Chapter 11 Hydrates

Chapter 11: Hydrates


Oil Field Chemicals Training Manual 11-2

Property of Nalco Energy Services Confidential & Proprietary DO NOT DUPLICATE

11.1 Problem

Formation of natural gas hydrates can present a serious problem in oil and gas production. Hydrates are crystalline, ice-like solids that form when small gas molecules, such as methane, ethane, and propane, are trapped in hydrogen-bonded water cages under high-pressure and low-temperature conditions, as shown in Figure 1. These conditions are often encountered in deepwater operations, such as subsea flowlines carrying wet gases and in cold-weather operations in northern climates.

The problem of natural gas hydrates has been well known to those working in the gas production, storage, and transportation industries for many years. Formation of gas hydrates can also be a problem in crude oil production and transportation. As little as 1% water cut is sufficient to form a hydrate plug in some oil producing systems for example, in Statoils Tommeliton field blockages formed from a hydrate slurry with less than 1% water cut. Formation of hydrate plugs is very fluid dependent. While some oil/water systems form hydrates and/or plugs almost instantaneously with low water cut, other oil/water systems may have difficulty forming hydrate plugs even at water cut as high as 50%. All water has the potential to be transformed into hydrates if the condition is right, i.e., low temperature and high pressure.

Figure 1. Structures of natural gas




Although the phenomenon of gas hydrates was first studied as early as 1811, the existence of hydrates was first confirmed by Villard in 1888. In the 1930s, Hammerschmidt discovered hydrates as a pipeline plugging agent and developed an equation (see section 11.7) to predict the hydrate depression temperature. The problems associated with the formation of gas hydrates can include: Reduction in the gas throughput. Plugging of flow lines. Increased pressure differences across the gathering system. Erosion. Damage to downstream equipment. Increased safety concerns. Unlike other plugging agents that require a substantial amount of time to accumulate in pipelines, such as sand, paraffin wax, or scale, hydrate formation is rapid (often requiring only hours to plug a pipeline) and, in some cases, catastrophic. Therefore, prevention of hydrate formation is the key strategy for hydrate control in deepwater production. Figure 2 shows the pictures of hydrates found in pig traps.

Gas hydrates can form in various parts of the subsea production system. Hydrates have been found in downhole tubing, wellhead trees, manifolds, jumpers, flowlines, and risers. A hydrate plug can cause a major interruption to the flow of produced fluids. Since most of the deepwater subsea wells are extremely productive, some as high as 100 MMSCF/day, this interruption can be very costly to the operator.

Figure 2. Hydrates plugs formed in the pipelines, courtesy of Statoil (left) and Petrobras (right)




Hydrate plugs in subsea environments can be difficult to remove, often requiring the gradual lowering of pressure in the line to allow the plug to thaw. This can be very time-consuming and often dangerous because a dislodged hydrate plug can act as a high-speed projectile, damaging the downstream equipment. Other remedial techniques, such as heating, coiled tubing, and chemical, have also been used.

11.2 Theory

Natural gas hydrates are crystals formed by water with small gas molecules and associated liquids in a ratio of 85 mol% water and 15 mol% hydrocarbons. Gas hydrates have been called the burning ice. This is due to the fact that gas hydrates are, in fact, host water cages containing guest gas molecules. These combustible gas molecules can be easily burned (Figure 3), leaving behind liquid water. The host cages, which contain many different sizes of cavities, are formed by water molecules hydrogen bonded to one another. These cages are thermodynamically unstable when the cavities are empty. However, as soon as some small molecules occupy the cages, they become thermodynamically stable and turn into solids, i.e., hydrates, as soon as some small molecules occupy the cavities. The dimension of these cavities fits very well with the size of the small gas molecules, such as methane, ethane, propane, butane, pentane, hexane, nitrogen, carbon dioxide, and hydrogen sulfide. Some larger molecules, such as cyclohexane and methylcyclopropane, can also fit into the larger cavities. Some molecules like benzene can also promote hydrate formation even though the molecules themselves may not fit into the cavities. There are several different structures possible (type I, II, and H) for the hydrate crystals as was shown in Figure 1. The most common structure found in the oil and gas fields is Type II hydrates. In contrast, Type H hydrates are created mostly in the laboratory environment. Type I hydrates are formed predominantly in a methane-rich environment (> 99 mol% methane). The presence of a small amount of heavier components in natural gas, such as 0.5 mol% propane, will make Type II the predominant structures. This is the reason why Type II is the most commonly observed structure in the field. Having the right components (natural gas and water) is not sufficient to form stable hydrates. The condition must also be right. The favorable condition is low temperature and high pressure, which is typical of deepwater offshore operation. Unlike ice formation that occurs around 0C, hydrate formation can occur at as high as 20C if the pressure is high enough. Indeed, the hydrate equilibrium temperature increases with increasing operating pressure (see Figure 4). At a typical seabed temperature of 4C, the hydrate equilibrium temperature can be as low as 170 psi.

Figure 3. Burning hydrates




11.3 Formation of Hydrates

The following four components must be present for gas hydrate crystal formation to take place: 1. Natural Gas 2. Water 3. High pressure 4. Low temperature The requirement for gas is easily met in all petroleum production systems. The water requirement is usually interpreted to mean water in the liquid phase. Water in the liquid phase can be either produced water or water condensed from gas subjected to temperatures below the dew point. The low-temperature and high-pressure requirements are met by many of the systems that are in operation today. Exactly how low the temperature has to be, or how high the pressure has to be to form hydrates, is governed by the hydrate equilibrium curve for the particular system. A typical curve is shown in Figure 4 on the next page. This curve shows the hydrate region to the left of the curve and the non-hydrate region to the right.




The severity of hydrate formation is a function of the degree of temperature inside the hydrate region at which the system operates at a given pressure. This is referred to as the degree of subcooling: the higher the degrees of subcooling, the more severe the potential for hydrate formation. In the hydrate phase equilibrium curve in Figure 4, the system is operated at a temperature of 60F and 5,500 psi. At the operating pressure, the hydrate equilibrium temperature is 80F. The system operates at 20F of subcooling. There are two possible solutions to remedy the hydrate problem if the producer desires to operate in the non-hydrate region: 1. (Figure 4 Arrow A) Increase the temperature of the system. This would move the

operating temperature from the current point in the hydrate region to some point to the right, outside the hydrate region.

2. (Figure 4 Arrow B) Lower the operating pressure.

Of course, these two options can be used at the same time by increasing the temperature while reducing the pressure, as shown by Arrow C.

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Figure 4. Typical Hydrate Equilibrium Curve

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The presence of acid gasses such as carbon dioxide or hydrogen sulfide in the system can shift the hydrate curve to the right, as shown in Figure 5. Thus, the presence of these gasses can exacerbate the hydrate formation situation and make prevention more difficult. While hydrate inhibitors will still work under these conditions, often a higher dosage is required.

Hydrate Formation Curves

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Figure 5. The effect of H2S on hydrate equilibrium curve




11.4 Prevention of Hydrates

As mentioned in the previous section, four essential elements are needed for hydrate formation: the presence of natural gas (e.g., methane), the presence of water, the condition of low temperature, and the condition of high pressure. The absence of any of these four elements would make hydrate formation impossible. For example, the element of low temperature can be removed from the equation by proper heat management techniques using external heating or thermal insulation. Similarly, lowering the pressure by choking-back the production can reduce the tendency for hydrates to form in a production system. Water, another necessary element in hydrate formation, can be removed by dehydration of the natural gas. Although all of these methods can theoretically prevent hydrate formation, some may not be feasible or desirable in the field, especially in offshore environments. For instance, dehydration may not be an option for offshore operation due to space or weight/load limitations for the processing equipment. Therefore, to transport the unprocessed, wet hydrocarbon production streams, operators often rely on other alternatives such as heat management or chemical inhibition. 11.4.1 Methanol and Glycol

The two most commonly used chemical inhibitors are methanol and ethylene glycol. These inhibitors shift the hydrate equilibrium condition so that the operating condition falls outside of the hydrate formation region. Take Figure 6 on the next page as an example.




The hydrate equilibrium curve for the given system is shown as the dashed line. The condition at which the system is being operated is 1,500 psi and 40F (point A). At such a high pressure, the hydrate equilibrium temperature is estimated to be 70F (point B). This means that the system is operated in the hydrate region with 30F (i.e., 70 - 40 = 30) subcooling. In order to operate this system out of the hydrate region, methanol (MeOH) or ethylene glycol (MEG) can be injected. If 35 wt% methanol (based on total produced water) is injected into the system, the hydrate equilibrium curve is shifted to the solid line on the left. Consequently, the operating condition falls to the right of the hydrate equilibrium curve, meaning that the condition is out of the hydrate region. The corresponding hydrate equilibrium at 1,500 psi is now 34F (point D), which is lower than the current operating temperature. Alternatively, one can inject 45 wt% ethylene glycol (based on total produced water) to move the hydrate equilibrium curve to the solid line on the right, effectively lowering the hydrate equilibrium temperature to 35F (point C). Note that methanol is more effective than ethylene glycol on a per weight basis due to its lower molecular weight (32 versus 62).

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Figure 6. Hydrate equilibrium curves with and without chemical inhibitors




Both methanol and ethylene glycol are often classified as thermodynamic inhibitors because of their ability to shift the hydrate equilibrium curve toward higher pressures and lower temperatures by changing the activity of water molecules. The effective concentration is very high, typically ranging from 10 wt% to 60 wt% (based on total produced water) as a function of subcooling. The higher the subcooling is, the higher the effective concentration must be. Methanol and ethylene glycol are the most popular choices because of their low cost and widespread availability. However, methanol usage also has some drawbacks. The drawbacks include flammability, toxicity, and due to the large volumes required to treat the hydrates, large storage requirements are necessary in the field. Glycols are generally not as toxic or flammable, but the cost of glycol is higher than methanol. Glycols are also less effective than methanol and require more energy to pump due to their higher viscosity 11.4.2 Low Dosage Hydrate Inhibitors

Recently, a new group of non-thermodynamic chemical inhibitors has been developed. These chemicals are very different from the traditional thermodynamic inhibitors because they do not shift the thermodynamic equilibrium of hydrate formation. Instead, these inhibitors interfere with the process of hydrate formation. Since the effective dosages of this new type of chemical inhibitors are much lower than those required for thermodynamic inhibitors, the inhibitors are usually classified as low dosage hydrate inhibitors (LDHI). The effective concentration for LDHI typically ranges from 500 ppm to 2% of the total amount of water being treated. Nalco has developed a group of effective LDHI and marketed them as FREEFLOW technology (see Figure 7).

Figure 7. Logos of FREEFLOW program based on the LDHI technology




Figure 10. The interaction of hydrate lattice with KHI polymers.

11.4.2.1 Mechanism of Kinetic Hydrate Inhibitors Some LDHI effectively interfere with the nucleation and crystallization of hydrate molecules, thus extending the time required to form hydrates (known as induction time). These products are referred to as kinetic hydrate inhibitors (KHI). Examples of these products include EC6441A, EC6451A, EC6481A, EC6491A, and EC6504A. These products are mainly polymer-based materials in an aqueous-based solvent system. The extension of induction time is a function of subcooling. The induction time increases exponentially as the degree of subcooling decreases. As a rule of thumb, FREEFLOW can effectively treat condensate systems up to 23F subcooling and black oil systems up to 18F subcooling for at least 48 hours protection, meaning that hydrates will not form for at least 48 hours. In some systems where the subcooling is low (e.g., 10F), the induction time can be as long as a week or more. Hydrocarbon also plays an important role in varying the induction time. For example, KHI has successfully treated a system with a subcooling as high as 30F.

Details of the hydrate control mechanism by KHI are largely unknown. Molecular modeling has been carried out to study the interaction between the KHI polymers and the hydrate lattice. It is thought that the polymer chain anchors on the hydrate lattice through the oxygen atoms. The pendant groups displace the gas molecules from the cavities and the polymer chain blocks the enclosure of the cages. This type of interaction disrupts the stable hydrate formation that otherwise will take place in a much shorter time frame. When the induction time is exceeded, the polymers are eventually displaced to allow more thermodynamically stable hydrates to form.

Figure 9. Molecular structures of some KHI polymers




Figure 11. Hydrate control mechanism for anti-agglomerants in the pipeline.

11.4.2.2 Mechanism of Anti-agglomerates Another type of LDHI can modify hydrate particles by adsorbing on or incorporating into the hydrate crystals. These chemicals have at least one long hydrocarbon chain to help the hydrate particles disperse in the hydrocarbon medium such that they do not agglomerate but stay dispersed as a slurry. For this reason, these chemicals are referred to as anti-agglomerants (AA), and the presence of a significant amount of hydrocarbon phase, typically in excess of 60% oil cut, is necessary. Figure 11 shows an illustrative mechanism of how AA works in the production systems.




11.4.2.3 Comparison of KHI to AA There are both advantages and disadvantages associated with the use of AA and KHI. In general, AA can handle a higher degree of subcooling and sustain a longer shut-in period. However, these chemicals are typically more toxic than KHIs. A minimum of oil cut, usually 50% to 70%, is needed for an AA to work. AAs may also cause production problems, such as bad water quality and emulsions. Also, pumping the resulting hydrate slurries can become an issue for the operation due to the concerns of erosion, over-pressure, oversize pump availability/operability, increased energy consumption, and lack of experience. In contrast to AA, KHI is more environmentally friendly, requires no oil to make it work, and provides a hydrate-free environment. However, the present KHI technology is limited to a lower degree of subcooling and a shorter shut-in period (limited to the maximum induction time extendable). The following table shows a quick summary of the advantages and disadvantages of AA and KHI. Kinetic Hydrate Inhibitors (KHI) Anti-agglomerates (AA) Advantages Requires no oil

Environmentally friendly Hydrate free operations

Higher degrees of subcooling than KHIs

Sustain longer shut-in periods

Disadvantages Lower degree of subcooling than AAs

Shorter shut-in period than AAs

Higher toxicity than KHIs Requires minimum 50% oil to

work

Potential water quality problems or emulsions

Pumping hydrate slurry requires larger pumps, more service time, and more energy




11.5 Return on Investment

Some important key performance indicators for hydrates include: Cost per BW treated Pressure differential on pipeline Hydrate related failure downtime Conformance to monitoring Chemical usage versus actual

11.6 System Survey

The Hydrate Inhibitor Questionnaire (section 11.6.1) and HydraCalc (11.6.2) can make the system survey process relatively easy. A section of the technical questionnaire is shown below. The HydraCalc computer-based model is a proprietary Nalco tool used in evaluating the potential for and the severity of a hydrate situation. These tools will aid you in collecting the design basis, system operating parameters, and other information required for making a thorough assessment of your customers hydrate challenge. They can also be used to develop the final recommendation. For some applications, it is necessary to have detailed modeling performed by research scientists highly skilled at this practice. It may also require physical testing in the Flow Assurance Laboratory. The information collected in the technical questionnaire can be passed along to Nalco marketing and research teams and used for this purpose. However, in many cases, the severity of the conditions can be determined in the field and the recommendation be made right there. HydraCalc can be used for this purpose.




11.6.1 Hydrate Inhibitor Questionnaire

IMPORTANT questions to be answered: A short description of your application, for example

Hydrate inhibitor is needed for a 10, 55-mile subsea pipeline that carries wet gas from the subsea manifold to the processing platform.

Pressure and temperature profiles, for example The inlet pressure is 3,000 psi and the arrival pressure at the platform is 2,300 psi.

The fluid leaves the manifold @ 110F and its temperature decreases to 40F seabed temperature after the first 3 miles. The temperature rises to 50F at the platform-boarding valve.

Chemical injection, for example How and where to be injected?

If injected through the umbilical, how long and what size is the umbilical? What is the material for the wetted part of the umbilical?

What is the temperature at the injection point?

Production rates (gas, water, and condensate), for example 85 MMSCFD gas with 50 BWPD and 20 BOPD

Gas composition, for example Component Percent Component Percent

N2 5% i-C4 2% CO2 3% n-C4 1.5% C1 80% i-C5 1% C2 5% n-C5 0.5% C3 2% Total 100%




11.6.2 HydraCalc

HydraCalc is a proprietary Nalco Excel-based program that requires only minimal input. The Nalco representative along with the customer, if appropriate, uses this program in the field. It provides a quick and accurate determination of the potential and the severity of a hydrate challenge. It also provides estimated Methanol consumption and KHI requirements. The program operates as follows: 1. After opening the HydraCalc program, the operator must first press ctrl-F to activate the

macros.

2. The company and stream or well name is entered for reference.

3. Enter the coldest expected system-operating temperature in degrees Fahrenheit (F). If this data is not available, use 40F. Few applications will be lower than that. As temperatures approach 32F, freezing becomes a concern, and low dosage hydrate inhibitors do not protect against ice. Using the lowest possible temperature will increase the severity of the application and lead to errors on the conservative side.

4. Enter the corresponding operating pressure in pounds per square inch (psi). If unsure, use the maximum pressure for the system. Similar to the temperature, using the higher pressure will increase the severity of the application and cause error on the conservative side.

5. Enter the gas production rate in million standard cubic feet per day (MMSCFD).

6. Enter the gas specific gravity. There are two choices for gas gravity. The operator can use the second page of the spreadsheet to calculate the gravity by entering mole percent of the individual components. In this case, the calculated gas gravity will show in the calculation table automatically. If the gas gravity is available, it can be entered directly into the calculation table. However, the link to the composition spreadsheet will be lost.

7. Enter the oil production in barrels of oil per day (BOPD).

8. Enter the API gravity of the crude, which is used to determine if it is black oil or a condensate system.

9. Enter the total water production rate in barrels of water per day (BWPD).

10. Choose the type of brine: fresh or saline. Fresh brine should be used if the total dissolved solids (TDS) of the water is not known. This will result in a worst-case-scenario calculation. If you choose the Saline option, the calculations will be carried out using 3.5 % TDS.

As the inputs are made, the calculations will run automatically. If Caution appears in the place of the hydrate inhibitor dosage, then the conditions may be too severe for the kinetic inhibitors. Please contact Marketing or Research to discuss. This doesnt necessarily mean that the kinetic inhibitors will not perform, but it does mean that a closer look is warranted.




11.6.2.1 HydraCalc Example Please press ctrl-F to activate Macro first. Input Parameters (in red)* Company Name ABC Oil Company Stream/Well Name Pipeline Coldest Operating Temperature 55F Corresponding Operating Pressure 2,000 psi Gas Production Rate 100 MMSCF/D Gas Specific Gravity (If you dont know the value, please fill out the composition worksheet and let the program calculate it for you.)

0.5864

Oil Production Rate 32 BOPD API Gravity of Oil 35 Total Water Production Rate 10 BWPD What is the type of brine, Fresh or Saline? Fresh Results and Recommendations Hydrate Equilibrium Temperature 68.0F Degree of Subcooling 13.0F Methanol Volume Required 511 GPD FREEFLOW EC6481A Volume Required 4 GPD FREEFLOW EC6491A Volume Required 7 FPD * Input parameters here are shown in boldface type.




Gas Gravity Calculation Please Input the mol% of each component and the MW of the plus (C10+) fraction ABC Oil Company Component MW Mole% Avg MW

N2 28.01 0.37 0.10365

CO2 44.01 0.07 0.03081

H2S 34.00 0.00 0.00000

methane 16.04 97.67 15.66920

ethane 30.07 0.55 0.16539

propane 44.10 0.38 0.16757

i-butane 58.12 0.15 0.08719

n-butane 58.12 0.15 0.08719

i-pentane 72.15 0.09 0.06494

n-pentane 72.15 0.08 0.05772

n-hexane 86.18 0.15 0.12927

n-heptane 96.00 0.14 0.13440

n-octane 107.00 0.10 0.10700

n-nonane 121.00 0.08 0.09680

n-decane 320.00 0.01 0.03200

C10+ 500 0.01 0.05000

Total 100.00

Gas Gravity 0.5864 16.98311




11.7 Product Selection

In the 1930s, Hammerschmidt discovered hydrates as a pipeline plugging solid and developed the following equation to predict the degree of subcooling as a function of inhibitor concentration. Today, the Hammerschmidt equation remains as a very useful tool to quickly assess the amount of thermodynamic inhibitor required for hydrate inhibition at a given degree of subcooling.

C W T = (Hammerschmidt equation)

M (100 - W) Where: T = degree of subcooling, (Thydrate equiliburium - Toperating), in F C = constant for a particular inhibitor (2,335 for methanol or 2,000 for ethylene glycol) W = weight percent of the inhibitor in the aqueous phase M = molecular weight of inhibitor (32 for methanol or 62 for ethylene glycol)

11.7.1 Hydrate Prediction Programs

Recently more accurate methods using computer modeling have been developed to build the hydrate equilibrium curve for a specific system. Nalco uses the three most popular industrial standard programs to estimate the hydrate equilibrium curve and, thus, the severity of the operating condition in terms of its hydrate potential. These programs are PVTSim developed by Calsep, Multiflash developed by Infochem, and CSMHYD developed by Colorado School of Mines. A simplified calculation was developed and included in the HydraCalc program to be used by the field personnel. Alternatively, the hydrate equilibrium curve can be measured in the laboratory by tracking the hydrate dissociation temperature as a function of pressure. The predicted curve is very accurate for the condensate system, generally within 1F error. However, large variations have been seen for the black oil systems due to potential interference that has not yet been fully identified and built into the models. Once the degree of subcooling is determined from the hydrate equilibrium curve and the operating condition, chemical inhibitor is selected and the dosage is decided based on the minimum effective concentration required. For KHI, the minimum effective concentration is a function of the degree of subcooling. For AA, the minimum effective dosage is dependent upon the hydrocarbon in the system. Regardless of AA or KHI being selected, it is better to verify the performance of LDHI in the laboratory to assure its effectiveness. Indeed, most customers would require some kind of laboratory testing before approving a product.




11.7.2 LDHI Laboratory Tests

Several kinds of laboratory test systems have been used for evaluating LDHI. These can be grouped into small-scale test equipment and large-scale simulation systems. All of these test systems are designed to operate at high pressures and low temperatures, some with visual capability. Autoclaves and rocking cells are small-scale test equipment; the flow loop and wheel loop are large simulation systems. The criteria for passing the performance test are different for each LDHI. To pass the test, KHI must inhibit hydrate formation for a minimum of a certain number of hours (typically 48 hours) at a specified subcooling or operating condition. The performance of AA is measured visually, although some may use viscosity or torque measurement as a quantitative and auxiliary tool. Acceptable AA performance must demonstrate free-flowing liquid containing tiny, dispersible hydrate particles. Autoclave tests are typically carried out in high-pressure vessels with multiple duplicates. The vessels are typically equipped with agitation devices, cooling jackets, as well as pressure, temperature, and/or torque sensors. Some may also have windows for visual inspection. A picture of the autoclave system is shown in Figure 12.

Figure 12. Picture of autoclaves for LDHI testing




The performance of KHI is usually measured by the induction time allowed at a given concentration. The induction time for hydrate formation is measured by monitoring the onset of hydrate formation, which will trigger a temperature spike (due to exothermic reaction) and a pressure drop (due to gas consumption) in a constant T/P experiment, as seen in Figure 13. Multiple duplicates are important to account for the expected variations in the measured induction time. It is known that all nucleation processes, including hydrates, are stochastic and, as such, require multiple duplicates to get a statistical average. The performance of AA in the autoclaves is assessed by visual inspection using the criteria stated above.

Figure 13. Temperature and pressure profiles of autoclave test of hydrate formation in the presence of KHI

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Rocking cell tests are typically performed in a small high-pressure cylinder made out of sapphire tube. A ball is placed inside the tube to provide agitation as the tube is being rocked. The measurement criteria are the same as those of the autoclave test. The main difference is that the shear force and the fluid mixing in the rocking cells are much less than those provided by the autoclave due to the mild rolling action of the ball. The rocking cells are typically placed in a constant temperature bath to achieve the low temperature. Figure 14 shows a picture of the rocking cell test unit located in Sugar Land, Texas.

If the candidate LDHI passes the performance tests in the small-scale laboratory unit, a large-scale simulation system is commonly used to verify the performance prior to scheduling a field trial. The most commonly used simulation systems are high-pressure flow loop and high-pressure wheel loop. High-pressure wheel loop was developed by Statoil to study the flow of production fluids in a closed conduit, such as subsea pipelines. Various types of chemicals, including LDHI, have been tested in this loop to assess the effect of these chemicals on the fluid behavior.

Figure 14. Picture of rocking cells for hydrate inhibitor evaluation.




A picture of the wheel loop is shown in Figure 15 along with hydrates formed inside the viewing window. The loop is usually made out of steel pipe shaped into a circle. The loop is mounted on a shaft connected to a motor and a torque sensor. Some loops are equipped with viewing windows to allow visual observation of the fluids inside. A camera is typically mounted on the windows to record the visible changes throughout the experiment. The whole assembly is housed in a temperature-controlled chamber in which the temperature is cooled to simulate the cold deepwater environment. One fundamental difference between the wheel loop and the fluid flowing in the pipeline is that the wheel loop has a moving pipe and relatively stagnant fluids, instead of fluids moving in a fixed pipe. In addition to visual observation of hydrate formation, some other variables are also monitored, such as pressure change or gas uptake.

Figure 15. Pictures of wheel loop in a cold chamber and hydrates in the viewing section




Figure 16. Flow loops in IFP (top), SWRI (bottom left) and ExxonMobil (bottom right)

A flow loop is probably the most realistic, large-scale pipeline simulation system built to study fluid behavior and chemical performance. Flow loops of various sizes and designs have been built. Pictures of some flow loops for hydrate studies are shown in Figure 16. These loops are typically operated at high pressure and low temperature for hydrate studies. Some are housed in a temperature-controlled chamber similar to those used for the wheel loop. Some have a cooling jacket around the pipe to control temperature. The differential pressure around the loop is monitored constantly. Any increase in differential pressure can be indicative of hydrate build-up. Some flow loops also have viewing ports to allow visual inspection or videotaping of the experiment.




11.8 Application Guidelines

The selection and design of a hydrate control program based on LDHI technology is discussed in sections 11.6 System Survey and 11.7 Product Selection. Laboratory tests to confirm the LDHI performance and to measure the effective concentration are also discussed. It is equally important to address several implementation issues before and during the deployment of any LDHI program in deepwater operations. These issues may not be as pertinent in land-based gas systems. 11.8.1 Material Compatibility

Material and chemical compatibility of LDHI with the system being treated is a key factor to determine whether the specific LDHI can be deployed. Material compatibility involves both metallic and non-metallic materials. The active species in most KHI formulations is mostly polymers that are inert to common materials used in the oil and gas fields. Therefore, the solvent packages used in the formulations usually determine the compatibility of the finished products with the existing materials. Most of the kinetic inhibitors are formulated in aqueous base solvents, such as water and alcohols. These are the same fluids as those encountered in the conventional systems treated with thermodynamic inhibitors. Therefore, no additional materials requirement is needed for implementing the KHI program. Anti-agglomerants, on the other hand, can be formulated to be either water-soluble or oil-soluble. The active components are generally more reactive than the KHI polymers. Therefore, the material and chemical compatibility of AA is less predictable. 11.8.2 Chemical Compatibility

Chemical compatibility of LDHI with other production chemicals can vary greatly. Therefore, it is important to carry out compatibility studies to investigate the effect of LDHI on the performance of existing chemicals. The effect of the existing chemicals on the LDHI performance is equally important. The most frequently used production chemicals, especially in subsea pipelines, are corrosion inhibitors, scale inhibitors, and paraffin inhibitors. These chemicals are formulated either in aqueous base solvents or in hydrocarbon solvents. Most water-soluble chemicals do not interfere with KHI. As a result, neither the performance of KHI nor the performance of water-soluble chemicals is affected. For example, no adverse effect has been observed between KHI and water-soluble corrosion or scale inhibitors. Oil-soluble chemicals present a different challenge. These chemicals can affect the performance of KHI at very high concentrations (e.g., > 1,000 ppm). However, the interference can be eliminated in the presence of hydrocarbon liquids. The interference is attributed to the accumulation of these oil-soluble species at the interface where KHI is acting to inhibit hydrates. Presence of hydrocarbon liquids facilitates these interfering species to partition back to the oil phase, leaving KHI at the interface to perform its duty.




It is important to point out that the distinction of chemical interference based on the solubility of chemicals is simply a general trend observed thus far. A few exceptions to this trend have also been observed. Chemical interference of AA by other production chemicals is common. It is recommended that both physical stability and the chemical compatibility be tested in the laboratory prior to a field trial. The former testing involves mixing all the treatment chemicals in the umbilical simulation for the stability under deepwater conditions. The latter testing involves the performance check in the presence of all potential interfering chemicals. 11.8.3 KHI Lowest Critical Solution Temperature (Cloud Point)

Another issue of concern is unique to the use of KHI. Kinetic hydrate inhibitors contain polymers that typically exhibit an inherent property called the lowest critical solution temperature (LCST). The lowest critical solution temperature is the point when polymers begin to precipitate form the solution and is very strongly dependent on the solvent used. For this reason, LCST is sometimes referred to as the cloud point, similar to the cloud point (or wax appearance temperature, WAT) of wax precipitation. For example, the LCST of EC6481A is greater than 100C when in its proprietary solvent package; however, the LCST drops considerably to 50C when the product is injected to the produced fluid where the solvent for the polymers is changed to brine. The LCST of polymers used in KHI ranges from 100F to greater than 150F, depending on the chemistry of the polymer and the salinity of the brine. Concerns were often raised with respect to the hot injection, such as to the downhole tubing where the temperature could exceed the LCST. This issue was addressed through formulation technique and simulation studies in the laboratory. Most KHI packages have been specially formulated so that the finished products remain clear and stable at temperatures above 100C. Therefore, no precipitation problem is expected in the injection line or umbilical. However, as the inhibitor enters the produced stream where it gets further diluted in the brine, the LCST can be substantially reduced by the change of solvent. It is possible to have polymers precipitated from the solution if the LCST falls below the fluid temperature. Laboratory simulation work shows that, at a typical concentration (< 5,000 ppm), KHI polymers precipitate as very tiny species that are very well dispersed in the produced fluids and continue to migrate downstream. It is unlikely that these highly dispersed species will deposit under the dynamic flowing condition. These polymers are dissolved easily back to the solution as soon as the downstream temperature drops below the LCST.




11.8.4 Solvent Stripping by Gas of LDHI

Similar to the application of any other production chemicals, the possibility of solvents being stripped by the produced gas must be assessed. Some produced gases can be relatively dry because the operating temperature is above their water dew point or hydrocarbon dew point. In such cases, the dry gas has the tendency to strip all the solvents away from the inhibitor, leaving behind the active species as solid residues. This not only stops the transport of inhibitors to where it needs to be but also creates a potential plugging problem. Therefore, the water/hydrocarbon saturation level in the gas phase must be properly assessed before the LDHI injection. If the produced gas is expected to be under-saturated with water or hydrocarbon, one of the following three approaches can be attempted to solve the problems: Pump additional solvents. Apply special LDHI with a low vapor pressure solvent. Inject LDHI at locations where temperature is below the dew point. 11.8.5 Physical Properties of LDHI

Physical properties such as flash point, pour point, and viscosity are important issues not to be overlooked. Among them viscosity is the most critical property that is difficult to be compromised because of the hardware limitation. Due to the difference in chemistry, AA is usually less viscous than KHI. The viscosity of KHI formulations increases with the polymer concentration and molecular weight. To meet this challenge, most KHI packages are formulated to keep the viscosity low enough for practical use. Viscosity directly affects the pressure drop across the chemical line and the overall pressure rating of the line. The higher the viscosity, the more powerful the injection pump and the higher the pressure rating required for the injection line. Some low viscosity kinetic inhibitors have been successfully formulated to achieve a viscosity of 15-20 cP at 20C and 25-30 cP at 4C. These low viscosity products are the most desirable KHI for long subsea pipelines with a small diameter umbilical and a higher KHI demand. 11.8.6 Injection Maintenance Caution

If LDHI is to replace the existing thermodynamic program, care must be taken to ensure that the current injection rate is maintained, as if the thermodynamic inhibitors are still being pumped, until the thermodynamic inhibitors are completely flushed out of the injection line. If the initial injection rate was turned down before the LDHI reaches to the other end, the produced fluid can be severely under-treated resulting in rapid hydrate formation. The initial volume (or injection time) required to flush the existing inhibitors can be readily estimated from the dimension of the chemical line and the injection rate.




11.9 Field Monitoring

Proper and constant monitoring of the inhibitor performance is the key to the success of the LDHI program. Although some prototypes may be under development, there is no standard hydrate probe in the market reliable and practical enough for on-line detection of hydrates. The effectiveness of hydrate control programs still relies on the analysis of some indirect but essential indicators. Most of these indicators are indeed being used in the monitoring program for traditional thermodynamic inhibition programs. The first key issue is to make sure that LDHI is delivered where it needs to be and distributed evenly throughout the system. In the case of subsea flowlines, the operator can look for the break-through of LDHI at the other end of the line. Depending upon the specific type of LDHI being used, different indicators, such as foaming, haziness, or discoloration, can be used to confirm the break-through. Once the break-through of LDHI is confirmed, samples can be taken to measure the residual chemical concentration. It is not uncommon to see the residual chemical concentration lower than the target value due to incorrect water production rate or inevitable adsorption onto solids. If this happens, the operator can check other indicators described below to decide whether to continue to adopt the current rate or to boost the injection rate to reach the target concentration. Increased pressure drop across the pipeline is a good indicator of hydrate formation. The increase in pressure drop can result from a partial blockage and/or increased viscosity due to hydrate slurry. If KHI is used for hydrate control, the pressure drop across the pipeline is expected to have little or no change. If AA is used for hydrate control, one should expect a small increase in pressure drop due to slurry formation. However, the pressure drop should remain as a constant after the initial hydrate formation. Any continuous increase in pressure drop is a sign of blockage caused by agglomeration of hydrate particles.




Excessive pressure fluctuation is also a good indicator that solid hydrates might be entrained in the fluid stream, as shown in Figure 17. However, both pressure drop and pressure transient can also be affected by changes in the production rate, which alone can lead to increased pressure drop or excessive fluctuations without formation of hydrates. Fouling Index is often used to eliminate or reduce the effect of changes in production rates from the pressure drop monitoring.

Figure 17 shows two types of pressure drop increases that occur with hydrate blockage of lines. The left chart shows the gradual increase in pressure drop, which would occur if hydrates form an ever-decreasing cross-section for the fluid to pass through. The right chart shows the more typical case of multiple spikes in pressure drop before the ultimate blockage. These spikes are indicative of particles in the cycle being stuck and released prior to the total blockage. If KHI is being pumped to the pipeline where pigging is capable, the pipeline should be pigged at a desired frequency. The fluids collected in the pig trap should be inspected for any presence of hydrates. Excessive degassing of water can be an indication of a minute amount of hydrates formed in the pipeline, even though solid hydrates may not be spotted in the pig trap. Regular pigging is also recommended for the systems treated with AA. Pigging allows the stagnant hydrate slurry to be removed before it becomes permanently stuck to the wall. The effectiveness of KHI can also be monitored by observing any sudden drop or gradual decrease in water production rate. The loss of water may indicate the consumption of water caused by hydrate formation. The aforementioned indicators are suggested as a tool for the operators to effectively monitor the performance of LDHI in their systems.

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Chapter 11 Hydrates