Hydrate Management in Practice - ACS Publications - American

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Hydrate Management in Practice Keijo Kinnari,*,† Jan Hundseid,† Xiaoyun Li,‡ and Kjell Magne Askvik§ †

Statoil ASA, N-4035 Stavanger, Norway Statoil ASA, N-7005 Trondheim, Norway § Statoil ASA, P.O. Box 70, N-5020 Bergen, Norway ‡

ABSTRACT: This paper describes the hydrate management strategies in Statoil’s gas and oil production systems. Hydrate management is a risk based approach allowing operations within the hydrate domain when the risk for hydrate plugging is concluded to be low. This is in sharp contrast to the hydrate avoidance approach practiced by Statoil in the past. Statoil has over 500 subsea wells and more than 100 subsea flowlines in operation. The hydrate management strategies take advantage of the intrinsic properties of the fluid systems, the hydrodynamics, and the plugging risk related to the amount of water present in the different parts of the production systems. This approach is based on a large body of research performed at Statoil and on extensive field experiences. Statoil’s current best practices in different production systems are described, and relevant examples from the field operations are provided.

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INTRODUCTION Hydrate control is likely the most challenging flow assurance area in the gas and oil industry due to its ubiquitous nature. If not properly addressed in design and operations, the result could be catastrophic, resulting in large economic losses. Hydrate-related problems have also caused great havoc on materials and the environment, and even fatal accidents have been experienced as a result of maloperation related to hydrate plugs. Hydrate control can thus not be treated in a haphazard way, but it requires a thorough and professional approach in order to achieve economically sound and environmentally and operationally safe production systems. Statoil is the main oil enterprise in Norway and has several global interests. Statoil had its first production in the Statfjord field in 1979. The Statfjord field comprises three concrete platforms and initially had only platform wells. Statfjord C was expanded in the mid 90s and 2000 with three satellite fields. However, the first subsea tie-in was the Gullfaks subsea well coming into operation in 1986. It took a few years before the subsea satellite production experienced its boom in the mid and late 1990s. Today Statoil has over 500 subsea wells and more than 100 flowlines in operation. Statoil is the second largest subsea producer in the world. The conditions in the Norwegian continental shelf are tough, demanding good robust solutions for production. These challenges are also carried over to hydrate control. The early hydrate control strategies followed the industry standard of that time. These strategies were extremely conservative. For example, the first operational strategies for the Gullfaks subsea systems required immediate methanol injection after an unplanned shutdown. Large amounts of chemicals were also to be injected into subsea wells to avoid any possible hydrate formation. In addition to being impossible to achieve in practice this approach also resulted in an enormous overuse of chemicals. We will see later in this paper how today’s strategies © XXXX American Chemical Society

have departed from this rather unnecessary and costly approach. It was realized quite early in the mid and late 1990s that a new practice was badly needed to improve the design and operational practice. Statoil coined the new approach “hydrate management” in contrast to the hydrate avoidance strategies deployed earlier, more or less the industry standard at that time. Hydrate avoidance and hydrate management concepts are schematically illustrated in Figure 1.

Figure 1. Hydrate avoidance versus hydrate management.

According to hydrate avoidance thinking, it is not allowed at all to enter the hydrate domain. In contrast, hydrate management strategy allows entering the hydrate domain if the risk is acceptable. As mentioned above it was quite obvious that hydrate avoidance could not be followed in practice in all cases. Considerable operational experience suggested that excessive Special Issue: In Honor of E. Dendy Sloan on the Occasion of His 70th Birthday Received: August 22, 2014 Accepted: October 2, 2014

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dx.doi.org/10.1021/je500783u | J. Chem. Eng. Data XXXX, XXX, XXX−XXX

Journal of Chemical & Engineering Data

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safety margins were used to avoid hydrate-related problems. Statoil therefore put a large amount of resources into improving understanding of the underlying processes and developing new improved strategies. A major cooperative program within multiphase technology was also initiated in the mid 1990s between the three different Norwegian oil companies, later to merge into a single company bearing the Statoil name. The merger resulted in a major enhancement in the hydrate control area, bringing together knowledge and experience from different approaches and thus complementing the knowledge base. This has allowed further implementation of new state-ofthe art approaches. This paper will provide an overview of the current best practice in Statoil based on the pioneering work done in the 1990s and 2000, supplemented with the latest operational experiences and R&D results.

Figure 3. Hydrate equilibrium temperature (HET) measured at 10 MPa for typical Statoil fluids as a function of mole fraction of the light components methane, ethane, and propane.

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universities). The in-house experimental facilities include hydrate cells and a flow simulator called “hydrate wheel”.1−5 In early 2000 Statoil constructed a flow assurance pilot at Kårstø with the objective of understanding hydrate plugging in a subsea system and how to apply it in field operations; see Figure 4.6

FLUID SYSTEMS Statoil produces a large variety of fluid types varying from heavy oils to gas condensates and practically liquid free gases. Figure 2 provides an overview of typical gas condensates and oils. Here the GOR (gas−oil ratio) is plotted against mole fraction of C10+.

Figure 2. Overview of typical Statoil fluids. Gas−oil volumetric ratios (GOR) at standard conditions (15.5 °C and 0.1 MPa) are plotted here against the mole fraction of the heavy hydrocarbons xC10+ (a lumped fraction containing all components in crude oil with 10 or more carbon atoms).

Figure 4. Statoil flow assurance pilot at Kårstø.

Statoil is a technology-driven company with a great interest in enhancing technology and its implementation in design and operation. This policy has allowed Statoil’s hydrate group to carry out several field trials. The organization of Statoil’s technology discipline also allows close contact between hydrate expertise, design, and operations. This allows quick identification of challenges, finding solutions and implementing these in design and operation. This has been the key factor in Statoil’s success in developing its hydrate control strategies and thus improving the overall economics through, for example, reduced chemical usage, reduced flaring, and extended operation time within the hydrate domain. Hydrate control is a broad theme and includes understanding of the hydrate related issues (prediction), knowing how to prevent or mitigate hydrate challenges (prevention), and knowing how to remediate any hydrate-related problem (problem solving). In Statoil these are also known as the 3P’s of hydrate control. Figure 5 illustrates the different available hydrate control options available to Statoil. The basis for everything is a sound

The hydrate properties also vary greatly for these systems. Figure 3 shows the impact of the light components methane, ethane, and propane on the hydrate equilibrium temperature (HET) at 10 MPa. Most of the fluids have HET in the band of (18 to 20) °C though there are systems with very low HETs and some with higher. Statoil has fields where the gas contains nearly methane, thus bringing the HET to about 13 °C at 10 MPa.

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HYDRATE MANAGEMENT The key issue in hydrate management is the understanding of plugging risk. Hydrate management is therefore a risk-based approach. It is of crucial importance to understand the factors that contribute to hydrate growth and finally to plugging. In order to find the answers to questions related to hydrate plugging risk Statoil has invested heavily in experimental work both in-house and at contractors (research institutes and B



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Figure 5. Hydrate control methods in Statoil.

Figure 6. Hydrate control methods for pipelines.

account in the final assessment. Nevertheless, the diagram does provide a kind of statistical overview over the field applications in Statoil. The next examples describe some of Statoil’s best practice in areas where our hydrate management approach is especially evident. Each of these cases are described and discussed separately. Hydrate Control of Wells. In the early days DHSVs (down hole safety valves) were typically installed at a depth where the ground temperature is above HET, the so-called hydrate safe depth. In addition methanol was to be injected as a part of any shutdown sequence. Cost drivers resulted in a quest for placing the DHSVs higher, thus bringing them outside the “safe” zone. After special studies, it was finally concluded that DHSVs can be installed higher. What is critical is the prevailing

understanding of the basic science and engineering aspects. The methods are dealt with in five different groups: (1) chemical methods, (2) thermal methods, (3) hydrodynamic methods, (4) process solutions, and (5) no hydrate control measures. Due to space limitations, we can only touch on some of these. Figure 6 illustrates the selection of a given hydrate control strategy for subsea pipeline systems. The horizontal axis shows the water content and the vertical axis the pipeline length. These are two key parameters in understanding hydrate plugging risk. The hidden message from the diagram is that hydrate plugging risk increases with increasing water content and pipeline length. For example, pipelines of a length up to 20 km are considered to have low hydrate plugging risk when the water content is low. Of course additional parameters like pipeline profile and fluid properties need also to be taken into C



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temperature in production wells after the well has been in production, and not the initial temperature. In addition in most cases there is enough gas such that the water level would anyway be gradually pushed sufficiently down into the warmer region. Statoil has therefore approved installation of DHSV at a minimum depth determined by authorities, in Norway at 50 m. It was also concluded early on that injection of chemicals into subsea wells is not necessary. This practice has therefore been eliminated from normal operations in Statoil. Hydrate control measures may still be necessary in platform wells where the water column extends into the riser or in subsea systems where the reservoir temperature is extremely low. Such measures are also necessary for water injectors where gas may be migrating into the injection well. Hydrate plugs have occurred in water injectors where this has not been done. Hydrate Control of Subsea Templates. Most of Statoil’s subsea wells are accessed from subsea templates. There are also, though, several subsea wells connected with a jumper to a central manifold. These jumpers are most often flexible, posing some additional hydrate control challenges. As mentioned, the hydrate control strategies in the past millennium required immediate actions from the operator after a shutdown. This would, of course, not be possible in practice. The requirement was therefore gradually changed from zero hours to one, two, four, and then to the current 8 h of no touch time (NTT). The change was possible due to a large number of field experiences including field trials and the specific studies carried out at the Statoil Flow Assurance pilot. Statoil’s normal practice has been not to insulate the subsea piping nor the valves. The NTT of 8 h is valid for any fluid systems and water content. In some cases Statoil has insulated the piping and will also continue to do so for a few specific reasons. The most important is to increase the steady state arrival temperature, thus extending the operational flexibility with respect to hydrates and wax at low flow rates. Hydrate Control of Flowlines. Low Water Content. The key parameter for determining hydrate plugging risk is water content. Each production system is analyzed with respect to water distribution during steady state and shutdown situations. When the water content at each low point is sufficiently low, typically 10% or less, no hydrate control measures are required during shutdowns. In some cases higher water content is allowed if the plugging risk is concluded to be low. In most cases an upper limit of 7 days for shutdown duration is defined to avoid any maloperation of the system. Figure 7 illustrates the water distribution of one given field over the whole pipeline length. This pipeline was permitted to stay shut-in without any active hydrate control measures. Production could be resumed smoothly. Hydrates can still be formed in the pipeline, and these can sometimes clog the topside choke. In these cases periodic chemical injection upstream the topside choke will be necessary. Natural Transportability. Some crude oils form naturally transportable hydrate slurries due to the presence of certain surfactants. The degree of natural transportability strongly depends on the water content and subcooling. A large amount of research has been carried out to identify key parameters that affect hydrate agglomeration and plugging tendency. This includes hydrate transportability tests using the flow simulator and loops.5,7 Statoil has been the main driver behind the development of the Wetting Index method.2,8,9 Figure 8 illustrates some of the results showing the wetting index for several oil systems. Those with high wetting index

Figure 7. Water distribution during steady state (upper graph) and shut-in (lower graph) conditions in a production flowline with no implemented hydrate control actions for a shut-in of 7 days duration. γ is hold-up defined as the volume fraction at a given location at the prevailing conditions. L is the flowline length. The vertical distance is denoted by h.

Figure 8. Wetting index (Δϕ) for different oils marked with letters A− M.

show a low agglomeration tendency and hence a low plugging potential.10,11 Fluid systems exhibiting very low agglomeration tendency require limited hydrate control measures. One example of this is Statoil’s Troll field where the fluid properties are favorable against agglomeration. For a shutdown situation, the flowlines have been left uninhibited for months even at a relatively high water content. The concept of natural transportability provides a valuable tool for optimizing operational strategies of existing production systems. A successful application of the concept requires testing of representative fluid samples at relevant conditions. D



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Figure 9. Operation within hydrate domain during a cold start-up.

Figure 10. Production loops with hydrate control based on circulation using well stream with high water cut.

In addition to the intrinsic chemical properties that determine oil’s wetting tendency, the physical properties are directly linked to plugging tendency. For example, heavy oils and oils with gelling characteristics are found to have low plugging tendency. This allows extension of operation within hydrate domain for a prolonged time. An example of this is shown in Figure 9. Here the oil has a pour point of 18 °C and density of about 900 kg/m3. No operational challenges related to hydrates were observed during a cold start-up. Use of Water. Statoil has subsea oil wells where the water cut is extremely high, above 95%. The GOR ratios are typically low for oil wells. When these wells have sufficiently high rate they are used for displacing the pipeline content in production loops. An example is shown in Figure 10. Some hydrates can still be formed, but the amount is minimal, and no operational problems have been accounted for. Statoil is working with understanding the risk in order to be

able to identify the acceptable operational limit for this type of operation. Hydrate Kinetics Technology. Statoil has developed a methodology for determining the hydrate formation induction time for oil systems, including some condensate systems. The induction time for these systems is repeatable. Figure 11 illustrates typical results from an experimental study. The green area indicates the area where the induction time is substantial; normally the lower limit is set to 12 h though exceptions in both directions exist. The closer to the equilibrium line the longer the induction time, up to several days. The yellow region covers induction times from the above limit of 12 h or so down to (1 to 2) h. The red area indicates the region where hydrate formation in practice is immediate. The induction time does not tell the criticality of the system. This has to be determined separately by looking into hydrate transportability, water content, pipeline configuration, and so forth. The application E



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Figure 11. Typical induction time plot for oil systems. The green area indicates the area where the induction time is long (typically longer than 12 h). The yellow region covers intermediate induction times (typically (1 to 12) h). The red area indicates the region where hydrate formation in practice is immediate (typically less than 1 h).

Figure 12. Application of hydrate kinetics technology. Extended no touch time (ΔNTT) plotted against the overall heat transfer coefficient U.

samples and the uncertainties connected to the expected changes in the fluid characteristics over the field lifetime. Compression Method. Statoil has for several years used the compression method for pipeline systems with sufficiently high gas fractions. The exact limit depends on the fluid properties and pipeline configurations. Typical gas−liquid ratios have been of the order of about 1000. The effect is highest for wellinsulated systems, but the method is used for pipelines with U (overall heat transfer coefficient) values of 4 W·m−2·K−1. The basic principle of this method is to take advantage of the compression heat. It is necessary that the compression be done relatively fast for standard type of insulation to minimize thermal losses. Benefits of the application of the concept are reduced chemical usage and faster startup. The method is used for both unplanned and planned shutdowns. Figure 13 illustrates results from one of Statoil’s fields where compression method is used. Here the topside temperature is increased to about 25 °C from ambient temperature before the topside choke is gradually opened. Continuous Operation within the Hydrate Domain. During tail production there are increasing challenges to being able to maintain the arrival temperature above HET. Continuous chemical injection may not be possible due to cost or negative downstream effects. In one such situation Statoil has been running within hydrate domain over a span of about 3 years interrupted by planned and unplanned shutdowns. The operating conditions are currently about 6 °C within the hydrate domain in the flexible riser, as shown in Figure 14. The flowline itself is warmed continuously using DEH (direct electric heating), but there is no chemical injection. At the beginning two plugging incidents in the riser occurred. The restrictions were a combination of hydrates and wax. It is believed that wax depositions here mitigate the hydrate challenge and thus allow safe operation within hydrate domain. More work is required to understand the interplay between wax and hydrates. Ethanol. Statoil has introduced ethanol to its tool box. Ethanol has been implemented at Åsgard due to its improved HSE effects in comparison to methanol, and it has now been used for two years. The main challenge with use of ethanol is its higher boiling point, causing it to be accumulated in iso-butane fraction. This challenge necessitates strict control over ethanol usage so as not to exceed the product specifications. Under-Inhibition. Comprehensive in-house studies related to under-inhibition effects on hydrate formation have been

of the induction time concept or hydrate kinetics is called hydrate kinetics technology (HKT).12 In practical terms HKT moves the hydrate curves to the left of the thermodynamic hydrate equilibrium curve. The effect is in principle the same as using thermodynamic inhibitors but now with limited duration. In other words, the operation can be defined with respect to the new hydrate curve as long as the time criteria are fulfilled. This extends the operational time window considerably, opening completely new possibilities for the hydrate management. HKT is applied in Statoil both at flowing and shut-in conditions. During operations the rate is sometimes reduced for specific reasons, for instance as a result of shutdown of some wells or production limitations imposed by gas export limitations. The rate reduction can bring the fluid system within hydrate domain for part of the system. Often such an operation has a time limitation. It is not always possible or desirable to inject chemicals, or even to shut down the whole production. A natural question is then whether the production can be continued without any hydrate control measures. The risk assessment will include analyzing the system with respect to its hydrate kinetics. It is important to determine that the production trajectory in the P−T plot would stay within the green region (the yellow region will typically provide a safety margin). If this is the case, no hydrates can be formed as long as the production can be kept within the given constraints. A separate assessment needs to be carried out for an unplanned shutdown from these conditions. The largest benefit by far of the HKT is in shutdown situations. The effect depends on the insulation efficiency as also shown in Figure 12. The no-touch time (NTT) can be extended by an order of magnitude for super insulated pipelines like PIPs, while a couple of hours extension can be achieved for moderate insulation levels. The concept has been applied in Statoil operations for both types of systems. This has resulted in reduced chemical use and faster start-up. Because the availability of representative fluid samples is certain only during the production phase, HKT provides an effective platform mainly for optimizing operational strategies of existing production systems. Use of HKT for optimizing new design for completely new fluid systems is more difficult due to the inherent uncertainties of the quality of the available fluid F



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Figure 13. Illustration of the effect of the compression method. Screen snapshot from an operational support program. The local normal units for pressure and temperature are used.

Plugging risk will first increase at a large degree of underinhibition. It then goes through a maximum due to the increased capillary bridging, and then is further reduced with reduced agglomeration tendency. Finally, transportable hydrate slurry is formed. Hydrate slurries formed in these systems contain fine particles which do not agglomerate into larger chunks. Despite this, it is important to keep the slurry concentration below the acceptable value to avoid jamming or a too-high viscosity. The limit depends on the degree of subcooling and the original MEG concentration. Figure 16 illustrates these effects for a given setting. The curves can be used to identify the maximum allowed subcooling for a given system when the acceptable slurry concentration limit is known. This number needs to be determined experimentally. For example, if we assume that a solid volume fraction of 0.43 is acceptable, we find from Figure 16 that a subcooling of about 9 K is allowed for a MEG concentration of 40 wt %. A fully inhibited system would thus require about 20 wt % more MEG. The reduction in MEG concentration is substantial. Statoil has implemented the under-inhibition concept in its design and operations. First, the safety margins can be substantially reduced. For design purposes Statoil currently uses a design margin of only 5 %. This is necessary to achieve proper sizing of facilities. In the past the safety margin has normally been 10 %. The greatest gain is in the operations, as the traditional safety margin can be eliminated in many cases. The safety margin can now be defined with respect to the transportability limit. Should hydrates be formed, they are transportable as hydrate slurries. This will normally not pose any practical challenge during transient operations. During continuous operation, one must ensure that the hydrate slurry can be properly melted and that it does not have any negative impact on the processing. The under-inhibition concept can also be used in cases with continuous chemical injection (in Statoil only MEG is currently used for such operation). Statoil has reduced safety margins even in these cases, but the final MEG concentration has to be matched with the corrosion control requirements which

Figure 14. Continuous operation within hydrate domain.

carried out by Statoil.3,13,14 The main conclusions from these studies can be presented schematically by Figure 15 using MEG (ethane-1,2-diol) as an example.

Figure 15. Hydrate plugging potential as a function of MEG concentration. G



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Figure 16. Aqueous saturation level α and solid content in the aqueous phase ϕ (volume fraction at the prevailing conditions) as a function of subcooling ΔT. X is the initial mass fraction of MEG in the aqueous phase. The aqueous saturation level α is defined as the volume ratio between the free water and pore/void space at the prevailing conditions if the slurry particles and water form aggregates. An α value greater than 3 indicates low potential for forming capillary bridges among slurry particles.

Figure 17. Hydrate control options for risers.

flowlines may have extremely good insulation providing a cooldown time of more than 24 h, while the riser cools into hydrate domain in less than 5 h. Other examples are heated flowlines and production loops which can be circulated with hydrate safe fluid. In these situations risers often require more immediate actions than the flowlines. On one hand it is desirable to postpone implementation of the hydrate control measures as long as possible. On the other hand it is important to avoid hydrate plug formation in risers as this potentially has the highest safety risk. Statoil applies the same principles for the riser risk assessment as for the flowlines. The key issue here is to understand the plugging tendency of the system. The inherently more serious consequence of having plug in the

sometimes can necessitate a higher MEG concentration than the hydrate control. Hydrate Control of Risers. Risers often present the weakest link in the production systems with respect to hydrate control due to their poorer thermal performance. Especially flexible risers pose by far the greatest challenges. Injection risers with water alternating gas (WAG) injection strategy also require special attention during the conversion process and the period immediately after a conversion. Typical methods available for hydrate control for risers are summarized in Figure 17. The main challenge for implementing the necessary hydrate control measures is timing. Often there is a “mismatch” between timing for the flowline and riser. For example, H



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risers rather than in flowlines dictates the necessity of a stringent approach, yet operation within hydrate domain is also permitted for risers when the plugging risk is low. Due to their geometry, flexible risers pose additional challenges with respect to hydrate control. Typically the riser comprises a sag with a large volume and an additional low point at the riser base at the touchdown area. In order to avoid use of large volumes of chemicals, Statoil uses a gas sweep to empty the risers of liquids whenever possible; normally no chemical is required during this operation. It is important that fluid is moved into a hydrate safe environment, like heated pipelines; moving liquids into a nonheated pipeline increases plugging risk. Flexible pipesincluding both flexible risers and flexible static pipes like jumpers connecting wells to a subsea manifoldintroduce another challenge with respect to hydrate plugs. If not properly accounted for, the plugs can cause damage to the pipe and result in large economic losses. Examples of damaged pipes are shown in Figure 18. Statoil has

heating is discussed in more detail by way of example of plug removal strategies in Statoil. Heating. Currently, Statoil has two types of heated pipeline systems for flow assurance purposes, heated bundles, and directly electrically heated pipelines (DEH). Hydrate control in particular has been the main driver for these technologies. The use of these technologies has provided effective, flexible, and operator friendly field concepts. Heating can be used to avoid hydrate formation in pipelines in all operational scenarios. Originally the design objective included the use of heating for hydrate plug removal. This was however barred from general use in the late 1990s due to possible safety risk. A meticulous study was launched in early 2000 to rigorously analyze plug melting by heating and to conclude whether safe windows for such operation can be defined. The study concluded that heating can be used for melting, though precaution is required as in any “normal” hydrate plug removal operations. All plug removal operations can involve safety hazard and need anyway to be handled with care. Plug removal using heated bundles is quite straightforward, as the risk of obtaining high pressures is minimal given the uniform temperature profile, but still proper operational guidelines are required. The pressure build-up as a result of the melting of plugs in heated pipelines is shown in Figure 19. The maximum pressure is here plotted against the heating time for various plug lengths.

Figure 18. Examples of damaged flexible pipes.

introduced stringent criteria for avoiding hydrate plugs and for handling plug situations in flexible pipes. The approach Statoil has chosen encompasses adequate monitoring, automatic shutdown, and detailed operational guidelines. Safety is always the uppermost element. Hydrate Remediation. Situations always can arise where it has not been possible to implement the required hydrate control measures or where there has been an operational error. Human error is minimized by proper operational guidelines and adequate training of operators and other key personnel. Statoil also has a duty team that is available 24/7 to assist operations in flow assurance related issues. The challenges often cover interpretation of hydrate control procedures in new situations and assistance in plug removal operations. These interactions with the operations give a first-hand knowledge of operational challenges that allows identification of technological challenges and of new research areas. This close link with operations has been the key behind the current hydrate management strategy in Statoil. Statoil has developed in-house methodology for plug removal operations. Basic principles are generally known: that is, one needs to get the conditions outside hydrate domain by using chemicals, heat, pressure reduction, or mechanical means. Use of heating is often connected to safety risk, and proper caution needs to be shown. As the use of heated pipelines is extensive in Statoil and increasing among other operators, the use of

Figure 19. Example on pressure buildup as a result of hydrate melting in heated pipelines for various plug lengths (L).

Extremely long plug lengths are needed to give pressure levels exceeding the design pressure. In practice it would be impossible to obtain such long continuous plugs. Several plugs can extend over a greater length, but it would be physically impossible to have a homogeneous long and compact plug. In Statoil’s experience individual plug lengths in flowlines are at maximum a few meters, but several plugs can span a long pipeline. In one instance more than 30 plugs were estimated to be present in a pipeline (nonheated) with a length of 11 km. In Statoil’s opinion, therefore, the challenge for pipelines in relation to melting using heating is exaggerated in most cases. However, as it is extremely difficult to get a complete overview of any plugging scenario in a subsea production system, it is always wise to show precaution and approach any plug removal operation with a proper safety mindset. I



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ACKNOWLEDGMENTS The authors want to thank Statoil for allowing publication of this paper.

In pipelines utilizing the DEH system, plug removal is somewhat more complicated than for heated bundles. For DEH systems, there is a potential for a nonuniform temperature profile due to the variations in magnetic permeability of the different pipe sections. The problem is greatest when the pipe sections are not sorted according to their magnetic permeability, as was the case for the first DEH pipelines installed by Statoil. This practice has since been changed to reduce this negative effect, and pipe sections are now sorted according to their permeability. The main challenge in melting hydrate plug in a flowline with DEH is related to having a hydrate plug over two pipe sections which have different permeability. A worst case scenario is where we have three pipe sections each with a length of 12 m, with a permeability distribution which would warm up only the middle pipe section over HET, such that there would be no melting in the two surrounding pipe sections. The probability for such a scenario is extremely low, both with respect to the overall magnetic permeability distribution (nonsorted) and to there being such a long, compact homogeneous hydrate plug that would extend over three pipe sections. The practical probability would most likely be nil. Nevertheless as a theoretical finite the probability exists. Statoil’s requirement is to show extra precaution always when melting hydrate plugs in DEH pipelines. A general allowance for an uncritical deployment of DEHi.e., just push the button and let the system take care of itselfdoes therefore not exist, and a case by case evaluation will be necessary during any plug removal operation. Use of heating is allowed, but this needs to be done within the framework of existing guidelines. It is also necessary to understand the thermal performance of each pipeline since the heat transfer characteristics can change considerably along the pipeline route, as is the case for some of our pipelines some sections are in free span, and the rest of the pipeline are either buried or rock dumped.

REFERENCES

(1) Gjertsen, L. H.; Fadnes, F. H. Measurements and predictions of hydrate equilibrium conditions. In Gas Hydrates: Challenges for the Future; Annals of the New York Academy of Sciences: New York, 2000; Vol. 912, pp 722−734. (2) Fotland, P.; Askvik, K. Some aspects of hydrate formation and wetting. J. Colloid Interface Sci. 2008, 321, 130−141. (3) Gjertsen, L. H.; Austvik, T; Urdahl, O. Hydrate plugging in under-inhibited systems. In Proceedings of the 2nd International Conference on Natural Gas Hydrates, Monfort, J. P., Ed., Toulouse, France, 1996. (4) Rasch, A.; Mikalsen, A.; Li, X.; Gjertsen, L. H.; Austvik, T. Evaluation of a Kinetic Hydrate Inhibitor with Focus on the Pressure and Fluid Dependency. In Proceedings of the 5th International Conference on Natural Gas Hydrates, Yokohama, Japan, 2002. (5) Li, X.; Hemmingsen, P. Plugging and Non-plugging Hydrate Behaviour in Different Fluid Systems - Understanding the Mechanisms. In Proceedings of the 20th International Oil Field Chemistry Symposium, Geilo, Norway, 2009. (6) Kinnari, K.; Labes-Carrier, C.; Habetinova, E.; Straume, E.; Hjarbo, K. Reduced chemical injection strategy for hydrate control of subsea templates and spools. In 5th North American Conference on Multiphase Technology, Banff, Canada, 31 May to 2 June 2006. (7) Hemmingsen, P.; Li, X.; Peytavy, J.; Sjöblom, J. Hydrate Plugging Potential of Original and Modified Crude Oils. J. Dispersion Sci. Technol. 2007, 28, 371−382. (8) Høiland, S.; Askvik, K.; Fotland, P.; Alagic, E.; Barth, T.; Fadnes, F. Wettability of Freon hydrates in crude oil/brine emulsions. J. Colloid Interface Sci. 2005, 287, 217−225. (9) Høiland, S.; Borgund, A. E.; Barth, T.; Fotland, P.; Askvik, K. M. Wettability of Freon hydrates in crude oil/brine emulsions: The effect of chemical additives. In Proceedings of the 5th International Conference on Natural Gas Hydrates, Trondheim, Norway, 2005. (10) Høiland, S.; Borgund, A. E.; Glénat, P.; Fotland, P.; Askvik, K.; Li, X. The Wetting Index: A Quantitative Measure Of Indigenous Hydrate Plugging Tendency; Flow Test Validations. In Proceedings of the 7th International Conference on Gas Hydrates, Edinburgh, UK, July 2011. (11) Gupta, A.; Crosby, D.; Guillory, J. The Hydrate Plugging Tendency Of Crude-Oils As Determined By Using High Pressure Electrical Conductivity And Transparent Hydrate Rocking Cell Tests. In Proceedings of the 7th International Conference on Gas Hydrates, Edinburgh, UK, July 2011. (12) Askvik, K.; Fotland, P.; Kinnari, K.; Li, X. Natural Kinetic Inhibition of Gas Hydrates in Oil and Gas Production, in preparation. (13) Hemmingsen, P. V.; Li, X.; Kinnari, K. Hydrate Plugging Potential in Under-inhibited Systems. In Proceedings of the 6th international conference on gas hydrates, Vancouver, Canada, July 2008. (14) Li, X.; Hemmingsen, P.; Kinnari, K. Use of Under-inhibition in Hydrate Control Strategies. In Proceedings of the 7th International Conference on Gas Hydrates, Edinburgh, UK, July 2011.

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SUMMARY Hydrate management in Statoil today is a risk-based approach, allowing operations within hydrate domain when the hydrate plugging risk is low. The hydrate management strategies take advantage of the intrinsic properties of the fluid systems and the hydrodynamics. Understanding the effect of water distributed in the different parts of the production systems plays a key role in determining the plugging risk. The concept of hydrate management is based on a large body of research and extensive field experience. It defines the basis for new design and operational procedures. The examples in this paper illustrate how hydrate management is practiced in Statoil for different production systems in operation. Statoil will continue its efforts to improve hydrate control strategies in order to maximize the economics. It is also Statoil’s desire that this paper would stimulate to more research in key areas of hydrate management.

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Corresponding Author

*Phone: +47 41 63 55 78. Fax: +47 51 99 00 50. E-mail: kjki@ statoil.com. Notes

The authors declare no competing financial interest. J


Hydrate Management in Practice - ACS Publications - American

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