Treatment plants for gas production

Transcription

1 5.4 Treatment plants for gas production Introduction This chapter examines the treatments required for the transport and distribution of natural gas. It will discuss the main processes used to purify gas and the requisite equipments both for gas bearing produced by gas reservoirs, and gas associated with crude oil. In the specific case of production from gas condensate reservoirs, the vapour phase and its treatment will be analysed in this chapter, whereas the liquid phase and its treatment have already been discussed in Chapter 5.3. This discussion covers surface plants comprised between the production wellheads (excluded) up to and including delivery to the gas pipelines used for transport and distribution. These treatment plants include gas/liquid separators, dehydration, condensate removal and sweetening units, and those used to remove other compounds in the gas such as mercaptans and mercury. Considering the significant increase in the transport of liquefied natural gas, this chapter will describe the pretreatments needed for liquefaction, in addition to liquefaction processes. The chemical and physical properties of natural gas depend on its origins and composition. The latter, except in unusual cases, does not significantly influence either treatment or transport. For this reason, the following discussion will not take into consideration the origins of the gas. Specifically, the chemical composition and the greater or lesser percentages of heavier hydrocarbons present in the gas have no impact on the considerations relating to the processes under examination. Therefore no distinction will be made between dry gas, gas condensate and gas associated with crude oil. However, it is important to note that the surface facilities needed to handle and purify natural gas are not always identical to those used to treat refinery gases and synthetic gases. Natural gas contains higher hydrocarbons, ranging from paraffins to aromatics and naphthenes; however, in contrast to refinery gases and synthetic gases, it does not contain olefins. As far as contaminants are concerned, natural gas may contain a wide range of compounds which can confer upon it negative properties, both in terms of transport and distribution. The main non-hydrocarbon component of natural gas is water. As will be seen in the following discussion, this is removed by dehydration, the most common treatment process in natural gas production. Chapter 5.3 dealing with oil treatment examined the properties of the water present in a reservoir fluid. In the specific case of gas, formation water has lower salinity than that commonly found in oil fields; despite this, the presence of chlorides in the water produced alongside gas must be carefully evaluated and treated to reduce to a minimum or avoid completely the contamination it causes during the purification processes undergone by the gas. Whereas the presence of modest quantities of free water in an oil is acceptable, in gas this component must be completely removed to avoid the formation of condensation under the most critical transport and distribution conditions, in other words at high pressure and low temperature. The parameter defining this condition is the water dew point, that is the temperature, at a given pressure, at which the first drop of condensed water forms. Natural gas may also contain inert gases such as nitrogen, N 2 and helium, He. In general their presence is acceptable within the limits of variability of the calorific value. Natural gas often also contains carbon dioxide, CO 2, and this compound is tolerated at higher or lower VOLUME I / EXPLORATION, PRODUCTION AND TRANSPORT 681

2 DEVELOPMENT PHASE OF HYDROCARBON FIELDS values, subject to the dehydration of the gas itself; this compound may confer considerable acidity on the gas, combining with any condensation water present. By contrast, the presence of hydrogen sulphide, H 2 S, often present in gas alongside other sulphur compounds such as mercaptans, is not tolerated. Whereas the contents of the former compound must be reduced to negligible values due to its toxicity, the limit content of other sulphur compounds (total sulphur) is higher. Another substance frequently found in gas is mercury, Hg, which may be present as elementary mercury, or in the form of some of its compounds, of which the most frequent is mercury sulphide HgS. The presence of this heavy metal in the gas may cause significant problems, not so much during production and in the gas gathering networks, as during subsequent condensate removal and liquefaction treatments. This is because at low temperatures elementary mercury changes from the gas phase in which it is found in the reservoir to the liquid phase; this condition must be avoided by treating the gas appropriately. Finally, gas production may contain solid particles of varying origins, such as sand or colloidal clay, dragged from the reservoir from which it is produced, or formed by corrosion. These suspended solids must be removed before the gas can be commercialized Sales gas specifications Calorific value and Wobbe index Most gas production is used as fuel for civic purposes, and as such is distributed to users through appropriate networks. For this purpose, the calorific value of the gas must have a limited range of variability. Generally speaking, in analysing the compatibility and interchangeability of various types of gas, the reference parameter used is the gross calorific value of methane (9,001.6 kcal/sm 3 ), since the latter is by far the predominant component of natural gas production. The range of variability of the calorific value in general must not exceed 10%. This fairly approximate factor on its own serves to define the inert gas content (N 2, CO 2, He, etc.), acceptable for the commercialization of natural gas. Natural gas may also contain higher hydrocarbons (ethane, propane, butanes, etc.) characterized by a far higher calorific value than that of methane; the inert gas and higher hydrocarbon content may therefore lead to considerable variability, whilst still meeting the restriction described above. In controlling combustion, alongside calorific value, another parameter of the gas is also important; its specific density with respect to air. For the sake of simplicity, it can be stated that the combined effect of the two parameters described above on gas combustion can be expressed by a single parameter known as the Wobbe index, and defined as HHV/sg 0.5, where HHV is the high heating value and sg the specific gravity of the gas mixture under examination. In the case of the methane used as a reference point, the Wobbe index is 12,094.8 kcal/sm 3. In evaluating the compatibility of a gas with delivery to a distribution network it is more correct to refer to the Wobbe index as defined above, rather than to the simpler calorific value. The range of variability generally accepted in the latter case is in the order of 5%. As can easily be seen, this specification is considerably more restrictive than the former, particularly due to the resulting limitation determined by the maximum allowed percentage of inert components. In treating gas, the specification described above is fundamentally important, since it is the basis for the treatments which the gas must undergo in order for it to be commercialized. Water and hydrocarbon dew point As mentioned above, gas must be transported through long gas pipelines and then delivered to users through distribution networks. The gas is treated upstream the transport and distribution system. The distribution network does not include any treatment, but merely reductions in pressure; as a result, the gas must meet specifications such as to ensure that no conditions under which water and/or hydrocarbons might condense arise during any of the phases of transport and distribution. Obviously, these specifications vary depending on the area crossed. Often, water and hydrocarbon dew point conditions also depend on the specific subsequent treatment which the gas must undergo. As will be seen below, the gas may be treated to recover higher hydrocarbons, or even liquefied for transport at atmospheric pressure with LNG carriers. In these cases, the gas must undergo a more or less severe cooling process; as a consequence, the requisite reduction of the water and hydrocarbon dew point may be more or less severe. Usually these two specifications consider two different values, although obviously they could be expressed as a single value. There are two reasons for this difference. As will be shown below, even very modest water condensation in a transport pipeline or during the treatment of gas may cause far more significant problems, such as the obstruction of the pipeline itself, than those caused by the modest condensation of hydrocarbons alone. For this reason, the operating margins for water condensation must be 682 ENCYCLOPAEDIA OF HYDROCARBONS

3 TREATMENT PLANTS FOR GAS PRODUCTION pressure 0 bubble points 20 retrograde condensation region temperature cricondentherm higher. A second reason is linked to the particular behaviour of the two-phase gas-liquid hydrocarbon equilibrium, as compared with the gas-water equilibrium. The latter shows a univocal pattern for saturation as a function of pressure. Given an identical water content, the higher the pressure the higher the dew point. In the case of hydrocarbons, this behaviour is more complex, and saturation and/or condensation do not have univocal behaviour versus pressure. The phase curve shown in Fig. 1 demonstrates that at low pressures the condensation temperature increases as pressure increases, up to a maximum value (cricondentherm); above this value the variation of the dew point as a function of pressure is inverted, and an increase in pressure leads to a reduction in the dew point. The range of pressures above the cricondentherm is therefore known as the retrograde condensation zone (see Chapter 4.2). Under this condition, a reduction of pressure at constant temperature leads to the condensation of liquid hydrocarbons rather than to undersaturation. The above description explains why, in defining hydrocarbon dew point specifications, reference is not made to a predetermined pressure, as for water, but to the full range of pressures, starting from atmospheric pressure. The water dew point specification is more commonly defined as the water content in the gas. Obviously, the hydrocarbon dew point cannot be expressed as a predetermined content. Inert gas content (CO 2 and N 2 ) The carbon dioxide (CO 2 ) concentration may be relatively high without interfering with the main restriction relating to the Wobbe index. Basically, the maximum permitted CO 2 content is linked to the maximum total permitted inert gas content (usually CO 2 N 2 ). As will be seen in the discussion of purification treatments required to obtain the requisite dew points Fig. 1. Phase diagram for a multi-component mixture. C quality, it is easier to remove carbon dioxide than nitrogen. It is therefore preferred, as far as possible, to leave the latter unaltered and to remove CO 2 until the required Wobbe index and/or maximum total inert gas content is reached. In general, CO 2 contents of up to 2-3% mol are acceptable; the total inert gas content, CO 2 N 2, should not exceed 6.5% mol. Maximum hydrogen sulphide (H 2 S) content The maximum permitted content for distribution networks in the United States and North America is 1/4 grain/10 2 Sft mg/sm ppm in volume; the same values are generally accepted in Europe. This extremely low content means that hydrogen sulphide must be removed almost entirely. It is worth noting that gas sweetening processes lead simultaneously to a significant removal of carbon dioxide. Total sulphur content Since it is not linked to safety problems, but merely to the reduction of air pollution, the total sulphur content, which often coincides with that of mercaptan sulphur, is 17 mg/sm 3, and thus far higher than that of hydrogen sulphide. Many processes for the removal of hydrogen sulphide and acid gases in general have only a modest impact on the removal of mercaptans, and thus of total sulphur. Very frequently, a natural gas with a high hydrogen sulphide content also contains significant quantities of mercaptans, which must be reduced to the aforementioned specification with appropriate treatment. The same is true for Liquefied Petroleum Gases (LPG) obtained from gas with condensate removal treatment. As far as hydrogen sulphide is concerned, LPGs must meet a specification similar to that for gas; as far as mercaptans are concerned, by contrast, LPGs, which are also used as vehicle fuels, must meet the same specifications as gasoline and pass the so-called Doctor test; in other words they must contain less than 10 ppm of mercaptans. As such, in order to be commercialized, LPGs must undergo suitable treatment, very similar to that described for oil. Suspended solids content There is no uniform specification for solids contents. The standard for the removal of suspended solids in gas is generally met as a consequence of the removal of liquid particles. Only in unusual cases, dictated mainly by specific treatment needs, is the gas subjected to filtration in order to remove suspended solids. Mercury content Many natural gases contain significant amounts of mercury. As a general rule, this contaminant should be removed to reduce air pollution; in practice, natural VOLUME I / EXPLORATION, PRODUCTION AND TRANSPORT 683

4 DEVELOPMENT PHASE OF HYDROCARBON FIELDS gas often undergoes only very simple treatment processes such as dehydration. In these cases, a limited mercury content has no significant impact on treatment itself, and is therefore accepted. This is not true when the gas must undergo cooling processes; in this case a stringent mercury removal treatment, to values of 10 ppb, is needed Gas/liquid separation From a theoretical point of view (dynamics of particles dispersed in a fluid), there is no difference between the setting of drops of liquid in a gas, and liquid/liquid gravity separation. Even from a practical perspective, the differences are insignificant. The final settling velocity of the particles, V t, is calculated by balancing the forces acting on the particles during their setting in the dispersing fluid. In the case of non-deformable spherical particles of diameter D p, we obtain: V t [4gD p (r p r)/3c r] 1/2 where g is the acceleration of gravity, r p the density of the particles, r the density of the dispersing fluid, and C the drag coefficient. In the case of the separation of liquid particles suspended in a dispersing liquid, the settling of the particles usually occurs in conditions of laminar flow, given the low value of the Reynolds number (R e ), defined by the equation: R e D p V t r/m (where m is the viscosity of the dispersing fluid). The coefficient C can thus be expressed by the simple equation: C 24/R e, making it possible to calculate V t using Stokes law (see Chapter 5.3). By contrast, when dealing with the separation of liquid particles in a gas, R e takes on a far higher value due to the low viscosity of the dispersing fluid (gas), and it is therefore no longer possible to assume that the particles settle under conditions of laminar flow. In this case the coefficient C is calculated as a function of R e using suitable programmes, or more complex equations. Solving the equation linking V t to D p requires calculation by trial and error, and this methodology has been codified in API RP 520. The most obvious use for this methodology is sizing or evaluating the flare KOD (Knock Out Drum) separator. In this specific instance, for safety reasons, it is impossible to use any type of internals suited to aiding the coalescence of dispersed drops. As a consequence, the sizing of the vessel is based exclusively on the gravity separation described above. Using this methodology, the diameter of the particles removed from the gas stream is, in the case cited, in the order of 250 mm, whereas in other cases it may reach slightly lower values; however, this is an extremely approximate separation. Another example of the use of simple gravity separation is the slug catcher (see Section 5.4.6), where the main purpose of the equipment is to block the slugs of liquid entrained in a gas stream. In all other cases where it is necessary to ensure a good reduction of entrained liquids alongside a rough gravity separation, a demisting unit must be inserted into the separator to help the drops to coalesce, facilitating the removal of particles with a diameter above 10 mm. It is not easy to define the degree of purification that can be obtained by these means; the statistical distribution of the diameters of the drops is in fact difficult to determine. It is common practice to consider the liquid content entrained in a gas downstream a demisting unit sized to remove drops with a diameter above 10 mm as being equal to 0.1 Gal/10 6 Sft 3. This practical simplification derives from the data from numerous separation units, rather than from studies of particle dynamics and the statistics of drop distribution. One of the most commonly used demisting unit is the wire mesh pad: this is inserted perpendicular to the gas flow at a predetermined distance from the outflow and inflow nozzles of the stream itself. In the separation of liquid from gas, the most frequently used typology is the vertical separator, where the gas outflow nozzle is positioned at the centre of the elliptical upper part of the vessel. In this case, the sizing of the separator is mainly based on calculating the minimum section needed for the installation described above. The equation determining the maximum velocity of the gas in the demisting wire mesh pad is as follows: V t K[(r L r G )/r G ] 1/2 where r L is the density of the liquid particles and r G the density of the dispersing gas. The constant K varies as a function of the type of separator required and its working pressure. The values recommended by the GPSA (Gas Processors Suppliers Association) as a function of the various working pressures range from 0.36 at atmospheric pressure to 0.21 at 100 bar and above (when the density is espressed in lb/sft 3 ). For some specific types of separation, such as the KOD separators used to protect compressors and expanders, the values of K are lower, with a coefficient of 0.8. In a vertical separator, the cross-sectional area of flow thus corresponds to that of the horizontal wire mesh pad installed inside it. For other dimensions, such as height, it is necessary to know the flow rate of liquid to be removed and determine the hold-up time, which may vary depending on operating conditions and the chemical and physical properties of the fluids to be separated. 684 ENCYCLOPAEDIA OF HYDROCARBONS

5 TREATMENT PLANTS FOR GAS PRODUCTION In some specific cases, horizontal separators may also be used, with the demisting unit positioned in an identical way to vertical separators, in other words with the gas flowing from bottom to top. When the separator may receive a two-phase flow with significant and discontinuous amounts of liquid, a double-barrel horizontal separator may also be used. Other types of demisting units are also commonly used to separate liquids from gas. The most frequently used are cyclones, and the so-called vanes. With the former, coalescence and the resulting separation are based on the centrifuge effect obtained in the circular movement of the gas. The results are extremely interesting: it is possible to obtain a higher degree of separation, with the almost complete removal of particles as small as 3 mm, or with even smaller diameters, and/or a reduction of the diameter of the separator into which the cyclones are inserted. The disadvantage of this solution lies in the greater pressure drop resulting from its use; however, this disadvantage is often negligible. The second type of coalescence elements are packages of vanes, also frequently used in oil-gas separators (see Chapter 5.3). In this type of separation, coalescence is due to the so-called chicane effect, very similar to the centrifuging described above. Both systems make the equipment more compact, and even make it possible to separate out any solid particles entrained by the gas with the liquid in an extremely efficient way. They are also self-cleaning, in other words they allow the solid particles to be drained away automatically in the separated liquid. The common wire mesh pad also removes solid particles together with the liquid but, unfortunately, given its engineering properties, it tends to retain the separated solids and collapse. When the gas to be separated contains a significant amount of solids, such as paraffin crystals which have separated from the liquid, as in the case of a low temperature separator, the wire mesh pad must be replaced with vanes or cyclones. The materials most commonly used to build separators are LTCS (Low Temperature Carbon Steel) for the outer shell, and AISI (American Iron and Steel Institute) 304L or 316L for the internals. When the gas has a significant acid gas content (H 2 S and CO 2 ) and is saturated in water, the shell must also be resistant to acid corrosion. This is usually achieved by plating the interior of the vessel (3 mm thick) with AISI 316L Dehydration and condensate removal Three-phase vapour/liquid/solid equilibrium It is known that a hydrocarbon mixture in the gaseous state may give rise to the condensation of pressure for hydrate formation (psia) 6,000 4,000 3,000 1,500 1, methane 0.6 gravity gas temperature ( F) Fig. 2. Temperature-pressure diagram; hydrate formation curves (GPSA, Gas Processors Suppliers Association). water and/or hydrocarbons as operating conditions vary. When free water forms in a natural gas stream, as an effect of high pressure and low temperature this may lead to the formation of compounds, hydrates, which are highly unstable but have the physical properties of a solid. The formation of a triple-point equilibrium (vapour, liquid, solid) depends on operating conditions and the properties of the gas mixture under examination. In the presence of free water, light hydrocarbons from methane to isobutane may give rise to the formation of solid hydrates at high pressures and low temperatures. The tendency of light hydrocarbons to form hydrates increases with the molecular weight of the hydrocarbon up to isobutane; from normal butane onwards this tendency disappears and the component behaves like an inert in the equilibrium described above. The presence of carbon dioxide and hydrogen sulphide may also facilitate hydrates to form; for the former this tendency is modest, for the latter it is far more significant. Diagrams have been constructed (Fig. 2) allowing us to evaluate the point at which hydrates form under given operating conditions (temperature and pressure) as a function of the mean molecular weight or density of the gas. VOLUME I / EXPLORATION, PRODUCTION AND TRANSPORT 685

6 DEVELOPMENT PHASE OF HYDROCARBON FIELDS This fact is approximately valid since, as has already been said, hydrocarbons from normal butane to higher hydrocarbons play no part in the formation of hydrates. The same is true for inert gases such as nitrogen as, although these raise the molecular weight of the gas containing them, they decrease their tendency to form hydrates. The most accurate way of evaluating hydrate formation is to calculate the vapour/solid equilibrium for the gas mixture under examination. The most commonly used method is based on the equilibrium constants K rs y/x where y is the molar fraction of the hydrocarbon in the gas and x its molar fraction in the solid phase. As for the determination of the dew point, the point at which hydrates form satisfies the following condition: Σ y/k rs 1. The values of K rs for the components involved are determined experimentally as a function of pressure and temperature. The care taken to avoid the formation of hydrates is motivated by the disastrous impact which the formation of solids in a gas transport pipeline and the potential line plugging caused by this phenomenon may have. Eliminating the causes of this is extremely simple, and is based on the removal of water by dehydrating the gas itself. Inhibitors are used for short stretches of pipeline, for example the flow lines linking the well to the gathering and treatment centre where the dehydration mentioned above is carried out. Hydrate inhibitors are highly hygroscopic compounds which can act both in the gaseous and liquid phase, such as methanol, CH 3 OH, characterized by high volatility as well as by its hygroscopic qualities. Other inhibitors, by contrast, such as monoethylene glycol (C 2 H 6 O 2 ) and diethylene glycol (C 4 H 10 O 3 ), characterized by very low volatility, act in the liquid phase. The result obtained by using inhibitors is to lower the point at which hydrates form to a temperature below the minimum temperature encountered during transport. Suppose that we need to transport a gas through a subsea pipeline. The worst transport condition refers to the temperature of the sea bed, assumed to be 6 C and the maximum working pressure, assumed to be 90 absolute bar. Let the gas be delivered at 90 absolute bar and at 20 C, and let it be saturated in water upstream of the line; let the flow rate be Sm 3 /d. For the sake of simplicity consider a gas consisting of 100% methane. According to the diagram in Fig. 2, the hydrate formation point of the gas is 54 F 12 C. To avoid the formation of hydrates in this case, it is therefore necessary to obtain a value of 6 C. The diagram in Fig. 3 shows the variation of the hydrate formation point when pressure (psia) 10,000 1,000 experimental data Hammerschmidt temperature ( F) Fig. 3. Hydrate inhibition with ethylene glycol. 50 % 25 % 0 % EG (Ethylene Glycol) is used. In the case under examination, the final acceptable concentration of diluted glycol is less than 50% by weight. To obtain the amount of glycol to be injected it is therefore necessary to perform a simple material balance calculation. The amount of water which condenses from the condition of saturation (at 20 C and 90 absolute bar) to the final condition (at 6 C and 90 absolute bar) is calculated: this is equal to 16 kg/h. If the concentration of the glycol injected is 85% by weight and the final concentration is 50%, the amount injected must be no less than 25 kg/h. When it reaches the end of the pipeline, the diluted glycol is separated out and brought back to the desired concentration by regeneration. This is obtained by reconcentrating the glycol at atmospheric pressure by boiling off the condensed water. The glycol injected acts in the liquid phase, and must therefore be mixed in an optimal way into the gas stream to be protected. In order to be effective, the glycol must wet the entire surface of the pipeline; if the pipeline is very long, the amount of glycol accumulating inside may be extremely significant. This effect is accentuated by the bathymetric profile of the subsea pipeline. In order to avoid significant accumulations of liquid and the consequent reduction of the system s transport capacity, it may be extremely useful to displace the liquid by launching of spheres. Alternatively, an extremely large slug catcher must be installed at the end of the pipeline. Finally, it should be noted that the reduction in the water dew point obtained with this methodology is significant. This value is slightly below the minimum temperature of the pipeline (6 C) at arrival pressure, which is obviously lower than the initial pressure. The gas thus obtained after the separation of the diluted EG does not meet transport and distribution specifications (the water dew point required is below ENCYCLOPAEDIA OF HYDROCARBONS

7 TREATMENT PLANTS FOR GAS PRODUCTION 10 C at 60 absolute bar), and it must therefore undergo dehydration treatment. It should be remembered that in the past, when gas was transported from offshore platforms, glycol was systematically injected. A transport system thus involves the injection of inhibitor after a preliminary separation at the wellhead, at a working pressure equal to the flowing pressure of the well. This solution makes it possible to avoid salty formation water mixing with the glycol. The latter is injected upstream of the pressure control installed on every pipeline downstream of the wellhead separator mentioned above. In this way, the glycol inhibits the hydrates which might form by the cooling caused by the pressure drop in the valve described above (Joule- Thompson effect). The glycol injected is separated onshore, regenerated, and sent back to the platform through a small transport pipeline coaxial with the main gas pipeline. This pipeline is installed together with the gas pipeline itself. More recently, especially when the subsea pipeline is extremely long, an alternative solution, more simple from operating point of view, has been to install a dehydration limit on the platform. In this way, when the natural gas arrives onshore it can be sent straight into the transport and distribution networks, although in many cases the inhibitor injection system is still used. As said earlier, methanol can be used instead of the more common EG to protect against hydrates when the reduction in the hydrate formation point required is important. Given an identical final concentration, methanol offers a lower hydrate formation point than that obtained with ethylene glycol. The use of methanol for injection is not particularly common since a considerable amount of the liquid injected passes in the vapour phase and is therefore lost; furthermore, glycol is less flammable and is neither aggressive nor toxic, unlike methanol which has the advantage of acting in the gaseous phase. It is therefore the ideal solution for discontinuos use (for example to protect a well during start-up or to melt a hydrate plug which has formed accidentally). The above discussion explains why the discontinuous injection of methanol is always coupled with the more common continuous injection of EG. Dehydration by cooling The discussion in the preceding paragraph makes it clear why one of the most simple ways of dehydrating a gas is to cool it, simultaneously injecting the requisite amount of inhibitor. The final temperature of the treatment is quite the same of the dew point which we wish to obtain. In the case examined above, shall be the gas cooled to 10 C for example by expanding it from 90 to 60 absolute bar. Assuming the same composition (100% methane), from the enthalpy-pressure diagram for methane it can be deduced that simple expansion causes a cooling of about 14.5 C. Therefore, to obtain the desired result, a feed effluent exchanger is required, allowing the gas to be pre-cooled upstream of expansion from 20 C to 2 C. The gas at the outlet of the low temperature separator at 10 C will warm to about 9 C, cooling the incoming gas (Fig. 4). The drop pressure assumed is therefore sufficient, coupled with a very modest exchange (or alternatively a more modest expansion with a more significant exchange), to obtain the desired result, in other words a water dew point equal to 10 C at 60 absolute bar. Returning to the preceding example and the injection of inhibitor, it can be seen that by injecting methanol, a final concentration slightly below 50% by weight can be used, whereas for ethylene glycol an Fig. 4. Conditioning gas with a low temperature separator. dry gas EG gas from high pressure separator gas/gas exchanger TIC PIC low temperature separator LC to liquid gathering system VOLUME I / EXPLORATION, PRODUCTION AND TRANSPORT 687

8 DEVELOPMENT PHASE OF HYDROCARBON FIELDS Fig. 5. Gas dew points over aqueous ethylene glycol solutions temperature. water vapor dew point ( F) % 80 % 75 % 70 % 60 % 50 % 30 % 0 % 90 % 92 % 94 % 95 % 96 % 97 % weight by 98 % glycol 99 %ethylene solution temperature ( F) amount such as to maintain a concentration of diluted EG above 60% must be injected. In both cases, however, the amounts in question are extremely modest. Now assume that a significant amount of EG is injected (for example 1,000 kg/h with a concentration of 97% in weight). In this case, the amount of water to be inhibited will be greater than in the preceding case: about 23 kg/h. The dilution resulting from the removal of water to the required dew point is negligeable, and the glycol therefore maintains a high concentration (95% in weight). This has an equally significant impact on the water/gas equilibrium. From the EG/water equilibrium diagram (Fig. 5), it can be seen that with the concentration of glycol described above, the required water dew point is obtained with a contact temperature of about 15 C, much higher than the 10 C calculated previously. Following the scheme described above, it is therefore sufficient to cool the gas to a slightly lower Table 1. Physical properties of glycols EG DEG TEG Chemical formula C 2 H 6 O 2 C 4 H 10 O 3 C 6 H 14 O 4 Molecular weight Boiling point ( C) at 1 atm Viscosity (cp) at 25 C Viscosity (cp) at 60 C Decomposition temperature ( C) temperature and inject 1,000 kg/h of concentrated EG. Since the cooling is very modest, the pressure drop required to obtain it is equally modest. To complete the analysis developed above, it should be noted that, given an identical required water content, a higher pressure corresponds to a higher dew point; for example, a pressure of 75 absolute bar instead of 60 in the low temperature separator (LTS) corresponds to a dew point of about 8 C, which increases the operating margin with respect to the required dehydration. In many cases it is impossible to obtain a low cost cooling of gas such as that described in the example above. Under these conditions, the properties of glycol described above can be exploited without the support of cooling. Dehydration by absorption with glycol The glycol most frequently used for this type of dehydration is triethylene glycol (TEG), but in some cases diethylene glycol (DEG) and monoethylene glycol (EG) may also be used successfully; these have different properties, as shown in Table 1. Fig. 6 shows the scheme of the plant. A stream of concentrated TEG is fed into the top of an absorption column operating under pressure, into the bottom of which the gas to be treated is injected. The contact with glycol obtained with several equilibrium stages in counterflow with the gas leads to the dehydration of the latter as it exits the top of the column in question. The stream of TEG, diluted by the water which it has absorbed (rich TEG), is discharged from the bottom of the column. In a second column, operating at atmospheric pressure and provided with a bottom 688 ENCYCLOPAEDIA OF HYDROCARBONS

9 TREATMENT PLANTS FOR GAS PRODUCTION reboiler, the rich TEG is reconcentrated by distilling the absorbed water. The regeneration column is divided into two sections: an upper rectifying and a lower distillation section, separated by the glycol feed. In order to reduce energy consumption for regeneration, the concentrated TEG from the bottom of the reboiler is exchanged with the feed. In order to produce an adequate reflux, and lower the losses of TEG due to regeneration, a condenser is installed above the reflux section. This usually consists of a helicoidal coil which creates a heat exchange between the cold glycol to be regenerated, flowing through the inside of the coil itself, and the vapours rising from the reflux section. The rich glycol exiting the absorber is saturated in water and in equilibrium with the gas stream to be treated under the operating conditions of the column; it therefore contains dissolved gas. To liberate this gas, allowing it to be used as fuel, a flash drum is installed upstream of the regeneration column, operating at low pressure (from 3 to 7 absolute bar). This is usually installed downstream of the top condenser described above, allowing the TEG to undergo modest preheating, and facilitating the aforementioned separation by reducing viscosity (TEG is the most dense and viscous of the three types of glycol mentioned above; see again Table 1). If the gas treated has a negligible higher hydrocarbon content, the separator (flash drum) only needs to degas the glycol; in this case it can be a vertical two-phase separator with modest hold-up time. When the gas treated is associated with crude oil, and therefore rich in higher hydrocarbons (light ends), the rich TEG may also contain liquid hydrocarbons. The latter cause a considerable increase in the foaming tendency typical of the glycol-natural gas system, and must therefore be removed as efficiently as possible. For this purpose, a three-phase horizontal separator is used, with long liquid hold-up times (20-30 minutes). Downstream of the flash drum, the rich TEG is filtered with a cartridge filter and an active carbon filter. For low flow rates of glycol, both filters operate on the whole stream; for large flow rates, the active carbon filter treats only part of the total (from 20 to 50%). Downstream of filtration and heat exchange, the rich glycol enters the regeneration column. The bottom reboiler is usually of the kettle type, and the column is flanged directly onto the upper part of the reboiler itself. Various systems can be used for heating. The TEG regeneration temperature corresponds to that of a reboiler operated slightly above 200 C, since at 207 C the TEG itself undergoes significant thermal degradation. It is thus evident that the final regeneration temperature control must be very precise and effective; this is also true for DEG and EG, which have a far lower degradation temperature (165 C). Bearing in mind that decomposition, though modest, may occur on contact with the hot wall of the reboiler, which must necessarily be at a higher temperature, it is important to limit its temperature and keep it at a constant value. This is done by reducing the density of heat flow in the boiler to a very low level, obviously attempting to keep it uniform over its entire surface (12,000 kcal/hm 2 ). Although the overall Fig. 6. Simplified scheme of dehydration with glycol. flash gas still water vapour dry gas lean glycol flash drum glycol contactor rich glycol reboiler surge drum wet gas inlet scrubber filter free liquid VOLUME I / EXPLORATION, PRODUCTION AND TRANSPORT 689

10 DEVELOPMENT PHASE OF HYDROCARBON FIELDS heat tranfer coefficient is fairly high, since it is mainly water which must be boiled, the temperature drop at the wall remains high. Many TEG regeneration systems use fired tubes and fume tubes immersed in the bath to be heated. This solution does not always meet the requirements described above; even if the aforementioned heat flow density parameter is met, the latter remains a mean value which varies considerably over the exchange surface, and which has extremely high values near the burners. Using fired tubes and fume tubes also makes the reboiler far more bulky than an indirect exchange obtained with a shell and tubes exchanger, or an electrical heater with armoured heating elements. If, as is frequently the case for gas and oil fields, the production of electrical energy for the overall field users has a modest cost, the latter solution presents considerable benefits in terms of simplicity, reliability, compactness and, most importantly, the reduction of both operating and investment costs. Since the cost of the exchange surface is modest, the density of heat flow can be reduced to 10 kw/hm 2 (equal to 8,600 Kcal/Hm 2 ), at minimal cost and maintaining considerable compactness. This value, coupled with the control of the regeneration temperature and the system s intrinsic guarantee that the temperature of the heating element will be kept perfectly uniform over its entire surface, creates an optimal heating system. Where available, condensing steam at medium pressure (20 absolute bar) has similar advantages; however, this condition is not particularly frequent. Finally, a hot oil heating system may also be used; however, this does not give the same results as the electric resistance described above since. Furthermore, given its characteristcs, this system cannot ensure a uniform wall temperature. Using it provides results comparable to those of fired tubes; however it is obviously far safer and more reliable, though more expensive. The regenerated TEG passes into the feed-effluent exchanger, where it gives up most of its sensible heat. Downstream of this exchange, it is pumped to absorption pressure, and sent into the top of the absorber (contractor) through a final cooler. Often this cooling is carried out by exchange with the treated gas exiting the absorber. Dehydration treatment by absorption with glycol is thus a very simple continuous process. In order to ensure that the unit functions well, a surge vessel for the circulation pumps is also needed; this is connected to the kettle reboiler which feeds it by gravity. The optimal hold-up time for the vessel is 20 minutes. With a regeneration system like that described, based on pure thermal regeneration, the maximum concentration obtainable for TEG is about 98.8% in gas dew point ( C) solution temperature ( C) weight. This value can provide acceptable dehydration only when the absorption column operates under normal conditions, in other words with a operating pressure above 60 bar, and an ambient temperature of C. When the gas must be compressed for delivery to the transport and distribution system, it is preferable to place the TEG unit downstream of compression. The diagram in Fig. 7 shows that the equilibrium dew point corresponding to 98.5% by weight for TEG at a contact temperature of 50 C is incompatible with normal transport conditions. Partly this is because it is necessary to maintain a positive difference in concentration between the dehydrated gas and the corresponding condition of equilibrium (driving force) to obtain the desired dehydration. The driving force allows mass transfer between the gas stream and the TEG itself to take place. The higher the driving force, the lower the number of stages of equilibrium needed to obtain the desired result, and consequently the smaller the absorption column needed to carry out the aforementioned stages of equilibrium. The amount of circulating glycol also has a significant impact on the number of stages required for dehydration Fig. 7. Water-TEG equilibrium diagram. The dashed line represents the concentration of lean TEG normally produced in a regenerator operating at atmospheric pressure and 204 C (Gas conditioning and processing). 690 ENCYCLOPAEDIA OF HYDROCARBONS

11 TREATMENT PLANTS FOR GAS PRODUCTION The above discussion shows that the concentration of the glycol is the decisive parameter for dehydration. When operating conditions require it, it is therefore necessary to regenerate the glycol more deeply. Below, the three most common deep regeneration methods are described. Using these methodologies, very high concentrations up to 99.98% in weight and even above can be obtained. The most commonly used system involves installing a gas stripping column (dryer) below the reboiler. The glycol, concentrated thermally in the reboiler, is fed into the top of the aforementioned column, which contains random packing to a predetermined height (from 800 to 2,000 mm). The stripping gas, preheated to 200 C, is injected into the lower part of the column. The gas, in counterflow with the liquid (TEG), creates a mass transfer between the two streams, removing the water and thus completely dehydrating the glycol. The results obtained are excellent, and require modest investment and operating costs; the stripping column is extremely small, and the type of internals is the cheapest and easiest to install. Operating costs, linked to the amount of gas used, depend on the conditions at which the latter can be disposed of. If it is used as fuel, costs are very modest, and this solution is definitely to be preferred. If, on the other hand, the gas exiting the top of the regenerator cannot be disposed of directly, but must be recompressed and treated like the main gas stream, the use of stripping gas must be carefully evaluated. A second method for obtaining high concentrations and avoiding the thermal degradation of the glycol during regeneration is to use a vacuum system. The regeneration scheme is identical to that described above; the only difference lies in the fact that the system is kept at very low pressure (0.1 absolute bar) by using a suitable vacuum unit (for example a system of two-stage ejectors with steam as a driving fluid, or, when this is not available, a liquid ring pump). The binary equilibrium of the TEG-water and DEG-water system varies as a function of the pressure at which regeneration is carried out. In this context, it should be noted that at 0.13 absolute bar, very high molar concentrations correspond to far lower temperatures than those which cause degradation. In this way, as well as avoiding the resulting thermal degradation, this system allows for the use of heating fluids at temperatures which are more favourable from an economic point of view (for example steam at low pressure, which can thus be produced by heat recovery). When the gas treatment plant as a whole uses steam, this system makes for considerable savings (extremely low costs for the vacuum unit and a very compact shell and tubes reboiler). A third system, which unlike the previous two is patented, is the so-called Drizo system, which involves the use of stripping gas obtained by vapourizing liquid compounds with a suitable heating coil. These compounds are essentially aromatic hydrocarbons (toluene, xylene, etc.), normally present in modest concentrations in gases associated with crude oils. These are absorbed by the glycol, which they concentrate, and are recovered during the regeneration phase by condensing the top vapours. The condenser and corresponding three-phase separator allow the aforementioned aromatic water vapour and stripping gas rich glycol rich glycol rich glycol stand pipe reflux condenser stripper rich glycol rich glycol rich glycol stand pipe reflux condenser stripper reboiler stripping gas heat source reboiler reboiler heat source stripping solvent water lean glycol STRIPPING GAS lean glycol DRIZO R solvent pump Fig. 8. Simplified schemes of TEG regeneration. VOLUME I / EXPLORATION, PRODUCTION AND TRANSPORT 691

12 DEVELOPMENT PHASE OF HYDROCARBON FIELDS hydrocarbons to be separated in the liquid phase, simultaneously separating out the water produced by regeneration. In this way, since both fluids can be condensed at atmospheric pressure and at relatively high temperature, it is easy and cheap to recycle the aromatics into the TEG stripping column by vapourizing them (Fig. 8). With this system, concentrations of 99.99% by weight can be reached for both TEG and DEG. This solution, coupled with an adequate number of stages of equilibrium in the absorber, allows gas to be dehydrated to up to 1 ppm by weight of residual water. The material used for glycol plants, except in unusual cases, is carbon steel both for the absorber and the regeneration vessel. The column internals, on the other hand, are in AISI 304 or 316L. Dehydration by adsorption with molecular sieves When we wish to obtain an almost total removal of water (0.1 ppm residual content), a solid bed adsorption process can be used. Unlike the preceding treatment, this process is semi-continuous. The molecules of water and of some polar contaminants (CO 2, H 2 S and mercaptans) are adsorbed by a silica gel which acts as a molecular sieve, allowing the gas to pass through the bed unaltered and retaining the polar molecules mentioned above, and water in particular, in its active centres with a bond of purely physical nature. For water the adsorption capacity is extremely high: 20% by weight during the first adsorption cycle. Subsequently, following the thermal cycles characterizing the regeneration of the bed, this capacity declines due to the progressive degradation of the adsorbent material. At the end of a bed s life (on average three years) this capacity falls to about 13% by weight. Therefore, in calculating the volume of adsorbent needed to carry out the required dehydration, a slightly lower parameter is used (12%). To obtain a continuous dehydration of the gas, several adsorbent beds are needed (usually three, of which two working and one in regeneration). The adsorption of water is carried out by making the gas flow from the top to the bottom of the adsorption column (down flow). Regeneration is carried out by interrupting the adsorption cycle before the bed becomes completely saturated in water; regeneration gas is used for stripping, suitably heated to about 280 C. The regeneration gas is made to flow in the opposite direction to the adsorption gas (up flow), in order to ensure the complete removal of the water adsorbed. The mass transfer from the gas to the solid during adsorption is facilitated by high pressure, whereas the inverse phenomenon during regeneration is facilitated by high temperature and/or low pressure. Usually in natural gas treatments the pressure is not lowered for regeneration, which occurs simply as an effect of temperature; this means that extremely high temperature values are required. These values represent the main limitation of the dehydration system under examination. Heating the regeneration gas requires a heat source at extremely high temperature. In small plants, where the regeneration duty is modest, armoured resistances can be used for heating. This allows an optimal control over the temperature of the gas itself, and that of the heating surface. For large plants with higher duty, the system used to heat the regeneration gas is based on radiant heaters; this creates direct contact between the gas and the surface of the heater coils subjected to radiation. The most commonly used type of heater is the vertical pipe still with burners on the bottom (see Chapter 5.3). Regeneration takes place in several stages: the first is the rapid heating of the bed; the second and most important takes place at constant temperature and involves the removal of the water adsorbed. When regeneration is nearly complete, the temperature begins to rise again until it reaches its maximum value, very close to that of the regeneration gas. At this point the stripping of water is complete. The next stage is to cool the bed, which must be brought back to optimal adsorption conditions. The gas passing through the bed during this stage is simply dehydrated gas, which has obviously not been heated. At the end of this stage the sieve is ready for a new adsorption cycle. The adsorbent generally used is granular, with grains of spherical or cylindrical shape (extruded); the most common sizes are 1/8'' or 1/16''. The acceptable superficial velocity of the gas, different for the two types of granules, depends on the working pressure. Using this criterion, the bed s cross-sectional area of flow is sized. Its height is calculated so as to create the volume needed to adsorb the required quantity of water (this in turn depends on the length of the cycle which we wish to obtain). The density of the adsorbent material is about 700 kg/m 3. As far as regeneration is concerned, the sizing criterion is based on a simple energy balance. The heat supplied by the regeneration gas must provide for the various components contributing to the heating of the bed, and the desorption heat of the water. The heating must also take into account the increase in temperature of the vessel itself, and of lost heat. Frequently, in order to reduce the latter two components, but above all to reduce the thermal stress on the vessel, the adsorber is insulated inside the vessel allowing its metal wall to be kept at a temperature between that of the bed and the outside temperature. The ratio of regeneration gas to treated gas flow rates usually ranges from 5 to 10%. Fig. 9 shows a scheme of a typical dehydration unit. As can be seen, the regeneration gas is cooled as it 692 ENCYCLOPAEDIA OF HYDROCARBONS