Research provides clues to hydrate formation and drilling-hazard solutions

March 9, 1998
Hydrate formation is a growing safety concern for offshore drilling programs, but, despite extensive laboratory research, pragmatic information is still lacking. Formation of hydrates in drilling fluids during a shut-in is the most likely hydrate-associated hazard in deepwater drilling, although the number of documented incidents is small. For several years, companies have been aware of problems arising from hydrate formation during well-control and drilling operations. Recently, these problems
Richard Szczepanski, Beryl Edmonds
Infochem Computer Services Ltd.

Nigel Brown, Terry Hamilton
Offshore Safety Division-Health & Safety Executive

Hydrate formation is a growing safety concern for offshore drilling programs, but, despite extensive laboratory research, pragmatic information is still lacking.

Formation of hydrates in drilling fluids during a shut-in is the most likely hydrate-associated hazard in deepwater drilling, although the number of documented incidents is small.

For several years, companies have been aware of problems arising from hydrate formation during well-control and drilling operations. Recently, these problems have increased because of:

  • An increase in deepwater exploration activity.
  • A move towards the use of environmentally favored water-based over oil-based drilling fluids.
In addition to the known naturally forming hydrates, laboratory experiments have also identified heavier hydrocarbons found in oil and gas condensate systems and a new hydrate structure. These two factors may increase the range from which hydrate formation can occur.

Safety concerns

As a result of the increased risk and the need to improve communication, the U.K. Health and Safety Executive asked Infochem Computer Services Ltd. to investigate the state-of-knowledge concerning hydrate formation during deep-sea drilling operations and to relate these findings to operations within U.K. controlled waters.

Gas hydrates are solid, ice-like compounds of natural gas and water. They can exist at temperatures above the freezing point of water (20-30° C.), under conditions of high pressure.

Although hydrate formation can be a problem for oil and gas production operations, the potential for encountering hydrates during the drilling process is a new phenomenon for U.K. offshore operations, particularly the West of Shetland frontier areas. Water depths in these areas range from 300 m to more than 1,000 m, with seabed temperatures as low as 0° C.1

In the Gulf of Mexico, where conditions are in some respects less extreme, serious hydrate problems encountered during well control operations have also been reported.

Hydrates can exist in situ in petroleum reservoirs where they can cause blowouts if drilled into inadvertently. Alternatively, extreme conditions of temperature and pressure mean that hydrates can easily form during the drilling process if fluids containing water-drilling muds, seawater, and produced water-come into contact with reservoir fluids.

Formation of solid hydrates can plug up subsea risers, blow out preventers (BOPs), and choke and kill lines. Conditions during well shut-in are particularly favorable for hydrate formation if high pressures are combined with falling temperatures, and there is sufficient time for equilibrium to be reached. The risks of hydrate formation are significantly increased by the use of water-based muds.

Hydrate structures

The hydrate crystal lattice is composed of hydrogen-bonded water molecules. It cannot exist on its own but must be stabilized by the inclusion of gas molecules in cavities within the lattice. There are a number of different hydrate crystal structures that form under varying conditions and with different gases.

Until recently, it was thought that hydrates form one of two structures, known as structure I (sI) or structure II (sII), and limited to natural gases up to butane.

Recent work carried out by the Department of Petroleum Engineering at Heriot-Watt University, however, has identified heavier hydrocarbons that can form hydrates.2 These hydrocarbons are found in oil and gas condensate systems. Their molecular size allows them to enter the large cavities of structure II gas hydrates.

Table 1 [70,539 bytes] gives a partial list of hydrate-forming species that might typically be found in natural gases and condensates. Furthermore, the newly discovered structure H (sH) hydrate (Fig. 1 [75,552 bytes]), has a hexagonal crystal lattice that has been shown to form at considerably higher temperatures than structures I and II. These larger molecules were previously regarded as being unable to form hydrates.

For example, methane plus trimethylbutane may form structure H hydrates at temperatures of 10° C. higher than methane would alone.3 The possibility of structure H hydrates may have serious implications for hazard assessment because hydrates may form at conditions where they were previously thought not to exist.

Modeling hydrates

Infochem has extended its modeling of hydrate formation and inhibition to include structure H hydrate and the heavy hydrate formers. 4

The aim was to discover whether:

  • The presence of heavy molecules may extend the potential hydrate stability region.
  • The hydrate formation observed in the laboratory is supported by operational observations.
  • The sH structure exhibits the same hard crystalline structure and tendency to aggregate as do sI and sII structures.
Initial calculations confirmed results that adding a small amount of structure H former to methane produces an sH hydrate that is more stable than the sI hydrate formed from pure methane. However, adding the same amount of an sII former (propane), would produce an even more stable sII hydrate for the mixture.

Based on the study, it would appear that for most petroleum fluids, if sH is formed, it is likely to be less stable than sII, although under certain conditions the two structures may coexist. This appears to be the case for the Bush Hill oil and gas seep where sH and sII hydrates were discovered on the sea bed.5

Fig. 2 [60,091 bytes] shows Infochem's predictions for the hydrate stability regions of this gas, in agreement with reported conditions. A survey of literature and oil company experience with hydrate formation in liquid hydrocarbon lines was carried out under the Deepstar II project.6

The survey failed to find any example of hydrates forming in flowing liquid-dominated pipelines, but since it only cited lines that flow above the hydrate formation temperature, this finding was not unexpected.

On initial start-up and restart after shutdowns, some problems were experienced near the wellhead in piping and valves. However, the survey could not determine whether the hydrates formed in the liquid phase or in gas accumulated in the upper part of the well.

In addition, it may be possible that sH hydrate may be softer and more pliable than sI or sII, and therefore less likely to plug, however, no source is referenced.

Hydrate stability

The equilibrium hydrate formation point calculated by models is the temperature (at a given pressure), or the pressure (at a given temperature), where the very first small quantity of hydrates forms after a sufficient period of time.

This point corresponds to the thermodynamic formation point. Model parameters derived through laboratory measurements are made by forming hydrates and slowly heating or depressurizing the sample until it totally dissociates.

The point on the dissociation curve where no hydrate remains is identical to the thermodynamic formation point. Typical experimental results are shown in Fig. 3 [41,132 bytes]. In practice, there is a delay in forming hydrate until a lower temperature or higher pressure is reached (Fig. 4 [52,691 bytes]).

Before the thermodynamic formation point is reached, hydrates cannot form. This point is also called the stability limit. Beyond the stability limit, hydrates can form but may not do so for a long period of time.

The rate at which hydrate forms beyond the stability limit, known as hydrate formation kinetics, is of practical and scientific interest because it may form the basis for new inhibitor types that affect the nucleation and agglomeration of hydrates.

Traditional thermodynamic hydrate inhibitors such as methanol, glycols, or salt depress the hydrate formation point by reducing the fugacity of water. Hydrate kinetic modeling is not well established and is one of the most significant barriers to an improved understanding of hydrate phenomena in practical applications, both in production and drilling.

Naturally occurring hydrates

The presence of hydrates within ocean sediments and subsurface polar regions is well established. Although hydrate presence in deep ocean sediments was also thought likely, it was not until 1975 that solid gas hydrates were first observed in oceanic sediments of the Black Sea. 7 8

The Deep Sea Drilling Project subsequently recovered samples from the Pacific continental margin off Mexico and Guatemala, the Atlantic continental margin near the southeastern U.S. coast, and the Blake Outer Ridge.8 9

Many hydrate cores from other regions have since been recovered.10 Leg 164 of the Ocean Drilling Program has recently drilled hydrate fields in an effort to improve understanding of the in situ characteristics of hydrates and hydrate-bearing sediments.11

To date, hydrates have not been reported on the U.K. continental margin. Water depths West of Shetland exceed 1,000 m in the Rockall Trough and Faero-Shetland Channel and seabed temperatures are close to 0° C. Thus, in these areas, hydrate deposits are certainly possible.12 13 The British Geological Survey is currently studying the possible extent of hydrates West of Shetland.1

The depth and thickness of a hydrate layer depends on a number of factors:

  • Seabed temperature
  • Geothermal temperature gradient and thermal conductivity
  • Pressure (water depth)
  • Gas composition
  • Water salinity.
A quantitative scheme for predicting a hydrate layer in permafrost regions was first proposed by Katz and has since been adapted to ocean sediments. 14 15 This is illustrated schematically in Fig. 5 [90,302 bytes]. However, the source of greatest uncertainty when applying the model to the U.K. continental margins is information on geo thermal gradients, and to a lesser extent, seabed temperatures.

Techniques for drilling hydrates

Bily and Dick were some of the first workers to report experiences of drilling into hydrates. 16 They concluded that drilling through a significant thickness of hydrates can pose important problems if not anticipated and promptly diagnosed.

Drilling into hydrate zones at normal speeds generates sufficient heat to cause hydrate decomposition. This results in highly gasified mud that could contribute to primary well control loss.

They recommend drilling hydrate zones using cooled mud and drilling with controlled penetration rates. Bily and Dick also suggest that hydrate zones should be cased-off before drilling deeper.

The presence of hydrate zones was determined through thermodynamic analysis of the hydrate stability zone in addition to analyzing field information from wire line logs, mud-gas logs, and drill-stem tests. A number of useful articles provide information from Alaskan and arctic research and experience.17-20

Roadifer, et al., has produced a detailed mathematical model concerning thermal effects in the drilling process.21 22 The model provides a tool for predicting hydrate dissociation and gas influx rates depending on reservoir and drilling conditions.

Their recommended procedure for drilling hydrates is summarized as follows:

  1. Determine hydrate zone depths.
  2. Watch for hydrate indicators while drilling.
  3. If hydrates are present, the mud should be cooled and weighted to offset the gas cut; the circulation rate should be increased to remove the gas; the penetration rate should be decreased; and mud gas samples should be tested to confirm the presence of hydrates.
The correct sizing of mud degassers to cope with hydrates is also emphasized.

Hydrate formation while drilling

Although hydrates may not be present in the reservoir formation, hydrate formation may be possible during the course of drilling or well-control operations. The risk is particularly high in deep-water areas.

The most obvious problem is formation of solid hydrate plugs either in the well bore, or more likely, in choke and kill lines and parts of the BOP where circulation does not take place.

There are several well-documented accounts of hydrate problems during drilling operations including case histories of hydrate formation during deep water drilling operations.23 The first case occurred in 350 m of water off the U.S. West coast.

In this case, gas entered the well and the kill operation lasted 7 days. Hydrates formed in the BOP, choke line, kill line, and riser. The second case was in 950 m of water in the Gulf of Mexico. A prolonged well control operation resulted from the failure of the BOP to function properly because of hydrates.

Barker and Gomez summarize the adverse effects of hydrate formation during well control operations as follows:

  1. Choke and kill lines become plugged, preventing its use in well circulation.
  2. Plugged formation at or below the BOPs prevents well-pressure monitoring below the BOPs.
  3. Plugged formation around the drillstring in the riser, BOPs, or casing prevents drillstring movement.
  4. Plugged formation between the drillstring and the BOPs prevents full BOP closure.
  5. Plugged formation in the ram cavity of a closed BOP prevents the BOP from fully opening.23
They emphasize the need to consider hydrates when planning deep water wells and the need for contingency plans that take into account long shut-in periods during which a subsea BOP may cool below the temperature at which hydrates form.

Drilling fluids and hydrates

Drilling fluids are complex mixtures that may contain electrolytes, polymers, surfactants, and weighting agents in addition to a base fluid consisting of oil or water. The use of water-based drilling fluids is now widespread because of environmental legislation.

The likelihood of hydrate formation in water-based muds is higher than in oil-based muds. Nevertheless, there will always be water present in the mud system and hydrate formation is possible with any mud formulation. If hydrates do form, they will also extract water from the drilling fluid, thereby changing the mud properties and possibly leading to barite sag.

Hydrate formation studies in water-based drilling muds show that the most important factor for hydrate inhibition is the level of salt concentration in the aqueous phase. However, some typical components of muds, such as bentonite, actually stabilize hydrates at higher temperatures, as compared with pure water, and promote the rate of hydrate formation.24-26

Mud formulations designed to inhibit hydrates must also achieve a correct balance of mud weight and viscosity. For example, workers at Shell Development Co. developed a salt/glycerol-based spotting fluid for use in the Gulf of Mexico for water depths greater than 2,000 m.31

Rheological property measurements show that high salt/glycerol water-based muds with weights up to 1.68 sp gr (14 ppg) can be prepared and are compatible with operational requirements.

The conclusions that can be drawn from publications to date are:

  1. The effects on hydrate stability for components added to a drilling fluid are approximately additive.
  2. The components that have a dominant effect on hydrate inhibition are glycerol and salts.
There have been no reported studies concerning hydrate formation rates (kinetics) in drilling fluids, nor any attempts to use kinetic inhibitors. A recent review of hydrate control in deepwater drilling indicates that more work is required before suitable kinetic inhibitors or crystal modifiers for drilling fluids can be recommended. 32

Completions fluids

Peavy and Cayias have reviewed the design considerations for hydrate prevention in deep water completions, providing field examples of hydrate problems. 27 An important point is that the use of inhibitors including methanol and glycols in high concentrations may lead to precipitation of salts. Peavy and Cayias describe a development project for three Gulf of Mexico deep water subsea gas well completions. 28 Recent reviews by Hunt include the hydrate inhibition design along with wider considerations for solids formation and oil field chemistry. 29 30


Funding for this work came through the Offshore Safety Division of the Health & Safety Executive, U.K.


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The Authors

Richard Szczepanski is a director for Infochem Computer Services Ltd., a London-based consultancy and software house specializing in physical properties for the oil and gas sector. Before joining Infochem in 1988, he was leader of the operational thermodynamics project at the British Petroleum Research Centre, Sunbury-on-Thames. He holds BS and PhD degrees in chemical engineering from Imperial College, London University, and has over 20 years' experience in physical property modeling and software development.
Beryl Edmonds is a director of Infochem Computer Services Ltd. and was previously the director of the Physical Property Data Service of the Institution of Chemical Engineers. She holds BS and PhD degrees in chemistry from Sheffield University. She has been a leading figure in thermodynamic data and modeling for 24 years.
Nigel Brown is a technology development manager for the Offshore Safety Division of the U.K. Health and Safety Executive.

He is a chartered chemical engineer with 15 years upstream oil industry experience. He holds BS and PhD degrees in chemical engineering and an MBA from Imperial College, London University.

Terry Hamilton is a principal inspector in the Offshore Safety Division of the U.K. Health and Safety Executive, and is a leader of the HSE well control program. He holds a BS degree from Bristol University and an MS degree from the Cranfield Institute of Technology.

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