed based on recent published gas-dominated flowloop investigations. The growth of the hydrate film formed on testing tubing walls is modeled. The model is used to estimate the amount of hydrates formed (on the tubing walls) and determine when and where hydrate blockage would occur. Based on the proposed model, a case study is carried out to investigate the effect of gas production rate, water depth, and inhibitor concentration on hydrate blockage development during deepwater gas well testing operations. Hydrates form and deposit more rapidly and the growth rate of the hydrate layer is higher when the gas production rate decreases, and/or the water content and the water depth increase, thus it takes a shorter time for hydrates to block the testing tubing. Conversely, longer time is required for the formation of hydrate blockage. For a typical deepwater gas well (water depth: 1565 m, liquid holdup: 3 %, gas production rate: 45×104 m3/d), it takes about 35 hours for the occurrence of hydrate blockage. Injection of hydrate inhibitors significantly delays the blockage. The study suggests that no inhibitors are required when the well testing operation can be completed before hydrate blockage occurs. Otherwise, the hydrate risk can be managed by injecting small amounts of inhibitors to delay the blockage, rather than keeping the system totally out of hydrate stability region with a high inhibitor fraction. The study suggests a more economical and environmentally friendly hydrate management technique for deepwater gas well testing operations, which can be applied as an alternative to the current total prevention method. The proposed model can be used as a useful tool for flow assurance engineers to estimate hydrate blockage risk and optimize inhibitor injection.