16th International Oil Field Chemistry Symposium 13-16 March 2005, Geilo, Norway

LDHI OPPORTUNITIES FOR OFFSHORE EUROPEANPRODUCTION

L. W. Clark, J. Anderson, L. Frostman, and N. PoyntonBaker Petrolite

ABSTRACT

Low Dosage Hydrate Inhibitors (LDHIs) are gaining worldwide acceptance as a viable alternative to the more conventional methods of hydrate flow assurance control. Use of this LDHI technology in the European area is becoming more common as operators are beginning to implement and gain from the advantages of LDHIs.

This paper will review the basic applicability of the various LDHIs and will review LDHI case histories worldwide in order to show how this technology could be implemented to a greater extent into European production systems.

Case histories will illustrate the use and advantages of multifunctional products indicating how operating companies can reduce operating costs and capital expenditure through their implementation. Differing production scenarios will be covered indicating how different LDHIs can be used to cover a range of applications in the field, such as those found in the European region. These will cover both the use of Anti-Agglomerants (AA) and Kinetic Hydrate Inhibitors (KHI).

INTRODUCTION

Gas hydrate formation is an issue that needs to be considered as part of the offshore production of gas and oil. Gas hydrates form when natural gas molecules are surrounded by water molecules to form ‘cage’-like structures. Gas hydrates are crystalline structures that look similar in appearance to ice and have similar characteristics - with the difference that hydrates incorporate a natural gas guest molecule as part of the structure.1- 4 Typical hydrate forming gases include light hydrocarbons (methane to heptanes), Nitrogen, Carbon Dioxide and Hydrogen Sulfide. Hydrates typically form at lower temperatures and higher pressures. Depending on the gas composition and the pressure, gas hydrates can form at temperatures of up to 18°C where gas co-exists with water.5-6 Offshore wells and offshore transmission lines may be operating under conditions where hydrate formation is favourable. Gas fields typically require continuous hydrate protection from the beginning of their life cycle. This is required as the hot gas being produced cools as it flows from the well via an uninsulated subsea line - leading to the formation of condensate and water. Oil wells on the other hand may only start producing

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water a couple of years into their life cycle. From that point onwards they will require protection from hydrate formation.

Hydrate inhibition and control is an important part of the design and operation of offshore production systems in order to prevent the formation of hydrate blockages.7 Hydrate plug formation and subsequent remediation can be a costly occurrence. Hydrate plugs may take days to months to dissociate depending on the system conditions and the remediation actions taken. This is costly in terms of deferred production. The action of trying to locate a blockage (particularly in an offshore production system) is also difficult. Remediation options include depressurization and/or the application of methanol or ethylene glycol to help melt a hydrate plug. Other options include trying to apply heat to help speed up the melting of a hydrate plug. All options need to be carefully considered to minimize the risks involved, such as the liberation of significant quantities of gas in a short time frame from a hydrate plug if heat is applied to the hydrate blockage.

In the prevention of hydrate formation several options are available to operating companies. Thermal insulation may be used to reduce heat loss from subsea pipelines to their colder surroundings - such that operating conditions are warmer and less likely to lead to hydrate formation. Another option is to dehydrate offshore production fluids before they are transported - leading to the requirement of offshore dehydration process units. Both of these options require significant additional capital expenditure (CAPEX). Another option is that production pressure could be decreased to reduce the likelihood of hydrate formation. However, this has the associated costs of deferred production. Chemical additives to the production fluids are another option that may be considered.

LOW DOSAGE HYDRATE INHIBITORS

Chemical additives that could be used for hydrate inhibition can generally be divided into three categories;

1. Thermodynamic Hydrate Inhibitors,2. Kinetic Hydrate Inhibitors (KHI), and3. Anti-Agglomerants (AA).

Both KHIs and AAs fall into the category of Low Dosage Hydrate Inhibitors. A comparison of the three different types of hydrate inhibitor is provided in Table 1 below.

The Thermodynamic Hydrate Inhibitors lower the formation temperature of hydrates by approximately the same amount as they lower the freezing point of ice.8 This is because gas hydrate structures consist of hydrogen bonded water molecules as is found in ice. The Thermodynamic Hydrate Inhibitors compete with the water molecules in terms of hydrogen bonding - making the formation of hydrates thermodynamically less likely. Thermodynamic Hydrate Inhibitors include salts, methanol and glycols such as ethylene glycol. However, the Thermodynamic Hydrate Inhibitors have the disadvantage that significant quantities of Thermodynamic Hydrate Inhibitor material may be required to prevent hydrate formation, for example; typically 10 to 40-vol. % of methanol may be required to be added to the produced water of a system. There may also be safety issues

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Table 1. A comparison of the three different types of hydrate inhibitor.

HydrateInhibitorType

Thermodynamic Hydrate Inhibitors

Kinetic Hydrate Inhibitors (KHI)

Anti-Agglomerants(AA)

Relative Generally lower Low to medium Higher subcoolingApplicability subcooling systems subcooling systems systems or longer

where logistics of using (generally < 11°C residence timelarge quantities of subcooling if not systems wherechemical is not an using additional water cutissue. Thermodynamic

Hydrate Inhibitor).< - 50- 75 %.

Treatment Typically 10 to 40 vol. Typically 1 to 5 vol. Typically 1 to 5 vol.concentrationsranges

% of produced water. % of produced water. % of produced water.

Advantages • Established • Smaller volumes • Smaller volumestechnology. of chemical of chemical

• Chemicals may be required. required.recycled. • Low toxicity. • Application rate

• Can re-dissolve • Combination is independenthydrate deposits products possible. of subcooling.with slug • Cost effective as • Combinationtreatments. applied above. products

possible.• Effective during

extended shut-ins.

Disadvantages • Safety issues. • Do not appear to • Do not appear to• Logistics of using be able to re- be able to

large quantities of dissolve deposits. re-dissolvechemical - storage, • System dependent deposits.transportation and limited time of • Requireshandling. effectiveness - presence of

• Dosage increases prolonged shut-in liquidwith subcooling. may require hydrocarbon

• Incompatibly with supplemental phase.paraffin and chemical • Below 0°C,corrosion injection. Thermodynamicinhibitors. • Dosage increases Inhibitor will

• Downstream as subcooling need to be addedproblems at increases. to suppress icerefinery.

• Methanol lost to hydrocarbon phase - increasing dosage requirements.

• Some KHIs have a maximum pressure beyond which they are not as effective.

formation.

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that will need to be considered when considering the storage, transportation and handling of such large quantities of substances such as methanol.

The effective required Thermodynamic Hydrate Inhibitor dosage depends on the driving force for hydrate formation experienced in the system which is represented by the quantity ‘subcooling’. Subcooling is defined as the difference between the hydrate dissociation temperature and the system operating temperature at a given pressure. The higher the subcooling, the more severe the system conditions and the greater the driving force for hydrate formation. The effective dosage of a Thermodynamic Hydrate Inhibitor required to be used in the system increases as the subcooling increases. Obviously, this may lead to significant operational expenditure (OPEX) costs and logistical challenges when operating offshore systems, especially as the subcooling experienced in a system increases.

Partly due to the disadvantages of Thermodynamic Hydrate Inhibitors, the development of Low Dosage Hydrate Inhibitors (LDHI) has occurred over the last 15-years. LDHIs are so called as they can be successfully applied at lower dosages when compared to Thermodynamic Hydrate Inhibitors. LDHIs differ from Thermodynamic Hydrate Inhibitors in that LDHIs do not shift the thermodynamic equilibrium of hydrate formation but rather they become involved in the mechanism of hydrate formation in such a way as to interfere and modify the formation of hydrate crystals. These LDHIs are classified depending on the way in which they modify the hydrate crystal formation mechanism. The main two categories of LDHI are the Kinetic Hydrate Inhibitors (KHI) and the Anti- Agglomerants (AA). However, there are other surfactants which act as hydrate inhibitors by dispersing hydrate crystals as they form.9

KHIs are typically water soluble polymers which interfere with and delay hydrate crystal nucleation and the initial crystal growth process.10 They act in an analogous way to scale inhibitors in that they inhibit the formation of small crystals by their interaction with crystal growth sites. Clues to the chemical structures suitable for use as KHIs came from the observation in nature that certain fish had the ability not to freeze in sub-zero seawater temperatures. This was found to be due the ability of the fish to produce a protein that (like a KHI with a hydrate crystal) attached to an ice crystal and inhibited the further growth of the ice crystal.11 The effect of the KHI is to slow down the kinetics of hydrate crystal formation and increase the induction time for hydrate formation. First generation KHIs were based on polymers of pyrrolidone or caprolactam ring based structures.12 However these first generation KHIs also had limitations, such as the subcooling limits and the time limits to their effectiveness. The first generation KHIs were effective at controlling hydrates at up to 8°C subcooling for up to 24-hours. Kelland et.al. noted this when he proposed that the first generation KHIs had upper limitations on the subcooling that they could effectively control (of 10°C).13

If the severity of the system exceeds the effectiveness of the KHI then a rapid formation of hydrate material can occur. KHIs effectively provide a certain amount of hydrate inhibition time during which it is intended that the produced fluids are moved through and out of the hydrate forming conditions of the production process (by the operator).

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Ideally, the KHI treatment is designed such that the KHI induction time is greater than the produced fluids’ residence time in the hydrate region. The risk of the hydrate inhibition time being exceeded needs to be evaluated as part of the hydrate management strategy and adequate contingency plans put in place (such as possible system depressurization).Subsequent development of second generation KHIs and even third generation KHIs has extended the limit of subcooling effectiveness up to 11 to 13°C (for days to weeks depending on the subcooling).

KHIs have the advantage of requiring lower dosages than Thermodynamic Hydrate Inhibitors and the associated OPEX savings this brings about. KHIs also reduce the risk due to storage and transportation of large quantities of Thermodynamic Hydrate Inhibitor. KHIs also are not limited by the water cut experienced in the produced fluids or by gas to oil ratios and generally, KHIs are relatively environmentally friendly.

There are, however, many offshore systems that operate under higher subcoolings than can be optimally controlled using KHIs alone. In systems with higher pressures and cooler temperatures, subcoolings of higher than 10°C are common. In deepwater systems, subcoolings of the order of 20°C are not uncommon and even higher subcoolings in ultra- deepwater systems can occur.14 This led to the development of Anti-Agglomerant (AA) hydrate inhibitors.15

Anti-Agglomerants allow the hydrate crystals to form but in doing so, the hydrate crystals are kept small and non-adherent. These sub-micrometer sized hydrate crystals are well dispersed in liquid hydrocarbon, thus allowing the hydrates to be transported in the production fluids, as fluid viscosity remains low. The AA molecule functions via two chemical groups within its structure that have two important functions. Firstly, part of the AA is incorporated into the hydrate crystal structure.6 This is typically an organic quaternary ammonium or phosphonium salt. Secondly, the AA has a long hydrocarbon ‘tail’ that makes the combined ‘hydrate crystal - AA’ structure soluble in hydrocarbon fluids preventing the formation of larger hydrate crystals.

Due to their mechanism of hydrate inhibition, AAs require the presence of a liquid hydrocarbon phase (condensate or oil), typically with a water cut of < 50 to 75 % and a Gas to Oil ratio (GOR) of < 100,000 scf/stb. AAs have the significant advantage that they are not restricted by the subcooling of the system (seen to be effective at subcoolings above 22°C). They also perform well regardless of the system’s residence time in the hydrate region, including extended shut-ins of > 2-weeks. This makes the AA application rate the most cost effective at higher subcoolings.

In an effort to further lower the costs of offshore production for operating companies, developments and advances have been made in the formulation, testing and application of combination products.16 Instead of having a separate chemical application of LDHI or corrosion Inhibitor (CI) or Paraffin Inhibitor (PI) it is possible to produce chemically compatible formulations of these inhibitor chemistries. These include LDHI/CI, LDHI/PI and even LDHI/CI/PI combinations. LDHI combinations with scale inhibitors or asphaltene inhibitors are also under development. Offshore chemicals may be applied via

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umbilical lines where one umbilical line may be used, for example, for a PI and a separate umbilical line may be used for a LDHI. Through the use of combination products, fewer umbilical lines would be required - as only one line would be needed for the LDHI/PI application. The use of combination products may also lead to potentially less weight due to chemical storage overall, a smaller number of storage tanks and application pumps. This leads to CAPEX savings and reduced OPEX costs such as maintenance costs.

COMMERCIAL APPLICATION OF LOW DOSAGE HYDRATE INHIBITORS - KHIs

Following the initial field trials of KHIs17-18, offshore commercial deployments began in the mid-1990s19"20 followed by further applications.21-24KHIs are typically applied in systems which are experiencing low to medium subcoolings of 10°C or less. In these small or large applications they have proved to be cost effective. KHIs can be used to either replace the application of methanol or glycol or the KHI can act as a supplement to it - reducing the quantity of methanol or glycol required. The following field trial descriptions share offshore KHI field trial experience which relates directly to systems in Europe which may benefit from the implementation and use of KHIs.

CASE HISTORY #1

The use of a KHI was implemented by a major operator in an UK North Sea offshore application after the operator had experienced problems with the use of ethylene glycol as a Thermodynamic Hydrate Inhibitor. Production was principally gas and was being produced via a subsea template. The operator had been using the addition of ethylene glycol to inhibit the formation of hydrates in a 12-inch diameter, 16-km subsea gas flowline. Approximate daily production rates are given in Table 2 with production conditions provided in Table 3.

Table 2. Approximate daily production rates for Case History #1.

Gas / MMscf Condensate / Bbl Water / Bbl80 150 500 - 3000

Table 3. Production conditions for Case History #1.

Flowing wellhead pressure / bar

Shut-in wellhead pressure / bar

Flowing wellhead temperature / °C

Shut-in wellhead temperature / °C

65 150 36 4

Due to increasing water production and rising salt levels (~80,000 ppm) the regeneration of ethylene glycol became problematic due to salt precipitating out in the heating bundles.

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This resulted in frequent shut-downs of the ethylene glycol regeneration system for cleaning and maintenance. It also led to the subsequent discharge of the contaminated ethylene glycol directly to the sea. Additionally, maintenance costs for this system were escalating due to increasing corrosion failures. Due to the negative environmental impact of discharging ethylene glycol, the increasing maintenance costs and the costs for replacement ethylene glycol, it was decided to investigate alternative hydrate inhibition technologies, i.e. KHIs. The most suitable LDHI was a KHI due to the high volumes of gas being produced and relatively low levels of water and condensate produced.

Prior to KHI implementation, an extensive laboratory testing program was carried out under field conditions using worst case shut-in conditions. The KHI selected for field trial showed good hydrate inhibitor performance at sub-coolings of 10°C. Laboratory testing showed the KHI provided a similar level of inhibition as ethylene glycol but only required between 10 - 15% equivalent chemical. Treatment costs using the KHI were 40% lower than when using ethylene glycol. The KHI selected showed low emulsion­forming tendency, had good material compatibility properties, had an excellent environmental classification and provided lower treatment costs.

The KHI was successfully applied in the field at the dosage indicated by laboratory tests. However, during the field trial stage, offshore performance monitoring established that salt levels were higher than first thought and approaching 250,000 ppm when specific wells were producing. This significantly reduced the sub-cooling experienced in the system and subsequently the amount of KHI required and applied. Overall treatment saving costs were estimated at 80 % with additional operational savings being realized through reduced tank rental, logistical expense and maintenance costs. The use of the KHI enabled production targets to be maintained, which in turn meant that the required delivery volumes and schedules could be met.

Further product development was then carried out with a corrosion inhibitor (CI) being successfully formulated with the KHI to give a combined KHI/CI product.16 This led to further cost savings for the operator. The KHI and the combined KHI/CI equivalent were successfully applied in the field for 18-months before the requirement for hydrate inhibitor was no longer necessary due to the declining reservoir pressure - moving production out of the hydrate forming region. KHIs provided the benefit of having good environmental characteristics helping to minimize environmental impact and the KHI usage also helped to lower overall project costs - as illustrated in Table 4.

Table 4. LDHI applied and benefits obtained for Case History #1.

Application location Offshore UK North SeaLDHI applied KHI initially.

Development led to a combined KHI / CI.Thermodynamic inhibitor replaced MEG replaced by using

10 - 15 % equivalent KHI.Treatment cost savings 80 %

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CASE HISTORY #2

An offshore gas production platform in Latin America had frequent hydrate problems throughout the year. Hydrates were often a problem in topsides equipment at two locations as produced fluids passed through valves and tubing restrictions. Daily production rates are given in Table 5 with production conditions provided in Table 6.

Table 5. Daily production rates for Case History #2.

Gas / MMscf Condensate / Bbl Water / Bbl180 to 300 500 100

The produced fluids were separated, processed to remove most of the water and condensate was then injected back into the flowing gas stream further downstream of the separators. The water content in the re-injected condensate phase was on the order of 1 %.

Table 6. Production conditions for Case History #2.

System pressure / bar System temperature / °C Subcooling / °C69 - 79 10 - 16 3

The system was previously treated with 20 gallons per day (gpd) of methanol at one location and 8 gpd of a first generation KHI injected at the second location. The operator was looking to eliminate the use of methanol and improve on KHI cost-performance by switching to a new KHI product. KHIs are well-proven for gas systems which operate 3 - 6°C inside the hydrate region.

Extensive product development and laboratory performance screening led to the formulation of a new type of KHI. This product was recommended at a rate of approximately 7 gpd based on the water content in the export pipeline. The operator ceased injection of the incumbent KHI and began injection of the new KHI in late July 2004. Subsequently, the methanol rate was reduced in several steps down to zero. While the KHI product was dosed based on an estimated 1% water cut in the condensate phase, the measured water cut fluctuated from 0.5 % to 86 % during the field trial. The KHI continued to perform well in inhibiting hydrates even when slugs of water passed through the system. The system operated normally with no reported hydrate problems anywhere in the system.

The use of the new KHI enabled the operator to obtain the cost savings illustrated in Table 7. The use of the novel KHI also afforded reduced chemical transportation logistics, lowered HS&E risk by not having to handle methanol and reduced pump maintenance by using only one pump instead of two.

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Table 7. LDHI applied and benefits obtained for Case History #2.

Application location Offshore Latin AmericaLDHI applied 7 gpd of novel KHI.Thermodynamic inhibitor replaced 20 gpd Methanol and 8 gpd of

1st generation KHITreatment cost savings 30 % (or $16000 / year).

COMMERCIAL APPLICATION OF LOW DOSAGE HYDRATE INHIBITORS - AAs

Reports of AA field trials have become more widespread in the literature in recent years.5-8, 25-27 AAs are typically applied in systems which are experiencing higher subcoolings of 10°C or more. AAs are well proven for gas condensate and oil production systems which operate > 17°C (> 30°F) inside the hydrate region. The AA is limited by the system water cut (typically water cut is less than 50 to 75 %, varying from system to system). There also has to be sufficient liquid hydrocarbon to suspend and transport the dispersed hydrate crystals - this leads to usage in systems with Gas to Oil Ratios (GOR) of typically less than 100,000 scf/stb. In these higher subcooling applications, AAs have proved to be the most cost effective LDHI. The AA also has no limit concerning the protection that it can provide relating to the residence time in the system - i.e. it can provide long hydrate protection times at high subcoolings. AAs can also be used to either replace the application of large volumes of methanol or glycol in high subcooling applications or the AA can act as a supplement to it - reducing the quantity of methanol or glycol required significantly. The following field trial summaries share offshore AA field trial experience which could be used in the implementation of AAs in offshore operating systems in Europe.

CASE HISTORY #3

A single well template in the Gulf of Mexico gave the production outlined in Table 8, where it is also noted that the operator had the ability to circulate a corrosion inhibited oil (CIO - diesel) at approximately 275 bpd as required.

Table 8. Daily production rates for Case History #3.

Gas / MMscf Sour gas H2S content / mol. %

Water / Bbl Ability to circulate Corrosion Inhibited Oil (CIO - diesel) /Bbl

8 - 10 MMscf 7 - 10 300 275

Production was via a 6-Km (4-mile) long subsea flowline in 3 to 4 m (10 - 15 ft) of water to a main production deck.

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Flowing pressures typically ranged from 76 - 86 bar (1100 - 1250 psig). During the cooler winter months, when the surface air temperature could reach as low as 4.4°C (40°F) , continuous hydrate inhibitor was needed to prevent the subsea flowline from freezing up with gas hydrates. Initial KHI treatments (prior to Baker Petrolite’s involvement) resulted in 50% downtime in the winter months due to hydrate blockages.

A careful analysis of the system suggested that, in conjunction with the circulation of the corrosion inhibited oil, this system would be an excellent candidate for an anti- agglomerant (AA) low dosage hydrate inhibitor. Through the use of the corrosion inhibited oil, the level of liquid hydrocarbon would be increased in the system such that the AA could now function - by allowing small hydrate particles to form, but keeping them small, non-adherent and dispersed in the oil phase. The AA provided the advantage that its hydrate inhibition would not be time dependant - as had been the case with the KHI. It would also provide the necessary protection at a fraction of the dosage of the methanol or glycol alternatives.

The AA was chosen for this application due to its successful treatments of other Gulf of Mexico subsea lines. It proved to be a successful application with the AA now having been applied (from November to March) through two winters at a rate of 7500 ppm (based on the water phase). This was equivalent to 0.32 gal LDHI/bbl water produced. This was done in conjunction with the circulation of the corrosion inhibited oil. No hydrate problems occurred during application. However, it was demonstrated that the system was still in the hydrate forming region, as when the AA was inadvertently under­dosed (due to chemical injection pump problems) hydrate problems were identified. After remediation and reinstatement of the correct AA injection rate, the system resumed normal operations - with no hydrate issues.

The use of the AA led to a significant increase in uptime for this system. The operator noted an incremental 308 MMscf production sustained over a 4-month period. The incremental production yielded an incremental revenue of $1.2 MM during the LDHI injection period. In addition to the improved uptime and incremental production benefits listed in Table 9, the AA (when properly dosed) has eliminated the need to remediate sour hydrate blockages in the line. Hydrate plugs, particularly in sour systems, pose a potential hazard to personnel, equipment and the environment during remediation. Use of the AA significantly reduced the HS&E risks associated with operating this line in the winter months.

Table 9. LDHI applied and benefits obtained for Case History #3.

Application location Offshore Gulf of MexicoLDHI applied 96 gpd of AA.Hydrate Inhibitor replaced Non Baker Petrolite KHI treatmentIncremental revenue due to incremental production

$1.2 MM.

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CASE HISTORY #4

A deepwater Gulf of Mexico operator recognized that it had hydrate inhibitor issues when one of its three subsea wells began producing excessive amounts of water. The operator quickly found that their maximum methanol injection rate (175 bpd, 28 m3/d) was insufficient to control hydrates in the 39-Km (24 mile) gas condensate flowlines. The actual requirement was for 250 bpd (40 m3/d) of methanol. This forced the operator to start choking back the water producing well, which at the time was making 45 MMscfd of gas. After an extensive evaluation process, the operator requested a field trial of an AA.

The system had the production figures given in Table 10. The flowlines were in 610-m of water.

Table 10. Production conditions for Case History #4.

Flowing pressure / bar

Shut-in pressure / bar

Ambient temperature / °C

Water cut / %

Normal subcooling in subsea flowlines / °C

36-hour packed line shut-in subcooling / °C

260(3800 psi)

310 bar(4500 psi)

5.6 25 12.2 13.3

The LDHI trial began with a topsides injection of the AA to ensure that water treating would not be an issue. The AA was then slowly phased into the subsea system while methanol was phased out. The AA was then applied for over a month with no signs of hydrate problems. The operator even performed a 36-hour packed line shut-in to demonstrate that the LDHI could control hydrates during both normal and transient operations of 13.3°C (24°F) subcooling. The operator deemed this test a resounding success and decided to continue to pump the AA instead of methanol. Subsequently, a flowline corrosion inhibitor was also qualified to be co-injected with the AA. The subsea application proceeded smoothly for over 10-months.

The economic value of this trial was analyzed, as the AA application provided significant financial benefits to the operator (see Table 11 and Figure 1). Prior to the trial, the operator pumped 7400 gpd of methanol, which was insufficient to control hydrates, even in the curtailed production phase. Because of the low dosage rate (0.35 gal/bbl water, 0.8 vol.%) and low viscosity of the AA, the operator was subsequently able to open up the water producing well further during the trial while still injecting sufficient AA to control hydrates. The water rate rose to 1500 - 1600 bwpd, which was readily handled by 525 - 560 gpd AA. In effect, the volume of hydrate inhibitor chemical required had been reduced by a factor of 20 through the use of the AA. The use of methanol would have required 250 bpd (40 m3/d) of methanol to control the hydrates but the AA now gave hydrate control using 12.5 bpd (2 m3/d). The added gas production (20 MMscfd) more

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than compensated for the cost of the AA used. The increase in gas and condensate production, reduced transportation costs and reduced pump maintenance resulted in a $35 million dollar reduction in the total cost of operations. Increased capacity afforded by the AA program allowed the operator to recover an incremental 1.1x 1010 scf in hydrocarbon reserves from the field.

Table 11. LDHI applied and benefits obtained for Case History #4.

Application location Offshore Gulf of MexicoLDHI applied 12.5 bpd of AA.Hydrate Inhibitor replaced (effective) 250 bpd MethanolAdded daily gas production 20 MMscfd.Reduction in total cost of operations $35 MMIncremental recovery of hydrocarbon reserves

1.1 x 1010 scf

Figure 1. Hydrate Inhibitor volume reductions when replacing Methanol with AA.

Methanol: 250 bpd LDHI: 12.5 bpd

COMMERCIAL APPLICATION OF LOW DOSAGE HYDRATE INHIBITOR COMBINATION PRODUCTS

Hydrates may form in the presence of other oil field deposits such as paraffin. This is illustrated in Figure 2 which shows a solid sample consisting of hydrates within a solid carbonaceous deposit which had been retrieved from a process system under hydrate forming conditions. As discussed above, the development of LDHI combination products has several advantages for operators and a suitable LDHI/PI would help to prevent deposits of paraffin and hydrates such as that illustrated in Figure 2.

Case history 1 gave an illustration of the use of a KHI which was optimised to become an application of a combined KHI/CI product (whereas Case History 4 gave an illustration of the use of an AA with the option of co-injecting a CI). The following two case histories briefly describe the applications of other LDHI combination products.

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Figure 2. Solid carbonaceous deposit containing hydrates.

CASE HISTORY #5 - AA/PI COMBINATION PRODUCT

In the Gulf of Mexico, a deepwater application has been using a combined AA/PI since late 2001 in an uninsulated subsea oil line. In this case, the AA has been formulated in such a way as to be compatible with the paraffin inhibitor to give a suitable AA/PI combination product. The operator has reported no hydrate issues to date.

CASE HISTORY #6 - AA/PI/CI COMBINATION PRODUCT

An AA/PI/CI combination product was successfully applied in the Gulf of Mexico. The system consisted of an 11-km (6.9 mile) subsea tie back to another asset in 500-m of water. Production conditions are given in Table 12.

Table 12. Daily production rates for Case History #6.

Gas /MMscf Oil/Bbl Water cut/ % Expected brine salinity / ppm TDS

15 1800 -2000 1 110,000

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It was preferred that the hydrate inhibitor, paraffin inhibitor and corrosion inhibitor all be combined into a three component ‘cocktail’ as there was only one umbilical line to enable the chemical application.

After successful product combination, formulation and performance testing, the combination product was used successfully to help start up a subsea gas condensate line. The product was injected over a period of months during which time hydrate issues were successfully controlled. The product was eventually discontinued as paraffin deposition was no longer thought to be a serious issue.

CONCLUSIONS

Gas hydrate inhibition and control is an important consideration in the offshore production of oil and gas. Hydrate blockages and expensive remediation costs can be avoided by the appropriate use of hydrate control strategies. The use of chemical hydrate inhibitors forms an important part of such considerations. Low Dosage Hydrate Inhibitors have been developed and are becoming increasingly used in the field as a suitable, reliable and cost saving tool for hydrate inhibition and control.

KHIs are most effective at low and moderate subcoolings, where they can be used to replace or reduce existing methanol or glycol applications. Their suitability to gas, gas condensate or oil production systems is enhanced by their lack of Gas to Oil Ratio restriction and their ability to work without water cut restrictions. AAs are most cost effective at higher subcooling scenarios as they perform well regardless of subcooling and regardless of the system’s residence time in the hydrate forming region, including extended shut-ins. Their application is limited to systems with water cuts of < 50 to 75 % and with GORs of less than approximately 100,000 scf/stb as they disperse small hydrate crystals in the hydrocarbon liquid phase. Combination products have also been developed to combine LDHIs with other inhibitors including corrosion inhibitors and paraffin inhibitors.

A review of recent case histories illustrated that LDHIs add value to production systems through the OPEX and CAPEX savings that can be made through their use. These include savings to operators through lower chemicals costs, lower dosage rates leading to lower transportation and storage costs along with other logistical cost savings - such as smaller storage vessels and less frequent refills. Use of combination LDHI products (such as KHI/CI) can also lead to fewer umbilical lines being required resulting in CAPEX savings. The use of LDHIs can eliminate the use of methanol and the associated problems of the use of methanol, such as the adverse impact of crude containing methanol on refinery processes. The use of LDHIs can enable the successful treatment of higher water production in existing systems, leading to increased production and even extending the life of a well.

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9. Kelland M. A., Svartaas T.M. and Dybvik L., “Control of Hydrate Formation by Surfactants and Polymers", SPE 28506, presented at the 1994 SPE Annual Technical Conference and Exhibition, New Orleans, 25-28 September 1994.

10. Klomp U. C., Kruka V. and Reinjhart R. “Low Dosage Inhibitors: (How) Do They Work?", IBC Conference Proceedings, Aberdeen, 1997.

11. Franks F., Darlington J., Schenz T., Mathias S. F., Slade L. and Levine H., “Antifreeze Activity of Antarctic Fish Glycoprotein and a Synthetic Polymer", Nature, 1987, vol.325, p146-147.

12. Kelland M. A., Svartaas T. M. and Dybvik L., “Studies on New Gas Hydrate Inhibitors", SPE 30420, presented at SPE Offshore Europe Conference in Aberdeen, 5-8 September 1995.

13. Kelland M. A., Svartaas T. M. and Dybvik L., “A New Generation of Gas Hydrate Inhibitors", SPE 30695, presented at the SPE Technical Conference, Dallas, October 22-25, 1995.

14. Mehta A. P., Walsh J. M. and Lorimer S. E., “Hydrate Challenges in Deepwater Production and Operation", Annals of the New York Academy of Science, 2000,vol. 912, p366-373.

15. Klomp U.C., Kruka V. R., Reinjhart R. and Weisenborn J., “Method of Inhibiting the Plugging of Conduits by Gas Hydrates", U. S. Patent 5 460 728, 1995.

16 Clark L. W. and Anderson J., “Development of effective combined Kinetic Hydrate Inhibitor / Corrosion Inhibitor (KHI / CI) products", to be presented at the Fifth International Conference on Gas Hydrates, Trondheim, 13-16 June 2005.

17. Bloys B., Lacey C. and Lynch P., “Laboratory Testing and Field Trial of a New Hydrate Inhibitor", OTC 7772, presented at the 27th Annual OTC, Houston, 1-4 May 1995.

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18. Corrigan A., Duncum S. N., Edwards A. R. and Osborne C. G., “Trials of Threshold Hydrate Inhibitors in the Ravenspurn to Cleeton Line", SPE 30696, presented at the Annual Technical Conference, Dallas, 22-25 October 1995.

19. Argo C. B., Blain R. A., Osborne C. G. and Priestley I. D., “Commercial Deployment of Low-Dosage Hydrate Inhibitors in a Southern North Sea 69 km Wet-Gas Subsea Pipeline", SPE 37255, presented at the SPE International Symposium on Oilfield Chemistry, Houston, 18-21 Feb., 1997.

20. Argo C. B., Blain R. A., Osborne C. G. and Priestley I. D., “Commercial Deployment of Low-Dosage Hydrate Inhibitors in a Southern North Sea 69 km Wet-Gas Subsea Pipeline", SPE Production & Facilities, May 2000, 15(2), p130­134.

21. Talley L. D. and Mitchell G. F., “Application of Proprietary Kinetic Hydrate Inhibitors in Gas Flowlines", OTC 11036, presented at the Offshore Technology Conference, Houston, 3-6 May 1999.

22. Mitchell G. F. and Talley L. D., “Application of Kinetic Hydrate Inhibitor in Black-Oil Flowlines", SPE 56770, presented at the SPE Annual Technical Conference and Exhibition, Houston, 3-6 October 1999.

23. Leporcher E. M., Fourest J. M., Labes-Carrier C. and Lompre M., “Multiphase transportation: A Kinetic Inhibitor Replaces Methanol to Prevent Hydrates in a 12-inc. Pipeline", SPE 50683, presented at the SPE European Petroleum Conference, The Hague, 20-22 October, 1998.

24. Fu. B., “A Novel Kinetic Hydrate Inhibitor for Hydrate Control", presented at the IBC “Controlling Hydrates, Paraffins and Asphaltenes ” conference, Oslo, 7-8 Dec. 1998.

25. Frostman L. M., “Anti-Agglomerant Hydrate Inhibitors for Prevention of Hydrate Plugs in Deepwater Systems", SPE 63122, presented at the SPE Annual Technical Conference and Exhibition, Dallas, 1-4 October 2000.

26. Frostman L. M. and Crosby D. L., “Low Dosage Hydrate Inhibitor (LDHI) Experience in Deepwater", presented at the Deep Offshore Technology conference, Marseille, Nov. 19-21, 2003.

27. Furlow W., “LDHI advances enable longer tiebacks", Offshore, Sept 2002, p56 &129.

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