Chemical Compromise: A Thermodynamic and Low-Dose Hydrate-Inhibitor Solution for Hydrate Control in the Gulf of Mexico
Authors: Szymczak Steve , Sanders Kenneth B. , Pakulski Marek K. , Higgins Timothy D. 
Published: July 2008

Gas-hydrate inhibition is a serious concern for operators producing at conditions in the hydrate region. As production goes into deeper water, hydrate control grows in importance. Ideally, operators want total hydrate control without the problems associated with thermodynamic inhibitors (THI) and/or low-dose hydrate inhibitors (LDHI). A Gulf of Mexico (GOM) operator experienced hydrate-control problems in an 18,000-ft umbilical line in spite of the addition of methanol as a thermodynamic hydrate inhibitor. In addition to erratic pressure, the high rates of methanol usage created a logistical problem as well as a health, safety, and environmental (HS&E) concern because of the handling issues associated with methanol.

Laboratory studies and previous onshore field experience indicated that hydrate-inhibition synergy is gained through the combination of thermodynamic inhibitors and LDHI (Budd et al. 2004). This is termed a hybrid hydrate inhibitor (HHI). Because of the performance, logistical, and cost drivers presented by the use of methanol, any alternative approach must consider those three factors. The performance has to do with hydrate dissolution in the event a hydrate formed during operations. A kinetic inhibitor (KHI) can prevent hydrate formation but cannot dissolve already formed hydrates. Antiagglomerant (AA) inhibitors allow hydrates to form but keep the hydrate particles dispersed in the fluids. The logistics have to do with pump sizing (i.e., conventional LDHI applications require new pumps and configurations). The cost of methanol is far less than specialty LDHI chemistry. Thus, the objective of the study is to provide all the benefits of the existing technology with improved performance, improved logistics, and at a cost not to exceed hydrate prevention with methanol.

After a presentation of lab and field studies to the operator, a method of application was approved for use. The differential pressure (Dp) between the wellhead pressure (chemical injection line) and the flowline pressure serves as the key performance metric. There is a significant decrease of Dp after the HHI product is introduced into the system. Initially, the HHI is applied at the same rate (and a much higher equivalent cost) as methanol. After saturation of the system, the inhibitor rate is decreased in a stepwise fashion until the daily costs of treatment fall below the daily cost of methanol. On a cost-performance basis, the new product outperforms the methanol. While the methanol rate is 120 gal/D, the new product controls line pressure at a rate as low as 12 gal/D. The HHI dosage is eventually set at 22 gal/D to compensate for potential flow and pressure/temperature fluctuations. From the logistical standpoint, methanol shipments to the platform decreased five-fold. This decrease meant less cost and handling as well as a reduction in the footprint for product storage. From an HS&E position, the potential for an incident is decreased in line with the reduction in boat trips and crane lifts.

The technology described in this paper created a synergy that assuages the concerns of operations, technical, logistics, HS&E, and personnel. After observing that hydrate dissolution is still possible at a lower dosage with less handling and at a comparable cost, the HHI treatment became a permanent hydrate prevention method. The project is a success with possible future expansion.

Introduction

Gas hydrates form when water molecules crystallize around guest molecules. The water/guest crystallization process has been recognized for several years, is well characterized, and occurs with sufficient combinations of temperature and pressure (Katz 1945). Light hydrocarbons, methane-to-heptanes, nitrogen, carbon dioxide, and hydrogen sulfide are the guest molecules of interest to the natural-gas industry. Depending on the pressure and gas composition, gas hydrates may build up at any place in which water coexists with natural gas at temperatures as high as 80°F [~30°C]. Gas-hydrate formation is a growing problem because producers drill in deeper waters and in cooler waters. The hydrates can form in a wellbore while the fluids go through pressure- and temperature-induced phase changes near the mud line. The hydrates also form in the flowlines from subsea completions to the separation facilities. The problem of finding an effective hydrate control method in a system at hydrate conditions is especially difficult in offshore environments where one has no control over the fluid composition, bottomhole pressure, and temperature. The well operator has only a limited control over the wellhead pressure. The producing formation temperature, Joule-Thomson cooling effect upon gas decompression, and heat loss to the environment are the factors deciding if a particular well or flowlines are at hydrate forming conditions. Hydrates create physical barriers to production and must be inhibited and dissolved if formed for gas production to occur. The operator must maintain the well and production lines free of hydrates at all times.