There is evidence that short lines (< 20 miles) can be handled with heat management; however, heating solutions may not be practical at line lengths greater than 50 miles. In addition to the conventional inhibitors MeOH and monoethylene glycol (MEG), there are three new types of hydrate inhibitors, sometimes called low-dosage hydrate inhibitors, which were tested in the field during the 1990s. [4] These dispersants are particularly effective in hydrate-plug protection upon line shut-ins and restarts. OnePetro (4) Petrowiki (2) SPE.org (1) Date. Filters provided upstream of the spray nozzles can avoid plugging of the spray heads. [6] To date, efforts to identify the stabilizing components, remove them, and re-insert them in a noninhibited oil have been unsuccessful. In addition, a cone inlet channel helps maintain uniform gas velocity profile so that the glycol spray pattern is not distorted. While most of the methanol dissolves in the water, a significant amount of methanol either remains with the vapor or dissolves into the liquid hydrocarbon phase. Wet gas contains entrained liquids consisting of water and hydrocarbon condensates that can cause hydrate formations in the orifice plate fitting, flow recorders, and instrument lines. The lowest temperature at which ethylene glycol injection units can be operated is −30°F. Figure 25-7. Pilot Loop Tests of New Additives Preventing Hydrate Plug Formation. For example, a recent Gulf of Mexico flowline experienced an overall-heat-transfer coefficient of 2 Btu/(hr-ft2-°F), while the design coefficient was 0.176 Btu/(hr-ft2-°F), the latter being a typical value for such applications. Injection rates of 120 L/h for gases may be anticipated. Determining the minimum production rates that will prevent hydrate formation in the wellbore. Only the smallest tank did not have enough width. Depending on the reservoir fluids the injection chemical can be - Methanol or Mono Ethylene glycol (MEG) for gas and gas/condensate wells. Slurry flow and heating/insulation represent, respectively, the fourth and fifth methods of hydrate prevention. The allowable values are defined in Table 25-7 as per ASME B31.8. Based on crude composition, pressure and temperature injection ratios of 10–50 ppmv may be expected. Injection to the export line is always done because costs of an export line from exotic material like Inconel are very high. Fluid Phase Equilibria 117: 186. Before considering prevention of hydrate plugs, it is important to consider safety problems involving hydrate plug removal. Notz, P. 1994. No liquid hydrocarbon need be present. There are occasions, rightly or wrongly, when the decision is made to operate a line or process containing liquid water. SPE disclaims any and all liability for your use of such content. 9.6. If a bare pipe is considered as the baseline cost, insulation can easily double to quadruple the installed-pipe cost. They are used to protect equipment, recover valuable streams, and meet environmental discharge limits. In this text, some chemicals are explained. Potential problems include: Incomplete coverage of all heat exchanger tubes with glycol spray, resulting in hydrate formation and plugging in some tubes. Tank shall be redundant to enable cleaning, repair without platform shutdown. Similarly, when planned or unanticipated shutdowns take place, large quantities of antifreeze are added in order to prevent hydrate formation. C. C. Chen and Y.-S. Liu, Wood Group Mustang, Houston, Texas. Highlight matches. Of the 20 gases, the lowest hydrate-formation pressure was 100 psig for a gas with 7 mol% propane, while the highest value was 300 psig for a gas with 1.8 mol% propane. Glycol has limited solubility in the gas phase so the glycol must be carefully distributed to each heat exchanger tube to ensure that an adequate amount is present in each tube to prevent hydrate formation. The outlined procedure exhibits the P-T history of the system and hence the hydrate formation temperature profile. Saeid Mokhatab, ... John Y. Mak, in Handbook of Natural Gas Transmission and Processing (Third Edition), 2015. In many cases transport distance is long enough to bring crude temperature equal to surrounding water. More information. The spray system is critical in the design of heat exchangers with glycol injection. Natural Hydrate Inhibiting Components in Crude Oils. Corrosion inhibitor is injected to prevent piping corrosion. The reactor effluent flows to a three-phase separator where air, disulfides, and regenerated caustic are separated. Crossover Loop (Left) and Production Loop (Right). The potential problems include: incomplete coverage of all heat exchanger tubes with glycol spray, resulting in hydrate formation and plugging in some tubes, inadequate mist formation by the injection system, resulting in uneven glycol distribution, and. [2]. In certain conditions crude may experience an abrupt reduction in pressure like during start-up of well. When injecting to the well, the pressure shall be equal to well flowing pressure and when injecting to the export line, it shall be equal to platform design pressure. The hydraulic and thermal models may be simulated using the commercial software PIPESIM or OLGA 2000. In Pipeline Rules of Thumb Handbook (Eighth Edition), 2014. From 45 to 50 miles, however, a second cooling trend is observed because of the Joule-Thomson gas-expansion effect. They may include pressure gauges and transmitters in the pump suction and discharge heads, level gauges and transmitters in the tanks, pressure reduction valves in the bypass lines to return excess chemical to the tanks, etc. The injection of salts (primarily CaCl 2) reduces hydrate formation by lowering the chemical activity of water, and by lowering the solubility of gas in water. The following philosophies may be adopted during shutdown operations: The subsea methanol injection system is capable of treating or displacing produced fluids with hydrate inhibitor between the manifold and SCSSV following well shutdown to prevent hydrate formation. High-efficiency liquid–liquid coalescers are finding increasing applications in industry where problematic emulsions exist. AutoPIPE Models of Tree Loops. 1. In order to prevent hydrate formation, the oil companies pour large volumes of antifreeze (methanol or glycol) into wells, pipelines and process equipment. To produce high-purity ethane from a wet NGL feed, a high-pressure deethanizer design has been developed to prevent hydrate formation without using a dehydration unit. Placing stiffeners inside tank is normally avoided. A new methanol-injection system to prevent hydrate formation in Main Pass Block 6 field, Gulf of Mexico, has passed its first winter's test. API RP 10B, Recommended Practice for Testing Well Cements, 22nd edition. Methanol Injections To Prevent Hydrate Formation Thanks to its chemical properties, Methanol can lower the freezing point of a water-based liquid and increase its boiling point, therefore, it is used as an antifreeze to keep cleaning fluids from freeing. Demulsifier is injected at inlet piping of production and or test separators. One successful solution to prevent hydrate formation is to use drip or condensate bottles in instrument and gauge lines. What Conditions Are Necessary to Promote Hydrate Formation? The process flow schematic for a glycol injection dehydration system is shown in Figure 7-6. Methanol/MEG or any LDHI may be used to prevent hydrate formation. Paper IIIb presented at the 1993 Intl. In-field LDHI injection rate may be 200 times less than MEG. Figure 25-8 shows the models of two loops used for the analyses. Chemical injection systems on one skid. [2] To the right of the diagram, hydrates will not form, and the system will exist in the fluid (hydrocarbon and water) region. Mobil Oil Corp. installed the system to prevent loss of production, due to hydrate formation in long flow lines between wells and production platforms. Phenols are also extracted into the caustic phase. During FEED analysis, the production system should be modeled starting at the reservoir using inflow performance relationships. Liquid or homogeneous catalysts are used in a number of processes where the catalyst and the reactants are insoluble and form emulsions. Figure 25-8. The most important variable affecting hydrate formation is the activity of the water, which is decreased by chemicals that dissolve by bonding to water molecules. Antifoam is injected at inlet piping of both test and production separator to prevent this phenomenon. There are four techniques to prevent hydrate formation: Remove the free and dissolved water from the system with separators, glycol dehydrators, molecular sieves, or other methods. This type of … Hydrate Formation and Behaviour in Pipes. Lower hydrate formation temperature with chemical 3. inhibition Dehydrate gas so water vapor will not condense into “free water”. Conference on Natural Gas Hydrates; E.D. Wet gas can be chilled to meet pipeline water as well as hydrocarbon dew point specification using the glycol injection process, which includes propane refrigeration for chilling. However, a few companies are considering methanol recovery from the aqueous phase. We use cookies to help provide and enhance our service and tailor content and ads. The hazy gasoline is problematic and has to be blended off or reprocessed; otherwise, it would cause the product to be off-specification in terms of sodium. Earlier than January, 2015 (2) 2018 (1) 2019 (1) 2020 (3) to. The chemical injection package consists of tanks, pumps, and control panel. In Predicting hydrate formation, a hand calculation method, accurate to 75%, is given for hydrate formation. Alternatively, heating the natural gas stream with a line heater above the temperature (PT value) at which hydrates form can also work. In the production of gasoline, organic sulfur compounds such as mercaptans often need to be removed. Table 25-8 lists the input data of design parameters for loop stress analyses. As can be seen from these plots, the hydrate formation temperature is about 61 to 65°F for almost every station. 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