Read APPEA-2011-hydrate-remediation-technology-paper.pdf text version

Lead author Henry Sheil

COST ReduCTiOn Of SubSea gaS PROduCTiOn SYSTeMS uSing eMeRging HYdRaTe ReMediaTiOn TeCHnOlOgY


Gas, hydrate, flowline, pressure, deep, well, intervention, dual, single, depressurisation, cost, dissociation, plug, blockage, access, point, ROV, riser, coiled, tubing, wellhead, pig, MODU, OSV, liquid, locating, LWI, test, bleed-off, DP.

H. Sheil1, P.Young1 and M. Richardson2 1 Peritus International Pty Ltd Level 4, 160 St Georges Terrace Perth WA 6000 2 Pöyry Pty Ltd Level 13, 140 St Georges Terrace Perth WA 6000 [email protected] [email protected] [email protected]


A number of significant fields are being developed on the Australian North West Shelf, with each most likely having extensive subsea flowline networks to collect production from numerous wells at multiple drill centres. The water depths vary greatly, with the minimum water temperatures ranging from 20°C to as low as 6°C, depending on depth. At the flowline operating pressures, the hydrate dissociation temperature is above the minimum seabed temperature, hence there is a risk of hydrate formation in the subsea system. A typical hydrate mitigation strategy is based on continuous injection of a thermodynamic hydrate inhibitor (typically monoethylene glycol [MEG]) with little or no insulation of the subsea system. Subsea systems are complex and due to the typically distributed nature of the wells, inhibitor must be injected at an adequate rate in all parts of the system. Where insufficient inhibitor is present, there is a risk of formation of hydrate formation and potential blockage of the line(s). The industry-preferred hydrate remediation approach is dual sided depressurisation (DSD). In the context of a single flowline system, this is performed by depressurising from both sides of the hydrate plug simultaneously, which minimises the projectile risk. The reception facility depressurises downstream of the plug, while depressurisation upstream of the plug is performed by the mobile offshore drilling unit (MODU) via a riser connection to the christmas tree (XT) or wellhead. The combination of availability, delayed mobilisation and high cost of a MODU represents a material threat to the efficacy of this approach. The feasibility of using a lightweight intervention vessel in place of the MODU was the subject of a recent study by Peritus International and Pöyry. The study's objective was to determine the most suitable hydrate remediation philosophy for an LNG development on Australia's North West Shelf (NWS). This APPEA Journal 2011--201


Gas flowlines are presenting flow assurance challenges in hydrate management resulting from low ambient seawater temperatures in an increasing number of deepwater developments. When the equilibrium hydrate temperature of the produced fluid is above the minimum seabed temperature, and the hydrate inhibition system fails, there is a risk of hydrate blockage in the subsea system. The industry-preferred approach for hydrate blockage remediation is dual sided depressurisation (DSD). The objective is to depressurise the flowline below hydrate onset conditions, thus allowing hydrate dissociation and safe disposal of the gas inventory. This is generally performed by one of two methods: installation of a dual flowline system for facility-based depressurisation (capital expenditure [CAPEX] impact) or by connecting a mobile offshore drilling unit (MODU) to an appropriate wellhead or christmas tree (XT) to allow simultaneous depressurisation at the MODU and the facility (operating expenditure [OPEX] impact). It is recognised that both methods incur significant costs. Typically the cost, schedule and availability uncertainties of bringing in a MODU to solve these production stoppages are too high. Consequently, subsea developments often select the increased CAPEX option. An optimisation of the MODU-based intervention method is the subject of this paper. The feasibility of using a lightweight intervention vessel (e.g. an offshore support vessel) in place of the MODU is investigated. In discussing this optimisation, this paper also presents an introduction to hydrate remediation theory, some practical challenges, case studies and vessel requirements.

H. Sheil, P.Young and M. Richardson study included the identification and feasibility review of light well intervention (LWI) techniques. solids and multiphase phenomena. Detailed flow assurance analyses are performed to manage solid deposition in transient and steady state conditions, to determine system parameters and operating procedures that avoid solid deposition. Six potential hydrate remediation methods were identified during the study.These methods have been summarised and included in Table 1.


Natural gas hydrates (hydrates) are crystalline solids that are formed when hydrocarbons and water are held under high pressures and low temperatures. Also known as clathrates, these ice-like solids can build up over time to create a hydrate blockage in a flowline. Hydrates occur in both oil and gas flowlines. The focus of this paper is hydrates in gas systems. Figure 1 is a typical hydrate formation curve. If the operating conditions are on the left of the `uninhibited' curve, where high pressure and low temperatures conditions exist, then hydrate formation occurs and the risk of a hydrate blockage is significantly increased. If the operating conditions are on the right of the uninhibited curve then hydrates will not form. A thermodynamic hydrate inhibitor (THI) can suppress the conditions at which hydrates form, enabling operation at higher pressures and lower temperatures. This is represented by the inhibited curve in Figure 1. Operating at high pressure is an economic driver for gas projects, so hydrate inhibition can offer higher production rates; however, if the hydrate inhibition system should fail, a hydrate blockage may occur, and a contingency plan is required. In the high pressure, low temperature environment observed in the deepwater projects on Australia's North West Shelf, hydrate management is a significant challenge requiring thorough analysis by flow assurance. Hydrate management is only one aspect of flow assurance engineering; a subsea system must effectively manage all potential


Hydrate plug dissociation in a subsea flowline network has numerous challenges. These include, but are not limited to: · Removal of multiple plugs; · Rapid depressurisation; · Pipe wall catastrophic failure; · Excessive head pressure; · Incorrect application of THIs; and, · Inability to pig.

Removal of multiple hydrate plugs

A hydrate may form in an inhibited system operating within the hydrate formation region when the ratio of inhibitor to water is too low. In practice it is unlikely that a single hydrate plug will form when the flowline contents are under-inhibited. Instead, a series of plugs will form throughout the flowline. The hydrates are most likely to manifest themselves in locations where significant volumes of liquids collect. The number of hydrate plugs will (in part) be a function of the flowline bathymetry.

figure 1. Inhibited and uninhibited hydrate formation curves. 202--APPEA Journal 2011

Cost reduction of subsea gas production systems using emerging hydrate remediation technology Table 1. High level summary of hydrate remediation methods. Method Description Advantages

· Can spray thermodynamic hydrate inhibitor (THI) at hydrate plug face. · May be used as gas lift to lighten hydrostatic head.


· Limited by length potentially ~6 km. · Requires internal access to flowline, which is impractical subsea and from facility. · May damage flowline interior surface · Unsuitable for hydrate plug dissociation. · Flowline must be piggable. · Subsea pigging requires vessel and suitable spread to drive pig. · Very high risk of stuck pig. · Trapped pressure within plug can lead to catastrophic pipe failure. · Applying heat difficult over extended pipe length(s) subsea. · Potential projectile upon hydrate dissociation causing catastrophic damage and fatalities. · Limited by access points. · Intervention vessel must be suitable for hydrocarbon disposal at surface. · Flowline bathymetry and length can prevent access to hydrate plug face. · Liberates large quantities of gas, hence pressure must be managed throughout the process.

Coiled tubing (CT)

CT pushed into flowline. The CT provides a conduit for fluid/gas injection.


Deploy pig train to push hydrate and debris out of flowline.

· May remove hydrate and debris. · Pig train can include chemical slugs for chemical conditioning required for re-commissioning.

Active heating

Application of heat to the pipe wall to bring plug above hydrate onset temperature. Flowline is depressurised from one side of plug (typically from the production facility) to below hydrate on-set pressure. Flowline is depressurised on both sides of plug to reduce pressure to below hydrate on-set pressure.

· Widely used in onshore and topside applications. · Access only required from a single side of plug. · Potentially no vessel deployment required. · Low risk of hydrate projectile. · More than twice as fast than SSD (Sloan and Koh, 2008). · Chemicals can be injected from many flowline access point via downline and hotstab, and at the XT via umbilical.

Single sided depressurisation (SSD) Dual sided depressurisation (DSD) Chemically melting with thermodynamic hydrate inhibitor (THI)

The use of a chemical to cause the hydrate plug to dissociate.

When multiple plugs are present, access to both sides of a single plug is unlikely to be feasible as pressure can only be relieved at available depressurisation access points (see Fig. 2).The trapped pressure between plugs has no suitable conduit to relieve pressure other than through the slightly porous hydrate plugs and/or upon hydrate dissociation. In practice removing a number of such plugs may only be possible via the Single Sided Depressurisation (SSD) method, however SSD is a greater risk because as sufficient dissociation of a plug occurs, the trapped pressure between adjacent plugs may propel a plug at high velocity through the flowlines. Projectile size alone does not necessarily determine the risk to equipment; projectile momentum will dictate the opposing force required to halt the projectile. Various unproven or estimate based procedures can be implemented to minimise projectile risk.These are beyond the scope of this paper, but still retain a level of risk. An example of how to control this effect is to perform depressurisation slowly, with regular hold periods, to reduce the differential pressure across the plug.

Rapid depressurisation

When the pressure is lowered in the system to achieve hydrate dissociation conditions (see Fig. 3), the plug surface temperature can drop considerably below ambient temperature due to the Joule-Thomson effect, as gas liberated from the hydrate plug simultaneously expands and cools. Hydrate dissociation is a heat and mass transfer process where ambient seawater supplies the required latent heat energy for the hydrate to dissociate; heat influx is absorbed through the pipe wall. Where trapped gas is flowing through a porous plug, the Joule-Thomson effect is thought to promote hydrate formation. Rapid depressurisation exacerbates the JouleThomson effect, reducing the temperature and increasing hydrate growth. Hydrate formation will cease once sufficient heat energy is recovered from the ambient seawater through the pipe wall, providing that hydrate dissociating conditions exist. Line 1 in Figure 4 illustrates this scenario. Slow depressurisation allows for heat influx from the ambient surroundings, however hydrate dissociation would APPEA Journal 2011--203

H. Sheil, P.Young and M. Richardson

figure 2. multiple hydrate plugs.

figure 3. Typical hydrate dissociation curve (inc. Ambient seawater temp at xt). not take place in a timely manner. This is illustrated by line 2 in Figure 4. The most time effective method to dissociate a hydrate is to use an intermediate pressure reduction rate or perform a series of incremental pressure drops--termed step-wise depressurisation--to balance the heat influx and JouleThomson effect. Thermal coatings on the flowline severely impede hydrate remediation. The heat transfer between the ambient seawater and the hydrate is reduced and consequently the Joule-Thomson effect may dominate, considerably reducing the flowline internal temperature. insufficient pressure relief then pressure will build up and may exceed the pipe wall design limits. In the most severe case, pressure accumulation may cause catastrophic failure of the pipe wall. Figure 5 illustrates this failure mode. Catastrophic failure of a pipe wall due to active heating occurred onboard a Statoil platform in the mid-1980s (SINTEF, 2000).


Depressurisation (DSD or SSD) is the industry preference. The water depth and liquid density are critical to the efficacy of this approach. Disposing of hydrocarbons under their own pressure may be insufficient to achieve the required hydrate dissociation conditions. Figure 3 illustrates the pressure required to dissociate the hydrate over a range of temperatures. During depressurisation the temperature is determined by the ambient seawater temperature at the hydrate location, however this neglects the Joule Thomson and heat exchange effects described above. For example, if the minimum ambient temperature of a flowline in 500 m of water is 6.3°C, to

Pipe wall catastrophic failure

Active heating of the pipe in the hydrate location can lead to catastrophic failure of the pipe wall. With limited knowledge of the hydrate plug location, a significant difficulty arises in how to apply heat safely to the hydrate blockage(s). Applying heat to the middle of a hydrate plug can liberate large volumes of gas. If the plug porosity provides 204--APPEA Journal 2011

Cost reduction of subsea gas production systems using emerging hydrate remediation technology

figure 4. depressurisation rate (Sloan and koh, 2008). achieve hydrate dissociation conditions the pressure is shown to be less than 12 bar. It is anticipated that other influences may cause the head pressure to exceed 12 bar; one example might be the injection of THI to dissociate the hydrate plug. Should the static liquid column exceed 110 m the pressure would exceed 12 bar and begin to counteract any residual benefit of using THI. To further reduce the pressure any of the following methods can be contemplated: · THI can be injected to increase the hydrate dissociation temperature; · Gas lift can be used to transport liquids to surface and thereby reduce the pressure head; or, · Pump hydrocarbons to surface. This may be completed by multiphase pumping, separating liquids and gas subsea and pumping the liquids to surface, or using a venturi system.

figure 5. direct heating of hydrate plug (Roar, 2009b).

Inability to pig

Following partial hydrate dissociation the plug remains should be completely removed from the system. This may be completed by flooding with adequate THI to completely disperse the plug. Dual flowline systems are typically configured to deploy and receive a pig train on the host facility. The pig train might remove the dissociated hydrate plug from the system to the facility for disposal. Pigging of single flowline systems would require a subsea pig trap. Typically a pig would be deployed subsea and propelled to the host facility, removing the dissociated hydrate remains. Pigging is highly problematic in both dual and single flowline cases. The length of a hydrate plug can be at least an order of magnitude greater than the pipe diameter and is frequently above 15 m (Sloan and Koh, 2008). Consequently the hydrate plug can exceed the length of the pig trap, making isolation of the pig trap difficult. Removing the dissociated plug by pigging offers no benefit and is considered to be highly detrimental in some instances. This study does not consider pigging to be a viable option for hydrate remediation.

Incorrect application of THIs

Some THIs are incompatible with LNG facilities. Methanol is an example of a THI not suitable for hydrate remediation on LNG facilities. Methanol is more effective at dissociating hydrates than MEG, however methanol contaminated hydrocarbons have adverse effects on LNG dehydration at the facility. Selection of a THI must therefore be thoroughly analysed for potential knock-on effects. THIs may be an ineffective hydrate dissociation method for some scenarios. The challenge of using THIs is getting the inhibitor into contact with the hydrate. The flowline bathymetry and location/availability of injection/vent access points can prevent the inhibitor from reaching the hydrate. In undulating bathymetries (see Fig. 2) pockets of trapped gas in the flowlines can obstruct the flow of THIs from reaching the hydrate. The distances between the injection/vent access points should be minimal to reduce this effect. The inclusion of several injection/vent access points throughout the system is a key enabler for getting THI to the hydrate plug.


Globally, only four examples of previous hydrate remediation case studies could be identified (for further details see Appendix A). They are as follows: · ARCO Orwell, 1996--Hydrate remediation on the UKCS completed by depressurisation using an FPSO. · BP Whittle and Wollaston, 2005--Helix Well Ops Seawell LWI vessel depressurised pipeline on UKCS. · ExxonMobil Mica, 2004--Depressurised pipeline via DSD to the facility in Gulf of Mexico, taking 60 days. · Statoil Tommeliten Gamma, 1994/95--19 hydrate formation experiments were performed to gain knowledge on hydrate management. Roar (2009a) mentions that Petrobras experienced ca. 5 hydrate blockages per year, and it is understood that their interventions to date generally required a MODU. APPEA Journal 2011--205

H. Sheil, P.Young and M. Richardson It is concluded that hydrate remediation case studies are poorly documented in the public domain.

Light well intervention systems

To date, the focus of most offshore support vessel (OSV) based LWI systems has been to avoid bringing any hydrocarbons on board the vessel. The combination of delayed availability and high day rates of MODU type vessels presents limited cost benefit for vessel-based hydrate remediation over alternative methods (e.g. installation of a permanent utility line for depressurisation). Coiled tubing (CT) service lines have been contemplated. The introduction of these lines had significant additional costs and they have been excluded from further study. The objective of this study was to identify LWI service providers with the capability (or potential capability) of providing lower cost and increased availability of LWI vessel based hydrate remediation. It is important to differentiate between downhole hydrate remediation and flowline hydrate remediation. Downhole hydrate remediation typically involves flushing with a THI to dissolve small quantities of hydrate in the tubing, wellhead and XT. Flowline hydrate remediation will likely entail depressurising large volumes of hydrocarbons, which is currently not a typical LWI service provider task--in fact most LWI service providers have gone to great lengths to avoid bringing hydrocarbons to surface. Flowline hydrate remediation is not widely documented, which indicates a technology gap. All LWI spreads have some common characteristics. The LWI spread connects to the XT and provides the capability to perform limited wellbore intervention with adequate pressure control, pressure barriers, and operational features such as rapid disconnection. In deeper waters (~>500 m) the LWI spread would typically be located into position, without guide wires, using a guidance funnel. In shallow waters the LWI spread may be located using guide lines and guide posts to counteract environmental forces. The LWI spreads may be limited by the XT design and the selection of conventional or horizontal XTs. Horizontal XTs generally require plug(s) to be set/unset with wireline and hence the XT is no longer a pressure controlling device during the intervention works. LWI spreads for horizontal XTs thus require an additional pressure control capability placed on top of the XT. Connecting the vessel through open water to the LWI equipment subsea are the wireline and an umbilical. The wireline passes through a grease box, or stuffing box, on the subsea lubricator, and controls the wellbore tools. Some LWI spreads provide a CT capability in addition to the wireline capabilities. CT enables some additional mechanical conveyance (pushing and pulling), fluid pumping and communication. The umbilical provides communication between the vessel and subsea equipment spread via hydraulics and usually electronics. It also supplies chemicals to the LWI spread. A wellbore tool (or multiple tools) are held in a lubricator.The lubricator is a pressure containing device attached on top of the XT. Some lubricators have the ability to hold several tools allowing the operator to change tools without


To perform DSD hydrate remediation on a single flowline system without a MODU, suitable system access points are required to reduce the pressure upstream of the hydrate plug. System access for MODU-based hydrate remediation is through the XT using the marine drilling riser. Available system access points need to be identified on the system in question to recognise potential analogue hydrate remediation methods. The findings from this study can be summarised as follows: · Hydrate remediation should be completed by DSD when practical to minimise the projectile risk. · THI injection can help the hydrate dissociation to be completed in a more time efficient manner. · THI must be injected at relevant locations to ensure contact with the hydrate. · A THI may be suitable for hydrate remediation, however it may cause problems at the facility. · The local pressure at the hydrate plug must be maintained below the relevant hydrate formation pressure. · Plugs are most likely to form where liquids collect, and multiple plugs may form in a flowline as a result. · Where multiple plugs form it may only be possible to perform SSD and hence the projectile risk must be managed. · The following methods are considered unsuitable for hydrate remediation: localised heating of the hydrate, removal of plug via pigging, system access using coiled tubing.


Further work was carried out to identify contractors that have suitable analogous systems or capabilities. The available technology predominantly focuses on downhole LWI tasks, and not specifically on hydrate remediation. The service providers identified were then approached about their potential hydrate remediation capabilities. A hydrate remediation system enabling a DSD in deep water must possess the following functional requirements: · Deliver hydrocarbons to surface for disposal without hydrate formation occurring in the conduit, using diverless intervention; · Suitably establish hydrate dissociation conditions in the flowline/XT recognising that time efficiency is a primary business driver; · Store and reticulate the chemicals necessary to negate the possibility of hydrates or other solids forming in the lines to the surface facility; and, · Ability to lift, receive, process and either store or dispose of formation and condensed water. 206--APPEA Journal 2011

Cost reduction of subsea gas production systems using emerging hydrate remediation technology the need to recover the lubricator to surface. Lubricator length does vary between spreads and may limit the available tools. The lower well control assembly typically contains a small bore BOP system to provide additional barriers to the environment for intervention activities. The assembly houses valves and/or rams capable of cutting through intervention tools and wire. An XT interface assembly acts as an interface between the LWI spread and the XT. The interface assembly is an XT specific device that is required to mate the systems together. LWI providers generally may not publicise any hydrate remediation capability, since the business focus thus far has been on downhole intervention activities, therefore identifying downhole activities analogous to hydrate remediation is important to recognise potential hydrate remediation service providers. Such activites include cementing, well abandonment, scale squeeze, well test and well clean-up. LWI is still an evolving area and is seen as a key emerging market, however intervention has been completed utilising these techniques for more than 20 years (Scranton, 2006): · First subsea intervention--BP Magnus July 1987. · First field abandonment--Argyll field, Hamilton Brothers, January 1993. · First subsea wellhead machining repair--Ellon field, Total, April 1995. · First subsea XT change out--Ivanhoe/Rob Roy field, November 1995. · First subsea CT intervention--Gannet field, Shell Expro, December 1997. · First recover/re-installation of an Electronic Submersible Pump XT--Gannet field, Shell Expro, January 1998. · First intervention into a horizontal XT--Arkwright field, Amoco, October 1998. · First deep water field abandonment (Horizontal XTs)-- Cooper field, EEX, August 1999. · First diverless well de-commissioning operation in North Sea--Tommeliten, Statoil, June 2000. The outright purchase of a LWI spread is anticipated to cost some US$6­30 million (2006), depending on its capabilities (Scranton, 2006). There are three LWI service providers that claim to be capable of supplying systems that satisfy one or more of the identified functional requirements. No service provider currently provides a complete turn-key system. It is recognised that the LWI market is embryonic at the moment, and expected to grow substantially once a level of general acceptance is reached. It is anticipated that a bleed-off package will require ca. 750 m2 deck space and 10 operators (five per shift). As required by the safety case philosophy, the risk involved in installing and operating this equipment on an intervention vessel is to be subject to an assessment. The risks should be as low as reasonably practicable.The vessel functional requirements are discussed later. To depressurise the flowline and dispose of the hydrocarbons from a vessel, the well test (or bleed-off) package may be similar to that used for well testing onshore or on a MODU. Hence the relevant guidance can be found in the publications such as codes for hazardous area classification (American Petroleum Institute, 1997), and the vessel classification society rules and guidelines. Figure 6 illustrates the components included in a typical well test and flare/vent package.

Plug locating technologies

It should be recognised that identifying a hydrate plug's location is very important. Failure to distinguish between a single plug and multiple plugs could lead to catastrophic failure from projectiles. If the plug size is underestimated, then the equipment may be incorrectly specified, leading to equipment failure, excessive duration, or additional trips to port. Therefore a method of non-intrusive non-contact detection is required to determine the size, location and number of hydrate plugs from outside the pipe wall. A brief investigation found hydrate plug detection systems in existence but the suitability for this application is not yet entirely clear.


This section presents typical vessel requirements for LWI. The information has been gathered from the LWI service providers and through dialogue with vessel suppliers. Recognising that LWI vessels are anticipated to be an area of dynamic growth, forecasting vessel availability in Asia Pacific is difficult.

functional specification

It is anticipated that a vessel suitable for completing hydrate remediation activities in Australia will require the following functional specification: · Based on input from the GoM contractors, the vessel needs to be an MSV/DSV/OSV, length > ca. 100 m. Available deck area ca. 1,000 m2; · Dynamic positioning: DP class 2 or better; · Dual work class ROVs with relevant valve operating tooling; · Active heave compensated crane suitable for ca. 20 tonnes and relevant WD; · Offshore installation safety case applicable to operating in Australia. (The legislative requirements are in APPEA Journal 2011--207

Well test or well bleed-off package

Discussions with a LWI service provider indicate that their previous hydrate remediation activities have been completed using a well test spread. Further discussions with well test engineers indicate that a bleed-off package may be a more suitable option, providing a cheaper alternative with lower manning requirements.

H. Sheil, P.Young and M. Richardson

figure 6. Well test and flare boom package. Commonwealth Of Australia, 2006, 2009); · Relevant class notification. (Note that no current classification currently exists specific to this practice, hence vessels are not easily identified as being so capable. This situation is currently evolving.); · Suitably sized moonpool preferred; · Adequate deck space; · Well test (or bleed-off) spread complete with flare boom; and, · LWI spread, handling devices, CT units, etc. quire some level of modification; however the vessels are capable of deploying LWI spreads and, crucially, they are expected to be cheaper than full scale MODU semi-subs.


The day rates for suitable LWI vessels will be at a considerable premium compared to those for typical current OSVs, possibly by a factor of around 2.0 to 2.5 as noted in Figure 7 (after Scranton, 2006). This high cost is predominantly for two reasons; firstly the relative novelty of performing LWI and similar types of intervention works from OSVs rather than MODUs, and secondly, the relatively sparse distribution around the world of suitable OSVs/MSVs. There is a reasonable likelihood that mobilisation of a suitable OSV would be costly, since such a vessel is anticipated to have to transit into the Asia Pacific region to perform a flowline depressurisation mission. For these reasons it is hard to draw any meaningful conclusion at this stage about the relative overall cost of performing the job between an OSV- or a MODU-based approach.

Suitable vessels

Provision of LWI vessels is an emerging market that is currently attracting significant investment worldwide. It is anticipated that the LWI vessel market will change considerably by the time the significant projects on the Australian North West Shelf are ready for start up in 2014­18. A list of existing and planned LWI vessels was compiled to gauge the current vessel capability. Vessels are available, but may not necessarily satisfy all of the requirements discussed previously, and will probably re208--APPEA Journal 2011

Cost reduction of subsea gas production systems using emerging hydrate remediation technology


Hydrate remediation capabilities exist and are currently mainly located outside the Asia Pacific region. Three service providers offer potential systems. Two further service providers offer systems that may be suitable but would require further investigation. Each hydrate remediation system needs a suitable access point into the subsea production flowline system. Gaining access through an LWI spread does require significantly more equipment, procedures and risk (operational and equipment) when compared to merely using pre-installed injection/vent access points. Furthermore, the inclusion of injection/vent access points throughout the system enables greater flexibility than is available to an LWI spread alone. The hydrate remediation systems have a functional requirement to reduce the pressure below hydrostatic conditions, hence the hydrocarbons are bled down and transported to the surface. This will ultimately need some level of assistance to reduce the pressure to hydrate dissociation conditions.The three service providers suggested hydrocarbon disposal to be completed using a well test spread or bleed-off package accompanied by a flare or vent. No alternative method was presented (e.g. floating flare or direct venting subsea). The potential systems presented by the three service providers all require at least two fluid conduits to surface, and a control umbilical. The two conduits to surface can be CT or collapse resistant hose, and are required for simultaneous THI injection and hydrocarbon return. All hydrate remediation methods suggested are required to be deployed from a suitable vessel. Vessels with suitable class notation and safety case to temporarily use well test equipment are scarce in the current market. Vessel classifications are under development for LWI vessels and notation requirements are uncertain at the time of writing. Vessel modification based on appropriate risk assessment is a potential method to make a vessel suitable for hydrate remediation activities.

figure 7. Well intervention vessel categorisation. existing hydrate remediation methods proposed by three companies are located outside the Asia Pacific region. To mobilise the equipment urgently without an existing contract is anticipated to be a lengthy and costly process. A suitable vessel of opportunity unlikely to be immediately available hence identifying, securing and transiting a vessel will be the greatest threat to a timely remediation. Engineering would be required to integrate the vessel and well test/bleed off package. This should include hazard identification studies (HAZIDs), contingency procedures, king post and flare boom analysis, etc. Hydrate remediation in a timely manner is a primary business driver in many subsea developments.The duration of deferred production may be greatly reduced with some effective pre-engineering.The objective of this work would be to have all of the appropriate contracts, procedures, documentation and risk assessments in place and accepted in advance by the relevant stakeholders. Typical existing subsea systems possess limited access points, hence flowline system access would typically be limited to two locations: LWI at the XT, and depressurisation at the host facility. However the inclusion of injection/ vent access points throughout the system (including at the XT, PLEM, In-line Tees and manifolds) reduces many of the operational and equipment risks of deploying a LWI spread.


This paper investigates alternative hydrate remediation methods by light weight intervention. Initial investigation showed that hydrate remediation by light well intervention (LWI) as such is unlikely, as no such capability presently exists; however this paper has identified that LWI service providers offer alternative systems that may be capable of hydrate remediation of gas flowlines. Since most current LWI spreads focus on avoiding bringing hydrocarbons onboard a vessel, very few of these vessels are immediately suitable for flowline hydrate remediation operations. Furthermore, should a suitable vessel become available, the hydrate remediation equipment spread must possess adequate safety measures for deployment and operation from the vessel (e.g. a failsafe emergency disconnect system). Suitable contracts and extensive engineering are required to remediate a hydrate in a timely manner. The


AMERICAN PETROLEUM INSTITUTE, 1997--ANSI/ API RP 505 Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, and Zone 2. Washington DC: API. COMMONWEALTH OF AUSTRALIA, 2006--Offshore Petroleum and Greenhouse Gas Storage Act 2006. COMMONWEALTH OF AUSTRALIA, 2009--Consolidated Offshore Petroleum (Safety) Regulations 2009. APPEA Journal 2011--209

H. Sheil, P.Young and M. Richardson DENNEY, D. (Ed), 2006--Flow Assurance Lessons: The Mica Tieback. Accessed 31 January 2011. <http://www.spe. org/spe-site/spe/spe/jpt/2006/06/5278447Syn18384.pdf>. ROAR, L., 2009a--Natural gas hydrates--the mother of all flow assurance challenges (field examples slides). Accessed 27 July 2010. < innhold/Notater/NewHydrate/6%20-%20Field%20examples%20slides.ppt>. ROAR, L., 2009b--Natural gas hydrates--the mother of all flow assurance challenges (safety slides). Accessed 22 July 2010. < Notater/NewHydrate/7%20-%20SAFETY%20slides.ppt>. SCRANTON, J., 2006--Subsea Well Intervention. RPSEA Forum, Massachusetts Institute of Technology, 31 October. SINTEF, 2000--Turning problems of gas hydrates to advantage. Accessed 27 July 2010. < volume-60/issue-4/technology/sintef-turning-problems-ofgas-hydrates-to-advantage.html>. SLOAN, E.D., 1998--Offshore Hydrate Engineering Handbook. Plano, TX: ARCO Exploration and Production Technology. SLOAN, E.D. AND KOH, E., 2008--Clathrate Hydrates of Natural Gases, Third Edition. Boca Raton, FL: CRC Press. figure 8. Arco orwell hydrate remediation setup. methanol into the plug and determined the plug's location. Some slight pressure increases were observed during depressurisation as gas pockets suddenly released as the plug dissociated.

BP Whittle and Wollaston

Location: Southern North Sea Basin, UKCS. Water Depth: ~40 m. Reference: Sloan and Koh, 2008. The MSV Stena Seawell (currently the Helix Well Ops Seawell) was mobilised. The Seawell is a light well intervention vessel that pioneered LWI performing its first well intervention in 1987. The Seawell transited to Block 42 for BP complete with a basic 10k psi well test package, flare boom and hydrocarbon returns package. The field layout is shown in Figure 9. Divers were used to remove subsea flanges and tie-in the temporary hook up, as shown in Figure 10. A series of bleed off stages were performed to dissociate hydrate formations spanning a 1.5 km section of the main Wollaston 8-inch production tie back to the Cleeton platform.This operation was performed at both ends of the pipeline in approximately 40 m water depth and during spring tides to manage the differential pressure across the plug. The hydrate was successfully dissociated six days after the vessel left location.


Location: Architecture: Thames Area, UKCS. 34km 16-inch flowline with pigg backed 3-inch MEG line. Water depth: ~32 m. Reference: Sloan, 1998. Hydrate removed successfully without equipment failure by connecting an FPSO vessel to the spare slot on the manifold using a flexible hose. Note this was a very fortunate and unusual chance occurrence. The pipeline was depressurised using the flare stack on the FPSO; consequently no platform modifications were required. A subsea skid was fabricated for an ESDV and MEG injection/vent access point, the skid was connected to the manifold by a tie-in spool. Concrete mattresses and gravel bags provided stability of the flexible hose on the approach to the skid. Figure 8 illustrates the set up used in the remediation. The depressurisation took 23 days to dissociate the hydrate; heat transfer between the pipeline and ocean was slow due to pipeline burial. Further, it was determined that the pressure in the pipeline must not drop below 12 bar otherwise ice may form despite the hydrate dissociation. The pipeline was occasionally back-pressured; this drew 210--APPEA Journal 2011

Exxonmobil mica

Location: Architecture: Gulf of Mexico ~47 km 8-inch uninsulated gas flowline, ~47 km 8 ½ inch insulated PIP oil flowline. Water depth: 1,325 m. Hydrate mitigation: Continuous methanol injection up stream of choke and at manifold. Reference: Denney, 2006; Roar, 2009a. A hydrate plug occurred in the gas flowline during an emergency shut down (ESD). The hydrate plug was located away from the facility, close to the manifold. The

Cost reduction of subsea gas production systems using emerging hydrate remediation technology

figure 9. BP Whittle and Wollaston field layout.

figure 10. Seawell subsea connection. APPEA Journal 2011--211

H. Sheil, P.Young and M. Richardson gas flowline was depressurised to atmospheric pressure to dissociate the plug. A valve was opened to relieve additional pressure from the upstream side of the plug. It took 60 days to remediate the hydrate from the ESD to remove the plug and re-start production in the flowlines. Two lessons learned can be taken from this case study: 1. In retrospect, it was recognised that it may have been more time-efficient to keep injecting methanol into the flowline, letting it slowly diffuse through the slightly porous plug and hence dissociate it; and, 2. The gas flowline was being controlled by the topside choke rather than the subsea choke before the ESD. In this case, the methanol-injection rate had been optimised for operational control via the subsea choke (with a much lower pressure in the flowline). When control of the flowrate had been changed to the topside choke and the pressure in the flowline increased by more than 69 bar, the methanol rate should have been increased accordingly, but was not.

Statoil Tommeliten Gamma

Location: Norwegian Continental Shelf Architecture: 11 km 6-inch flowlines to the Edda Platform. Water depth: 75 m. Reference: Roar, 2009a; SINTEF, 2000. In 1994/95 SINTEF personnel were allowed to carry out 19 hydrate formation and remediation experiments on a 11 km 6-inch service line on Statoil's Tommeliten Gamma subsea development. A mass of useful data was collected, some of which has yet to be fully analysed. The field has since been decommissioned. One of SINTEF's most important findings was that hydrate plugs are not imporous, as ice plugs formed from water are. Statoil have reported seeing plugs with porosity in excess of 50%. Consequently the water content of the fluid stream need not be high to enable hydrate plugs to form. As gas permeates through the plug, it undergoes expansion cooling due to Joule Thomson effects, which leads to further growth of the plug. Hence the plug can grow despite the flow stopping. Cases have been known of a single plug being several kilometres long. Key learnings are summarised as: · Easy and quick hydrate formation--subsea and topside; · Under inhibition increases plugging risk; · Hydrate plugs are typically porous and permeable; · Joule-Thomson cooling on low pressure side of plugs enables hydrate growth; · Depressurisation and methanol injection effective melters; · Topside remediation best by heating and/or methanol injection; and, · Results were suspected to be system specific.

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Cost reduction of subsea gas production systems using emerging hydrate remediation technology


Henry Sheil has 28 years oil and gas facilities experience. He has worked for both operating companies and consultants/service providers, initially in the North Sea sector, and since 1991 in the Asia Pacific region. His initial professional experience was gained working in oil and gas production and facilities, and gas turbines. He is a generalist practitioner in the area of subsea production systems, with particular interest in subsea trees, control systems, flowline connection systems, flexible flowlines and umbilicals, subsea hydraulic and electrical distribution, and subsea construction and intervention utilising remote (i.e. diverless) technology. Henry holds a first class honors degree in mechanical engineering from NUI (dublin) in Ireland, attained Chartered Engineer status in 1988 through the Institution of Engineers of Ireland (C.Eng.mIEI), and has a Graduate diploma in Business from Curtin University in WA. member: SPE and SUT (in the Uk and Australia). PeterYoung is a senior pipeline engineer with more than six years oil and gas experience in both the upstream and downstream sectors of the industry, having been employed by Shell, BP, JP kenny and Peritus International. Working in all engineering phases, Peter has knowledge of pipeline design, pipeline repair, pre-commissioning, pipeline installation contingency planning, reliability, maintenance and operations. Peter has worked on significant projects including the Woodside Browse, Sunrise and Pluto LNG Projects on the Australian North West Shelf, and the BP Harding Area Gas Project on the UkCS. Author of two papers, Peter is presenting them both nationally and internationally. further, Peter has practical field experience aboard a diving support vessel, an oil platform and at an oil refinery. Peter holds an mSc(res) in Advanced mechanical Engineering from University of Sheffield, and a BEng(Hons) in mechanical design and Technology from Northumbria University, Uk. Martin Richardson is a senior project engineer with Pöyry Pty Ltd. He has more than 18 years of international office and site-based engineering experience including oil and gas (onshore and offshore platforms, fPSo), LNG, petrochemical, pharmaceutical and aluminium manufacturing facilities. His project engineering experience includes instrument engineering, procurement, vendor management and factory and site testing. martin's site experience includes management and supervision of installation and construction contractors, cost and schedule management, progress reporting, inspection of site installations, and technical support for client organisations. martin holds an HNC in Industrial measurement and Control from the University of Teeside, and an oNC in Engineering from Longlands College of further Education, England.

APPEA Journal 2011--213

214--APPEA Journal 2011


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