Hydrate Blockage in Subsea Water Injection Wells - Causes and Preventive Procedures

Abstract

Hydrate blockage has been a problem in Campos Basin subsea producer wells for a long time. Although hydrate formation was not expected in sea water injection wells there were some occurrences in Campos Basin. The formation of hydrate requires the presence of water and gas at low temperature and high pressure condition. As the subsea sea water injection wells always present water at low temperature and high pressure, the missing link to form hydrate is gas. Thus, to explain the occurrence of hydrate blockage in these wells one has to explain how and when gas enters into the well. A study was carried out to determine the causes of gas inflow into the injection strings and to make recommendations on the proper procedures and equipments to avoid hydrate blockage. The literature survey and the Campos Basin occurrences showed initially that gas segregation, water hammer effects and crossflow were the most probable causes for gas inflow during injection plant shutdowns or long time waiting for injection. The crossflow was ignored because the formations are homogeneous in all the cases. The water hammer effects were analyzed with a numerical simulator developed in the study. The final analyses revealed that gas segregation was the cause of hydrate blockage in the water injection wells studied. Other relevant conclusions are that down hole valves, such as deep subsurface safety valves and backflow valves are useless to prevent gas inflow and that water hammer effects can be managed in the sea water injection plant. This paper presents recommendations for water injection wells startups, regarding hydrate prevention, which can be useful for any subsea water injection project. Introduction Natural gas hydrates are solid structures composed of water and gas. Depending on the thermodynamic conditions, water molecules will form a solid cage entrapping gas molecules (Freitas et al. 2002). Hydrate blockage has been a problem in Campos Basin subsea producer wells since 1994. In Campos Basin the sea temperature decreases with WD showing values around 13°C at 300 m WD, 8.5°C at 500 m WD and varies in the range of 3.5°C to 4.5°C from 1,000 m to 2,000 m WD. In this scenario, hydrate may occur in water depth (WD) beyond 300 m (984 ft), even with small amounts of water and gas. The hydrate blockages often occur during operations such as production shutdown/startup. From 1994 to 2006 hydrate blockage was the main cause of rig intervention in the most prolific field of Campos Basin (Figure 1). Their occurrences in completion and workover have decreased in Campos Basin because of the preventive measures adopted. Besides causing production losses and requiring expensive rig interventions, hydrate blockages can put in risk the production system safety and the environment. This is because they can occur in the wet Christmas tree (WCT) valves, and in the subsurface safety valve control lines (Freitas et al. 2002). Analyses have shown that lack of attention to details in planning the operations and not following program and good practices are by far the main causes of the hydrate problems (Rodrigues et al. 2007). The first occurrence of hydrate blockage in water injection wells (WIW) in Campos Basin was in August 2000. Since then there were eight occurrences in seven wells, all requiring costly rig interventions. At the most penalized field it was decided to install downhole valves to prevent gas migration from the formation open zones up to the WCT valves. The recurrence of hydrate blockage in subsea WIW was the reason for this study. There are no publications about hydrate blockage in WIW to the best of our knowledge. However, there are good references about some probable causes of hydrate blockage that were raised in the early phase of this study. This is the case of water hammer (WH) effects.

Kinetic Hydrate Inhibition with N-Alkyl-N-vinylformamide Polymers: Comparison of Polymers to n-Propyl and Isopropyl Groups

“…1,2 Under these thermodynamic conditions, water molecules form cage-like structures and trap small gas molecules within these hydrate structures. Typical gas molecules are small hydrocarbons, such as methane, ethane, and propane, as well as carbon dioxide and hydrogen sulfide.…”

“…Silica gel column chromatography with hexane/ ethyl acetate (2:1) was achieved to obtain the liquid monomer (19.6 g, 173 mmol, 84% yield). 1 N-(Isopropyl)-N-vinylformamide (2). In the glass flask, activated molecular sieve 4A, anhydrous DMF (28 mL), and NVF (15.5 mL, 205 mmol) were combined.…”

“…Silica gel column chromatography with hexane/ethyl acetate (2:1) was achieved to obtain the liquid monomer (11.9 g, 105 mmol, 51% yield). 1 h. An aliquot of crude mixture was taken for 1 H NMR analysis to determine conversion after 24 h. Then, the reaction mixture was dissolved in MeOH/water (1:1, v/v) and then poured into a large amount of acetone to recover the insoluble part (76% yield). The different feed ratios of co-polymerization were listed in Table 1.…”

“…Natural gas hydrates tend to form at elevated pressures and low temperatures, which are typical conditions in cold-climate upstream oil and gas fields and subsea multiphase pipelines. , Under these thermodynamic conditions, water molecules form cage-like structures and trap small gas molecules within these hydrate structures. Typical gas molecules are small hydrocarbons, such as methane, ethane, and propane, as well as carbon dioxide and hydrogen sulfide. − …”

A Dynamic Simulation Study of Water Hammer for Offshore Injection Wells to Provide Operation Guidelines

“…There are three stages in the wellbore after topside pump stopping: (1) after-flow (BH has not yet felt the topside shut-in in the first few seconds (8 sec. for the discussed case) thus water continues to flow into to the reservoirs), (2) back flow toward to wellhead with maximum rate equal to the steady state injection rate (about 35,000 stb/d for the studied case), and (3) water hammer when the well feels the topside check valve closing. When wellbore feels the flow stopping at topside, wellbore fluid downward velocity starts to reduce until after-flow stops.…”