Injection Of Hydrate Inhibitors Research Articles

Modeling Two-Step Mechanism of Thermodynamic Hydrate Inhibitor Injection for Gas Hydrate Plug Dissociation

Modeling Two-Step Mechanism of Thermodynamic Hydrate Inhibitor Injection for Gas Hydrate Plug Dissociation

Dew pressure point and liquid dropout of CH4 + alcohol (methanol or ethanol) system with high gas content at high-pressure and high-temperature

Hydrate inhibitor injection through gas-lift flow is used in production fields. The gas + inhibitor system's phase behavior provides essential information regarding monophasic regions and operational safety conditions. Methane is the main constituent of natural gas and is commonly used as a model component to represent gas reservoir fluids. However, pressure variation during a gas-lift injection can cause liquid dropout at valve injection. Therefore, phase behavior knowledge of methane + alcohol mixtures is potentially interesting in the oil and gas industry. In this work, dew pressure and liquid dropout data were experimental measured for methane + methanol (96.60 mol % CH4) and methane + ethanol (96.50 mol % CH4) systems in the temperature domain of 313.15 to 366.65 K and pressure up to 70 MPa. The CPA equation of state was used to correlate dew pressure and liquid dropout data for all systems, presenting a dew pressure absolute relative deviation of 6.89 and 5.22 % for methane + methanol (96.60 mol % CH4) and methane + ethanol (96.50 mol % CH4), respectively.

Kinetics of methane + hydrogen sulfide clathrate hydrate formation in the presence/absence of poly N-vinyl pyrrolidone (PVP) and L-tyrosine: Experimental study and modeling of the induction time

Gas hydrates, or clathrate hydrates, formation can dramatically damage the transmission lines and operational equipment of the natural gas dominated system, which in turn to ruptured pipeline or destruction equipment. To prevent these problems, hydrate inhibitor injection is one of the most practical approaches. Subsequently, in several experimental studies, the induction time appraisement is employed as an expression for the inhibition accomplishment of kinetic hydrate inhibitor (KHI). Therefore, predicting/estimating the gas hydrate induction time is a crucial and essential subject in this field. To tackle this substantial issue, in the current investigation, the kinetics of methane + hydrogen sulfide hydrate formation (induction time) was investigated. The effects of using two types of KHI including Poly N-vinyl pyrrolidone (PVP) and L-Tyrosine with different concentrations (less than 2 wt%) on the induction time of the aforesaid system were revealed. The experiments were performed in a 100 cm3 stirred autoclave at temperatures ranging from 274.15 to 280.15 K over the primary pressure of 10 MPa. The experimental results indicate that KHIs at low concentrations (less than 2 wt%) approximately have no observational effects on thermodynamic equilibrium conditions but have a significant impact on increasing the induction time and abating the gas consumption during crystalline solid formation. This study also aimed at utilizing the Perturbed-Chain Statistical Associating Fluid Theory (PC-SAFT) based model of induction time for hydrate phase appearance of the binary gaseous comprising of 0.995 mole fraction (MF) CH4 + 0.005 mole fraction (MF) H2S at different subcooling in the presence and absence of PVP and L-Tyrosine applying the Freundlich adsorption isotherm. Model results show a satisfactory agreement with experimental data. The model can be used for reliable calculation of hydrate formation induction time for the methane + hydrogen sulfide + water system in the presence/absence of the aforementioned KHIs.

Gas Hydrate Formation Risk and Prevention for the Development Wells in the Lingshui Gas Field in South China Sea

Hydrate formation risk is an important challenge in the development of deep-water gas field. Considering the characteristics of the Lingshui (LS) gas field in the South China Sea and the difference of well structures, a model for calculating wellbore temperature and pressure in deep-water gas production well is proposed and verified by the field data. Combining the hydrate equilibrium models with varied gas components, the prediction method of hydrate formation region in deep-water gas well in the South China Sea is obtained. The hydrate formation regions under different operating conditions for a deep-water gas well in the South China Sea were given by the proposed model. The results show that no hydrate formation risk exists in the production operation, but the risk exists in the shut-in and testing operations. Meanwhile, the determination of the hydrate inhibitor injection parameters during the testing operation is studied, and the influence of the inhibitors’ injection concentration and pressure on preventing gas hydrates is analyzed. This work provides useful advice for the prediction and prevention of hydrate formation risk in the development of deep-water gas fields, especially in the South China Sea.

Economic benefit of methane hydrate reformation management in transport pipeline by reducing thermodynamic hydrate inhibitor injection

Hydrate reformation is an inherent risk in a methane hydrate production system because dissociated water and methane flow through transport pipelines simultaneously. In this study, comprehensive experiments using high-pressure autoclaves are performed to investigate the effect of reducing the concentration of thermodynamic hydrate inhibitor on hydrate reformation characteristics. In order to simulate the production of methane hydrates, these are formed and dissociated in the preliminary stage; thereafter, the hydrates are reformed from dissociated water. Although dissociated water and fresh water are found to have similar formation rates, they have a major difference in relative torque, especially in the early stage of hydrate formation. The instant rise of the relative torque in the dissociated water is observed to be up to 2.5; thereafter, it remains approximately 3.0 until hydrate conversion reaches 28 vol%. This trend is different from that in fresh water, where a steady increase in relative torque with sudden spikes is observed. These results clearly show the high risk of hydrate blockage in the transport pipelines of a methane hydrate production system; hence, the injection of hydrate inhibitor is necessary. In this study, monoethylene glycol (MEG) is the selected thermodynamic hydrate inhibitor; its concentration is maintained below a specific value to completely avoid hydrate formation. Despite the occurrence of hydrate reformation, a stable relative torque is observed in a 20 wt% MEG concentration, where the conversion of water to hydrate approximately reaches 40 vol%. For a 10 wt% MEG concentration, a sudden increase in relative torque of up to 2.0 is observed in the early stage of hydrate formation; this suggests that the foregoing is less effective in sustaining flowability. Compared to fresh water, the addition of a 20 wt% MEG to dissociated water results in a more stable torque. Once the performance of the MEG concentration reduction is confirmed, the MEG regeneration process is designed accordingly by using both multiphase flow and process simulation models. A life cycle cost (LCC) analysis is conducted by estimating the capital expenditures (CAPEX) and operating expenditures (OPEX) of the MEG regeneration process. Considering both CAPEX and OPEX, the LCC for complete inhibition (35 wt%) is 90.15 MUSD (million United States dollars); however, for the 20 and 10 wt% MEG concentrations, the LCC values are reduced to 86.79 and 84.58 MUSD, respectively. The foregoing suggests the potential economic benefit of methane hydrate reformation management to avoid blockage.

Economic evaluation of MEG injection and regeneration process for oil FPSO

Injection and regeneration of MEG for an offshore oil field to prevent the risk of hydrate formation was compared to those of conventional hydrate inhibitor, MEOH (methanol). It was presumed that the injected MEG was regenerated in FPSO to 90 wt% concentration while the MeOH was simply treated without re-use. A multiphase simulation tool was employed to determine the temperature and pressure profile in subsea flowline, which provided the required concentration of hydrate inhibitors for hydrate prevention. While the required concentration of MeOH was around 18 to 30 wt% depending on the water depth, the concentration of MEG was varied from 28 to 46 wt%. NPC (net present cost) for MeOH and MEG injection was estimated as a function of injection count per year with economic assessment. The resulting NPC of MEG injection system for single injection event per year was expensive than that of MeOH injection system due to the higher total capital costs for MEG injection and regeneration system. However, the economic benefit of MeOH systems was decreased with increasing the injection event frequency because the injected MeOH cannot be recovered, and increasing storage tank and purchased MeOH cost were directly added to the total cost. When varying the water depth, i.e. ambient sea water temperature of the offshore oil field, the minimum number of injections per year was different for the MEG injection system to be economically favorable than the MeOH injection system. It became economically favorable when injected more than 2.2 times per year for the case of water depth 1250 m, while it required more than 3.3 times per year for the case of water depth of 600 m. The results showed that the MEG injection and regeneration system can be a feasible option for remote oil fields depending on the average number of hydrate inhibitor injection per year.

Effect of Poly Vinyl Caprolactam Concentration on the Dissociation Temperature for Methane Hydrates

The use of KHI in conventional gas production has become common, but its applicability to methane hydrate production has not yet been extensively studied, particularly in the presence of residual hydrate structures. Methane gas from marine hydrate deposits can be produced by methods like depressurization, thermal stimulation, and the injection of hydrate inhibitors. Because residual hydrate structures known as hydrate precursors will exist in the liquid water phase after dissociation, the risk of methane hydrate reformation has to be evaluated during the production and transportation of methane gas through offshore pipelines. Even though one viable option to avoid hydrate reformation is injecting hydrate inhibitors before transporting the fluids through pipelines, one must consider the effect that these chemicals have on hydrate plug dissociation. In the research literature, results regarding dissociation phenomena are few. This study reports the effect on dissociation for methane hydrates formed with the...

Natural Gas Evolution in a Gas Hydrate Melt: Effect of Thermodynamic Hydrate Inhibitors.

Natural gas extraction from gas hydrate sediments by injection of hydrate inhibitors involves the decomposition of hydrates. The evolution of dissolved gas from the hydrate melt is an important step in the extraction process. Using classical molecular dynamics simulations, we study the evolution of dissolved methane from its hydrate melt in the presence of two thermodynamic hydrate inhibitors, NaCl and CH3OH. An increase in the concentration of hydrate inhibitors is found to promote the nucleation of methane nanobubbles in the hydrate melt. Whereas NaCl promotes bubble formation by enhancing the hydrophobic interaction between aqueous CH4 molecules, CH3OH molecules assist bubble formation by stabilizing CH4 bubble nuclei formed in the solution. The CH3OH molecules accumulate around the nuclei leading to a decrease in the surface tension at their interface with water. The nanobubbles formed are found to be highly dynamic with frequent exchange of CH4 molecules between the bubble and the surrounding liquid. A quantitative analysis of the dynamic behavior of the bubble is performed by introducing a unit step function whose value depends on the location of CH4 molecules with respect to the bubble. It is observed that an increase in the concentration of thermodynamic hydrate inhibitors reduces the exchange process, making the bubble less dynamic. It is also found that for a given concentration of the inhibitor, larger bubbles are less dynamic compared to smaller ones. The dependence of the dynamic nature of nanobubbles on bubble size and inhibitor concentration is correlated with the solubility of CH4 and the Laplace pressure within the bubble. The effect of CO2 on the formation of nanobubble in the CH4-CO2 mixed gas hydrate melt in the presence of inhibitors is also examined. The simulations show that the presence of CO2 molecules significantly reduces the induction time for methane nanobubble nucleation. The role of CO2 in the early nucleation of bubble is explained based on the interaction between the bubble and the dissolved CO2 molecules.

Determination of hydrate inhibitor injection rate for flowlines based on Monte Carlo method

The present study proposes a new methodology that estimates the acceptable injection rate of a hydrate inhibitor considering the random failure and subsequent maintenance of the topside system followed by the cooldown of the flowlines and risers where hydrate can potentially form. The proposed methodology consists of four steps: system description, topside system simulation, subsea system simulation, and construction of the exceedance curve for the inhibitor injection. As the system is defined in the first step, Monte Carlo simulation (MCS) is performed in the topside system simulation step to predict the system failure frequency and subsequent downtime that leads to the exceedance curve of the downtime. With the exceedance curve of the downtime, the longest downtime, equivalently the longest cooldown time, τLC, is estimated. In the subsea system simulation step, the cooldown path of the inventory is obtained by multiphase simulation and τTD, the time that the inventory touch down the hydrate formation region is defined. The last step combines the MCS with multiphase simulation to yield the frequency of the required MEG injection to avoid the hydrate formation. The exceedance curve provides risk-based information for determining the required MEG injection rate based on risk acceptance criteria, which may vary with different points of view. Four case studies are performed for several installations that have different extent of process configurations and insulation.

Determination of hydrate inhibitor injection rate based on the life-cycle cost of the injection facility and mitigating measures

This study presents a framework for hydrate formation risk management. Hydrate formation accidents and the consequences of hydrate formation risk are defined by the initiation of hydrate formation and pipeline blockage due to hydrate formation, respectively. The hazards, preventive measures and mitigating measures for hydrate formation are presented in accordance with defined accidents and consequences. A life-cycle cost (LCC)-based hydrate formation risk management methodology is proposed that consists of four steps: construction of an exceedance curve for the durations of operational interruptions, construction of an exceedance curve for the frequency versus the monoethylene glycol (MEG) injection rate, selection of the MEG injection rate, and LCC estimation. Operational interruptions are quantified in terms of the frequency of hazard occurrence and their extent via exceedance curves for the durations of the operational interruptions. The next step of constructing the exceedance curve for the frequency of hydrate formation with respect to the MEG injection rate quantifies the frequency of the accidents for a given MEG injection rate. Because the failure rate and the repair time of equipment are discrete, only a set of representative MEG injection rates deserve further consideration in the LCC estimation. Two case studies are performed with topsides that have different process complexities, which lead to different frequencies of operational interruption.

WITHDRAWN: A reliable model for estimating a hydrate inhibitor injection rate

This article has been withdrawn at the request of the Editor In Chief. The Publisher apologizes for any inconvenience this may cause. The full Elsevier Policy on Article Withdrawal can be found at http://www.elsevier.com/locate/withdrawalpolicy .

Innovative subsea configurations for the development of long gas-condensate subsea tie-backs

Several subsea tie-backs to the shore of gas-condensate fields operate today (Ormen Lange, Snohvit), but they are associated to large reserves and suffer from several weaknesses: the sensitivity to liquid accumulation in the lines, which can lead to an early shutdown of production, in particular in case of water breakthrough; and, the disadvantage of continuous injection of hydrate inhibitors, generally MEG, supplied from shore by a dedicated line. Saipem has recently performed several studies to evaluate the technical feasibility of cases with moderate to large reserves (1-10 Tcf), longer step-outs, and deeper waters, while optimising the recovery factor. There have been investigations of new subsea configurations combined with new operating philosophies, such as: conventional dual production lines, single lines, and subsea gas/liquid separation, possibly combined with subsea wet or dry gas compression. The work performed clearly shows, in some cases, the potential benefit of the subsea gas/liquid separation in reducing the liquid accumulation, leading to an increase of the recovery factor. This extended abstract presents the various solutions with their advantages, limitations, and drawbacks. The first part is dedicated to production considerations, such as the management of the liquid hold-up for low flowrates (end-of-life), turndown conditions, pigging, restart, and impact on the receiving terminal (slug catcher). The interest of using low-dosage hydrate inhibitors is also discussed. The second part focuses on pipeline design from the deepwater field to the shore, as well as on the installation constraints corresponding to the capabilities of the present installation vessels.

Inhibition of methane hydrate re-formation in offshore pipelines with a kinetic hydrate inhibitor

Methane gas from marine hydrate deposits can be produced by one or a combination of three methods; depressurization, thermal stimulation, and the injection of hydrate inhibitors. Because residual hydrate structures known as hydrate precursors will exist in the liquid water phase after dissociation, the risk of methane hydrate re-formation has to be evaluated during the production and transportation of methane gas through offshore pipelines. New experimental procedures composed of three stages are designed to simulate the dissociation of marine hydrates and the transportation of produced fluids. The obtained experimental results have shown that methane hydrates are rapidly re-formed when the temperature of dissociated water falls into the hydrate formation region during the cooling down process. The subcooling for three different dissociation pressures of 80, 70, and 60bar were 1.3, 1.2 and 1.6°C, respectively. One viable option to avoid hydrate re-formation is injecting hydrate inhibitors before transporting the fluids through pipelines. Among various hydrate inhibitors, Poly(N-vinylcaprolactam) (PVCap) was selected as a possible candidate for a Kinetic Hydrate Inhibitor (KHI) and injected into dissociated water before cooling down the fluids. The concentration of PVCap was varied from 0.5 to 3.0wt.%. With an increase in the PVCap concentration, the subcooling increased to 7.8°C at a dissociation pressure of 80bar, which suggests that the risk of hydrate re-formation can be reduced by injecting PVCap. Moreover it is observed that the subcooling increased to 8.8°C at the PVCap concentration of 3.0wt.% in the presence of NaCl in the water phase. Although the use of KHI in conventional gas production has become common, its applicability to methane hydrate production has not yet been studied thoroughly, especially in the presence of residual hydrate structures. In this work, the application of KHI to methane hydrate production is discussed.

Water detection in gas/condensate flows by SeCaP technology

Safe and controlled operation of subsea gas/condensate flow lines depends on adequate monitoring capabilities of free water in the well stream. Accurate knowledge on the amount of water present directly determines the requirement for hydrate inhibitor injection. Free water originates from two sources; condensed water from the produced gas phase and the possible amount of formation water from the reservoir. The gas production should ideally be single phase from the reservoir, but as the temperature and the pressure are reduced in the well and flow line, both a liquid hydrocarbon phase and water will condense from the gas. Normally there is less water than condensate present, and the water cut can be lower than 10%. This means that the water often is dispersed as droplets in the condensate phase due to high velocities. The paper presents tests on a 3” Sentech WCM (WaterCutMeter), based on the Single Electrode Capacitance Probe (SeCaP) technology. These experiments were conducted at 78 bar and 0 °C in the Norsk Hydro multiphase flow loop in Porsgrunn, with the primary objective to see if this instrument was able to detect the small changes in the amount of water present at such realistic operating conditions. The results show that the SeCaP WCM was able to detect changes in water content smaller than 0.01 vol%, but the meter needs a thorough temperature correction as the signal is strongly influenced by temperature changes.