Energy Sources, Part A, 29:39–45, 2007Copyright © Taylor & Francis Group, LLCISSN: 1556-7036 print/1556-7230 onlineDOI: 10.1080/009083190933988

A Review of Strategies for Solving Gas-HydrateProblems in Subsea Pipelines

S. MOKHATAB

Lead Process EngineerTehran Raymand Consulting Engineers LtdTehran, Iran

R. J. WILKENS

Chemical and Materials Engineering DepartmentUniversity of DaytonDayton, Ohio, USA

K. J. LEONTARITIS

AsphWax, Inc.Houston, Texas, USA

Abstract Flow assurance management is critical to successful and economic oper-ation of oil and gas production systems. As production activities progress into deeperwaters, flow assurance challenges become more prevalent, and system design must ad-dress these issues from a fresh perspective. Hence, new management and remediationtechniques have to be developed to reliably, efficiently, safely, and economically pre-vent or handle these problems for the range of expected conditions including startup,shutdown, and turndown scenarios.

An inherent problem with natural gas production or transmission is the forma-tion of gas hydrates, which can lead to safety hazards to production/transportationsystems and to substantial economic risks. Therefore, an understanding of how, when,and where hydrates form is necessary to overcoming hydrate problems. These ques-tions have become all the more crucial since deepwater fields have been discovered orbrought in production, where these fields are perfect candidate to encounter hydrateforming conditions. This article answers these crucial questions as well as providessignificant information on the best method to prevent and remediate hydrates in deep-water production operations.

Keywords flow assurance, gas hydrates, prevention techniques, subsea pipelines

Gas Hydrates

Gas hydrates form in untreated multiphase flows when water molecules crystallize aroundguest molecules at certain pressure and temperature conditions. The most common guest

Address correspondence to Saeid Mokhatab, Lead Process Engineer, Tehran Raymand Con-sulting Engineers Ltd, No. 10, Ahmad Ghassir Street, Dr. Beheshti Avenue, Tehran, P.O. Box15136, Iran. E-mail: s.mokhatab@tehranraymand.com

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molecules are methane, ethane, propane, isobutane, normal butane, nitrogen, carbon diox-ide and hydrogen sulfide, of which methane occurs most abundantly in natural hydrates(GPSA, 1998). While many factors influence hydrate formation, the two major con-ditions that promote hydrate formations are (1) the gas being at the appropriate tem-perature and pressure, and (2) the gas being at or below its water dew point. Otherfactors that affect hydrate formation include mixing, kinetics, type of physical site, sur-face for crystal formation, agglomeration and the salinity of the system (Edmonds et al.,1998).

Hydrates are known to occur when natural gas and water coexist at elevated pressureand reduced temperature. High pressures and low temperatures are common in deepwa-ter oil and gas fields, which provide ideal conditions for the formation of hydrates. Ingeneral, when the multiphase fluid produced at the wellhead flows through the subseapipelines, it becomes colder, which means most subsea pipelines could experience hy-drates at some point in their operating envelope. Moreover, shut-in and startup are alsoprimary times when hydrates form. On shut-in, the line temperature cools to that of theocean floor so that the system is almost always in the hydrate region if the line is notdepressurized (Hunt, 1996). At that condition, multiple hydrate plugs can form. Figures1 and 2 show the hydrate envelope (HE) examples for oil and gas. The hydrate curverepresents the thermodynamic boundary between hydrate stability and dissociation. Con-ditions to the left of the curve represent situations in which hydrates are stable and “can”form. Operating under such conditions does not necessarily mean that hydrates will form,only that they are possible (Leontaritis, 2000).

Figure 1. Typical gas hydrate envelope of Gulf of Mexico.

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Figure 2. Typical oil hydrate envelope of Gulf of Mexico.

Possible Problems

Although gas hydrates may be of potential benefit both as an important source of hydro-carbon energy and as a means of storing and transmitting natural gas, they represent asevere operational problem as the hydrate crystals deposit on pipe walls and accumulateas large plugs, resulting in blocked pipelines, over pressuring and eventually shut downof production facilities. Acceleration of these plugs when driven by a pressure gradient(e.g., single-sided depressurization after hydrate formation) can also cause considerabledamage to production facilities, and therefore create a severe safety and environmentalhazard. The removal of hydrate plugs in subsea production/transmission systems posessafety concerns and can be time consuming and costly (Wilkens, 2002). For this reason,the hydrate formation in subsea gas transmission pipelines should be prevented effectivelyand economically to guarantee the pipelines operate normally.

Hydrate Prevention Techniques

Gas hydrate formation can be prevented by several methods. The permanent solution isremoval of water prior to pipeline transportation, such as using an offshore dehydrationplant or subsea separation, which are not often the most cost effective solutions. Anotherway to prevent hydrate plugs is to maintain the pressure and temperature conditionsoutside the hydrate formation region. The primary practical means of avoiding hydrateformation rely on the idea of preventing the HE and P and T production facilities pro-file from crossing each other during normal production (see oil and gas HE examples

42 S. Mokhatab et al.

above). This is done by either pushing the HE to the left using thermodynamic inhibitors,either regular, e.g., methanol or glycols, or more exotic low dosage or by shrinking theP and T production facilities profile to the right by insulating and/or heating the flowline (Leontaritis, 2000). An economical thermal loss reduction method, recently utilizedoffshore in the Gulf of Mexico, is with pipeline burial. However, conventional insula-tion on the outer surface of the pipe and more effective pipe-in-pipe insulation methodsare still preferred around the world because their performance can be predicted withengineering accuracy. It may be possible to operate at a pressure less than the hydrateformation pressure. However, line-depressurization approach is not practical in long andhigh-pressure gas transmission pipelines. In addition, rapid gas decompression at thewellhead (e.g., through flow-controlling sub-sea chokes in satellite wells producing todistant host platforms) results in lowering the temperature and could create favorableconditions for hydrate formation (Hunt, 1996; Wilkens, 2002). In general, at the wellsite,two methods are applicable, namely thermal and chemical (Mokhatab et al., 2004).

Thermal Methods

Thermal methods use either the conservation or introduction of heat in order to maintainthe flowing mixture outside the hydrate formation range. Heat conservation is commonpractice and is accomplished through insulation. This method can be feasible for somesubsea applications depending upon the fluid being transported, the tie back distance, andtopsides capabilities of host platform. The design of such conservation systems typicallyseeks a balance between the high cost of the insulation, the intended operability of thesystem, and the acceptable risk level. In addition to its high capital expenditure level andthe technical challenges, it will not also prevent entering the hydrate formation regionduring a long-term shutdown. However, it generally prevents hydrate formation duringnormal operation conditions.

A number of different concepts are available for introducing additional heat to apipeline (Hansen et al., 1999). The simplest is an external hot-water jacket, either for apipe-in-pipe system or for a bundle. Other methods use either conductive or inductive heattracing (Lervik et al., 1998). There is concern over the reliability of conductive systems.An electrical resistance heating system may be desirable for long offset systems, whereavailable insulation is insufficient, or for shut-in conditions (Oram, 1995). The ability toheat during production depends on the specific electrical heating implementation. Suchsystems provide environmentally friendly fluid temperature control without flaring forpipeline depressurization. The effect is also an increase in production as there is no timelost by unnecessary depressurization, pigging, heating-medium circulation, or removal ofhydrate blockage.

Chemical Inhibition

Keeping operating pressures and temperatures out of the hydrate formation region canalso be achieved by adding chemical compounds that change the behavior of the newmixture. Both oil and gas flowlines require some hydrate inhibition, especially in deep-water environments. Typical gas flowlines do not have insulation and require continuouschemical inhibition for hydrate inhibition. Alternatively, oil flowlines are typically insu-lated but require hydrate inhibitors for start-up and shut-in restarts (Notz et al., 1996).Chemical inhibitors are injected at the wellhead and prevent the hydrate formation bydepressing the hydrate temperature below that of the pipeline operating temperature.

Hydrate Management 43

This method is expensive if the water production is significant. For most oil productionsystems, this cost is prohibitively expensive whereas it can be the least expensive alterna-tive for gas systems. Hydrate inhibition using chemical inhibitors is still the most widelyused method, and the development of alternative, cost-effective and environmentally ac-ceptable hydrate inhibitors is a technological challenge for the oil and gas productionindustry (Lederhos et al., 1996).

Thermodynamic Inhibitors

Traditionally, the most common practical approach to prevent hydrate formation in gasproduction systems has been the addition of massive amounts of methanol, ethyleneglycol, or triethylene glycol (at a high enough concentration) to the gas/water stream.These chemicals are called “thermodynamic inhibitors” and have the effect of shiftingthe hydrate formation loci to the left, which causes the hydrate formation point to bedisplaced to a lower temperature and/or a high pressure.

The thermodynamic inhibitor selection process often involves comparison of manyfactors including capital/operating cost, physical properties, safety, corrosion inhibition,gas dehydration capacity, etc. However, a primary factor in the selection process iswhether or not the spent chemical will be recovered, regenerated and reinjected. Inpractice, there is a significant push from refineries to limit the allowable concentration ofmethanol in the produced oil or condensate. High methanol concentration in the oil cancause problems in desalting operations and management of effluent streams. In addition,producers are also reducing methanol content in gas because of severe penalties incurredfor deviating from gas plants specifications. Methanol problems become more acuteduring events such as a hurricane shut-in when operators bullhead in several barrelsof methanol into the tubing of oil wells. Upon re-start, downstream problems can becaused by the methanol slug. Typically, methanol is used in a non-regenerable systembecause it is a relatively inexpensive inhibitor and therefore, the economics of methanolrecovery will not be favorable in most cases. Often when applying this inhibitor, thereis a significant expense associated with the cost of “lost” methanol. However, sincemethanol is lower viscosity and its lower surface tension makes effective separation easyat cryogenic conditions (below −13◦F), it is usually preferred (Esteban et al., 2000).

In many cases, hydrate plug formation is prevented through the addition of glycols(usually ethylene glycol because of its lower cost, lower viscosity and lower solubilityin liquid hydrocarbons) to depress the hydrate formation temperature. But in order tobe effective, glycols must be added at rates of up to 100% of the weight of water.Since glycols are expensive inhibitors, there is a definite need for extra, costly and spaceconsuming, onshore or offshore plants for their regeneration. In addition, these materialsare inconvenient and hazardous due to chemical toxicity and flammability (Edmonds et al.,1998). Therefore, new, cost-effective, and environmentally acceptable hydrate inhibitorsthat allow multiphase fluids to be transported untreated over long distances have beenunder increasing investigation by the oil and gas industry (Kelland et al., 1995, 2000).These new hydrate inhibitors can lead to very substantial cost savings, not only for thereduced cost of the new inhibitor but also in the size of the injection, pumping andstorage facilities, where it is possible to redesign production facilities on a smaller scale(Goodwin and Hunt, 1995). These new hydrate inhibitors, called low dosage hydrateinhibitors (LDHIs), form the basis of a technique that does not operate by changing thethermodynamic conditions of the system. In fact, LDHIs act at the early stages of hydrateformation by modifying the rheological properties of the system (Sinquin et al., 2004).

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Low Dosage Hydrate Inhibitors

LDHIs have been actively investigated for the last ten years in both academia and industry(Mehta et al., 2002). There are two types of LDHIs: the “kinetic hydrate inhibitors”(KHIs), and “anti-agglomerants” (AAs). Most commercial kinetic inhibitors are highmolecular weight polymeric chemicals (i.e., poly[N-vinyl pyrrolidone] or poly[vinyl-methylacetamide/vinylcaprolactam]), which are effective at concentrations typically ten toone hundred times less than thermodynamic inhibitors concentrations. KHIs may preventcrystal nucleation or growth during a sufficient delay compared to the residence time in thepipeline. The deeper a system operates in the hydrate region, the shorter the time duringwhich kinetic hydrate inhibitors can delay hydrate formation. The achievable delays rangebetween weeks if the pipeline operates less than 42◦F in the hydrate region to hours if thepipeline operates 50◦F in the hydrate region. Kinetic inhibitors are relatively insensitiveto the hydrocarbon phase and may therefore turn out to be applicable to a wide range ofhydrocarbon systems. However, the industrial application of kinetic inhibitors dependson the repeatability of multiphase pipeline testing results among laboratory, pilot plantand field, and the transferability among different plants.

Contrary to thermodynamic inhibitors and kinetic hydrate inhibitors, AAs, whichare surface active chemicals (i.e., alkyl aromatic sulphonates or alkylphenylethoxylates)do not prevent the formation of hydrate crystals, but keep the particles small and welldispersed so that fluid viscosity remains low, allowing the hydrates to be transported alongwith the produced fluids. AAs performance is relatively independent of time. In addition,AAs appear to be effective at more extreme conditions than KHIs, which make theseproducts of interest to operators looking for cost effective hydrate control in deepwaterfields (Frostman, 2000). These additives are currently applied in the Gulf of Mexico, theNorth Sea (Palermo et al., 2000) and West Africa. However, they have mainly limitationsin terms of water cut, where they require a continuous oil phase and therefore onlyapplicable at lower water cuts. The maximum water cut is expected to be between 40and 50%. This limitation is caused by the rheological properties of suspensions with highsolid fraction and may depend on flow regime conditions.

Deployment of LDHIs is a complex operation that must be carefully prepared inorder to prevent any side effects that could compromise normal production operations orthe efficiency of additional chemical treatments. There are a few documented cases ofcommercial deployment of LDHIs (Frostman, 2003), however, they are essentially newtechnology, and extensive laboratory testing will be required to support the use of LDHIsin deepwater operations.

Acknowledgment

The authors would like to thank Dr. Ulfert Klomp of Shell Global Solutions InternationalB.V, Amsterdam, The Netherlands, for the kind assistance, comments, and suggestionreceived from him for the article.

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