Inhibitor injection

On the fig. 1 is given the family of curves displaying the dependence of chemi-luminescence intensity ver-sus time at injection of AO (the arrow shows the moment of inhibitor injection). 

Currently, there are three possible gas recovery processes for hydrates (1) thermal stimulation, (2) depressurization and (3) inhibitor injection. Very limited thermal stimulation and depressurization tests were reported for the Mallik natural gas hydrate reservoirs, together with numerical simulations (Moridis et al. 2004,... 

Dump Systems For an inhibitor injection or quench system, the inhibitor or quenching medium is transferred from an external supply to the reactive material in a dump system, the reactive material is transferred from the storage/handling facility to a safer location that is the same size or, more commonly, larger than the normal capacity of the facility. This allows depressurizing and deinventory of the reacting mass from the facility in an out-of-control situation, such as an incipient runaway reaction. 

Models have been developed to evalnate natnral gas production from hydrates by both depressnrization and heating methods. There are three methods to obtain methane from gas hydrates (1) the depressurization method, (2) the thermal stimulation method, and (3) the chemical inhibition method. The thermal stimulation method and the chemical inhibitor injection method are both costly procedmes, whereas the depressurization method may prove useful when applied to more than one production. 

Fig. 5.9 Design of the chip-based enzyme ESI-MS assay. MS instrument Ion-trap mass spectrometer (LCQ Deca, Thermo Electron). I Sample components/inhibitors injected by flow injection or eluting from capillary HPLC column. E Infusion pump delivering the enzyme cathepsin B. S infusion pump delivering the substrate Z-FR-AMC. Micro-chip design Vrije Universiteit Amsterdam. Micro-chip production Micronit Microfluidics BV (Enschede, The Netherlands).

Downhole wax inhibitor injection will not he required since the stabilized flowing temperature within the well tubing and at the wellhead will be some 55°C which is wpll above the cloud point and wax dissolution... 

Since HtS dissolved in water is very corrosive to carbon 4 steel, a comprehensive corrosion-control program is being conducted. In the field, each well is treated once per month by displacing inhibitor down to the perfora-. tions with stock tank oil. Corrosion coupons in the flow-lines are inspected every 6 months Little corrosion has been detected in the field. In the plants, corrosion in-hibitor is added daily to the gas-sweetening solvent, the salt water system, and the stabilizer overhead. Inhibitor is -Jj also added to bulk chemicals as received. Numerous corrosion coupons and probes are installed in each facility and are pulled for inspection every 1 to 3 months Corrosion rates have been low (less than I mil/year) asY result of the inhibitor injection program. 

Soviet researchers indicated that thermal stimulation from above the ground was not economically viable. Trofimuk et al. (1982) suggested alternatives of pressure reduction, inhibitor injection, geothermal stimulation, or in situ combustion techniques. Recovery techniques modeled in the Western Hemisphere were by either pressure reduction or thermal stimulation. The first of these was by McGuire (1982), followed by Holder et al. (1984a), Burshears et al. (1986), and workers in the CSM laboratory (Selim and Sloan, 1985, 1987, 1989 Yousif et al., 1988, 1990). 

Hydrate dissociation is of key importance in gas production from natural hydrate reservoirs and in pipeline plug remediation. Hydrate dissociation is an endothermic process in which heat must be supplied externally to break the hydrogen bonds between water molecules and the van der Waals interaction forces between the guest and water molecules of the hydrate lattice to decompose the hydrate to water and gas (e.g., the methane hydrate heat of dissociation is 500 J/gm-water). The different methods that can be used to dissociate a hydrate plug (in the pipeline) or hydrate core (in oceanic or permafrost deposits) are depressurization, thermal stimulation, thermodynamic inhibitor injection, or a combination of these methods. Thermal stimulation and depressurization have been well quantified using laboratory measurements and state-of-the-art models. Chapter 7 describes the application of hydrate dissociation to gas evolution from a hydrate reservoir, while Chapter 8 describes the industrial application of hydrate dissociation. Therefore in this section, discussion is limited to a brief review of the conceptual picture, correlations, and laboratory-scale phenomena of hydrate dissociation. 

Relative to our phase equilibrium study in Chapters 4 and 5, the above three techniques are illustrated on the phase diagram of Figure 7.18, as AT = 0, AT = 0, and 10% methanol, for depressurization, thermal stimulation, and inhibitor injection, respectively. Additional explanation is given in the figure caption. 

Figure 7.18 A phase diagram showing the three common hydrate dissociation techniques, relative to the initial sample condition (intersection of horizontal and vertical arrows). Depressurization is shown as AT = 0 thermal stimulation as AP = 0 inhibitor injection is represented by displacing the solid hydrate formation curve to the dashed curve, via injection of 10 wt% methanol in the free water phase.

The discussion in Section 7.6 is not intended to imply that the three methods of depressurization, thermal stimulation, and inhibitor injection are the only means of hydrate dissociation. Because the hydrate science is available as indicated in the earlier chapters of this book, the application of that science to recovery from hydrates is an exercise for the innovative engineer. Novel ideas such as fire flooding (Halleck et al., 1982), burial of nuclear wastes (Malone, 1985, p. 27), and the use of electromagnetic heating (Islam, 1994) are only three innovative ways of dissociating hydrates, but none have been tried. However, in this portion of the chapter, it is intended to describe trends for dissociating hydrates in several kinds of reservoirs, as an indication of the future. 

The Messoyakha field has been produced through both inhibitor injection and depressurization, as well as combinations of the two. The inhibitor injection tests, presented in Table 7.14 from the combined results by Sumetz (1974) and Makogon (1981, p. 174), frequently gave dramatic short-term increases in production rates, due to hydrate dissociation in the vicinity of each injected well bore. In the table, methanol and mixtures of methanol and calcium chloride were injected under pressure, using a cement aggregate. For long-term dissociation of hydrates, depressurization was used. 

Test Results from Inhibitor Injection in the Messoyakha Field... 

When the water phase is uninhibited, as when excess water is produced, dehydrator failure, or when inhibitor injection is lost, for example, due to inhibitor umbilical failure or inhibitor pump failure. 

The reason for this system failure was that the importance of a reliable temperature measurement for triggering the inhibitor injection was duly recognized during the risk analysis and an especially thick tube was installed for the temperature probe, providing a high mechanical resistance. .. but also a high time constant for the thermometer Hence, as the temperature probe reached... 

It is important to correctly inject the inhibitor. Injecting the inhibitor upstream of a point of high turbulence such as a pump suction or ahead of a pump letdown valve has been recommended (373). An injection point a long distance upstream of the column should be avoided whenever possible (328). It is also important to disperse the inhibitor correctly. One case has been reported (50)... 

It is essential to inject the amount of inhibitor recommended by the supplier or found optimum in laboratory tests. Excessive inhibitor injection can be harmful. One experience has been reported (85) where application of three times the recommended amount of antifoam inhibited tray action, causing product purity to drop. In other circumstances, excessive inhibitor addition was reported to aggravate a foaming problem (84, 238, 239). 

At present, conventional methods to control coal spontaneous combustion in goaf include grouting, nitrogen injection, inhibitors injection and etc. fire-fighting technology (Qin Botao 2007, Chan Yafei 2008). In recent years, by the study of coal spontaneous combustion mechanism and new materials, new fire prevention and extinguishing... 

Fig. 2. Urinary glucose excretion in partially depancreatized rats with or without poly(ADP-ribose) synthetase inhibitor injection. 1, 2, and 3 months after the 90% pancreatectomy, the urine of each rat was collected for 24 h. Urinary glucose levels were measured by the glucose oxidase method. O Control rats nicotinamide-injected rats 3-aminobenzamide-injected rats. Statistical significance of differences between rats treated with and without poly(ADP-ribose) synthetase inhibitors was analyzed using Student s t test. Each point is the mean for five different rats vertical bars show SD when larger than the symbol indicating the mean value., and = p<0.10, p<0.05, and p<0.025 vs control rats. The time after the partial pancreatectomy is shown on the abscissa...

Interrupted inhibitor injection or an overdose of acid can be highly detrimental, causing damage to materials and lessening thermal exchange efficiency. 

There are several approaches to dissociate hydrates depressurization, thermal stimulation, thermodynamic inhibitor injection, or a combination of these methods. By depressurization or thermal stimulation, hydrate can be moved across the phase equilibrium fine to the unstable zone. However, inhibitor injection does not aim to change the temperature or pressure conditions of the hydrate but switch the phase equilibrium line to a lower temperature and a higher pressure, leaving the hydrate in the unstable zone. 

In this case, the ion-association model predicted that the connate water would require a minimum dilution with boiler feedwater of 15 percent to prevent halite precipitation (Fig. 8.23). The model also predicted that over-injection of dilution water would promote barite (barium sulfate) formation (Fig. 8.24). Although the well produced F1,S at a concentration of 50 mg/L, the program did not predict the formation of iron sulfide because of the combination of low pH and high temperature. Boiler feedwater was injected into the bottom of the well using the downhole injection valve normally used for corrosion inhibitor injection. Injection of dilution water at a rate of 25 to 30 percent has allowed the well to produce successfully since startup. Barite and iron sulfide precipitation have not been observed, and plugging with salt has not occurred. 

The KPI itself is derived from a measure of the produced fluids including water and hydrocarbon phases and the inhibitor injected in the produced fluid stream to provide a correlation between how much inhibitor should be in the produced fluid stream versus actual injected inhibitor concentrations. The KPI percent inhibitor availability (Inhibitor y) function is described by Eq. (12.6) ... 

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