Hydrate Plug Research Articles

Hydration of natural gas hydrogen mixture test equipment

The use of hydrogen as an energy source is advantageous because its combustion processes only produce water vapor, but not carbon dioxide. This excess energy can be stored in underground gas storage facilities, where it is delivered mixed with natural gas. In gas- and oil industry the formation of hydrate crystals can cause significant damages. A huge amount of hydrate crystal is formed, it can cause hydrate plugs in the pipeline. Like natural gas, hydrate formation occurs in the case of a natural gas-hydrogen mixture. The paper presents a method which can be used to study hydrate formation in natural gas-hydrogen mixture.

Simulation of Hydrate Plug Prevention in Natural Gas Pipeline from Bohai Bay to Onshore Facilities in China

Simulation of Hydrate Plug Prevention in Natural Gas Pipeline from Bohai Bay to Onshore Facilities in China

Research on Prediction Methods of Wellbore Hydrate Formation of Ultra-Deep Gas Wells in Northwest Sichuan

According to the formation and handling situation of hydrate in ultra-deep high-pressure sulfurcontaining gas wells in northwest Sichuan, the formation conditions of natural gas hydrate was studied based on previous studies on hydrate, the molecular dynamics of natural gas hydrate and the multiphase flow law of high-temperature high-pressure high-sulfur-containing gas wellbore were combined, and the pressure prediction model with high-temperature high-pressure sulfur-containing gas wells as the target was built. The chemical and physical control methods of wellbore hydrate plugging were discussed to provide the scientific theoretical basis for the prediction and control of hydrate in high-temperature high-pressure high-sulfurcontaining gas wells.

Hydrate bedding modeling in oil-dominated systems

The rapid formation of gas hydrates is one of the major concerns in offshore oil and gas transportation due to the possible plugging of unmanaged hydrate agglomerates. Within the oil and gas industry, hydrate management guidelines have shifted over the last decade from hydrate avoidance to hydrate management. Allowing hydrate formation in pipelines without blockages requires understanding of the hydrate formation and plugging mechanisms under different operational conditions. Furthermore, a predictive tool which can be coupled with the multiphase flow conditions encountered in the field is highly desired in order to ensure successful transportation of hydrate slurries.In the realm of modeling, one such hydrate plugging mechanism that remains unaddressed is the bedding of hydrate particles, which may occur when hydrate particles aggregate within the pipeline. In this work, a bedding model based on force balances has been developed and coupled with a transient multiphase flow simulator. It is proposed that agglomeration controls bedding and bedding is a function of the agglomerate size, which is assumed to follow a log-normal distribution based on an autoclave experimental study. The bedding model has been tested and validated against large-scale flowloop experiments at different water cuts and liquid velocities. Pressure drop comparison between the simulations and experiments shows an improvement after implementing the bedding model for simulations with low liquid velocity. This work may contribute to the understanding of the hydrate plugging mechanisms and be applied to optimize hydrate management guidelines in offshore oil and gas production.

Temperature Field in a Material Containing Asphalt-Resin-Paraffin Substances in a Microwave Electromagnetic Field

The relevance of the study is due to the need to develop technological and technical solutions of protecting from paraffin and gas hydrate plugs within the pipelines formed under particular thermohydrodynamic conditions. In this regard, this article is aimed at disclosing the features of heating and melting of such plugs using a super-high-frequency electromagnetic radiation source moving within the pipeline. A theoretical study of temperature change within the “pipeline – plug – environment” system, which allows us to fully consider its interaction with the electromagnetic radiation, is the leading method for studying this problem. A mathematical model has been presented and a theoretical study of the plug electromagnetic heating process for heat exchange on the pipe outer surface according to Newton’s law on the hypothesis that the EM transmitter of Н11 type moves, and the achievement of a complicated configuration of thermal sources and temperature has been disclosed in the article. The materials of the article are of practical value for establishing the initial indices of the paraffin plugs removal technology in a pipeline and oil well when exposed to electromagnetic radiation.

Ai Based Detection of Gas Hydrate Formation in the Field

During the production of natural gas one of the major problems is the formation of hydrate crystals in the pipeline. The forming hydrate crystals can form hydrate plugs in the pipeline. The hydrate plugs lengthen production outages and result in financial losses for the producer, because the removal of the plugs is a time consuming procedure. One of the solutions used to prevent hydrate formation is the injection of modern compositions to the gas flow. The modern compositions help to dehydrate the gas, thus, the size of hydrate crystals does not increase. The substances, used in low concentrations, have to be locally injected, at the gas well sites. Inhibitor dosing depends on the amount of gas hydrate present. In the article a neural network based predictive detection solution is presented, which uses four factors.

Reduction Clathrate Hydrates Growth Rates and Adhesion Forces on Surfaces of Inorganic or Polymer Coatings

Hydrate plugging is one of the major risks for oil and gas transportation in pipelines. To mitigate the adhesion between hydrate particles and pipeline walls, hexagonal boron nitride (HBN), polydim...

In situ PXRD analysis on the kinetic effect of PVP-K90 and PVCap on methane hydrate dissociation below ice point

Kinetic hydrate inhibitors (KHIs) have been developed as an alternative for the prevention of hydrate plug in natural gas transportations due to economic and environmental factors. To understand the kinetic performance of KHIs comprehensively, dissociations of CH4 hydrates in the presence of PVP-K90 and PVCap were investigated below ice point. Cryo-SEM and in situ PXRD were used to provide a microscopic insight on the dissociation kinetics. Results showed that a typical CH4 hydrate dissociation at 268 K could be divided into 4 stages. The self-preservation effect took place in the second stage accompanied with an rise in the ratio of Ih(002) to Ih(100) peaks from 0.5 to 1.1. About 30% of CH4 hydrates were suggested to dissociate into plate-like ice to form ice coatings on hydrate surface. In the presence of PVP-K90 or PVCap, the self-preservation stage reduced greatly and the initial dissociation rates of CH4 hydrates were found enhanced as the concentrations of the KHIs increased from 0.5 to 2.0 wt%. SEM images revealed that PVP-K90 was suggested to be included in the small ice crystals embedded in hydrate phase and hinder the connections of the plate-like ice crystals on hydrate surface, while PVCap was found to induce a dendritic growth of CH4 hydrate, leading to a surge in the specific surface area of CH4 hydrates which was not beneficial to the formation of ice coatings on hydrate phase. Therefore, both PVP-K90 and PVCap promoted hydrate dissociation below ice point by inhibiting the formation of self-preservation effect.

Research progress on hydrate plugging in multiphase mixed rich-liquid transportation pipelines

The plugging mechanism of multiphase mixed rich-liquid transportation in submarine pipeline is a prerequisite for maintaining the fluid flow in the pipeline and ensuring safe fluid flow. This paper introduced the common experimental devices used to study multiphase flow, and summarized the plugging progress and mechanism in the liquid-rich system. Besides, it divided the rich-liquid phase system into an oil-based system, a partially dispersed system, and a water-based system according to the different water cuts, and discussed the mechanism of hydrate plugging. Moreover, it summarized the mechanism and the use of anti-agglomerates in different systems. Furthermore, it proposed some suggestions for future research on hydrate plugging. First, in the oil-based system, the effect factors of hydrates are combined with the mechanical properties of hydrate deposit layer, and the hydrate plugging mechanism models at inclined and elbow pipes should be established. Second, the mechanism of oil-water emulsion breaking in partially dispersed system and the reason for the migration of the oil-water interface should be analyzed, and the property of the free water layer on the hydrate plugging process should be quantified. Third, a complete model of the effect of the synergy of liquid bridge force and van der Waals force in the water-based system on the hydrate particle coalescence frequency model is needed, and the coalescence frequency model should be summarized. Next, the dynamic analysis of a multiphase mixed rich-liquid transportation pipeline should be coupled with the process of hydrate coalescence, deposition, and blockage decomposition. Finally, the effects of anti-agglomerates on the morphological evolution of hydrate under different systems and pipeline plugging conditions in different media should be further explored.

Hydrate Plugging and Flow Remediation during CO2 Injection in Sediments

Successful geological sequestration of carbon depends strongly on reservoir seal integrity and storage capacity, including CO2 injection efficiency. Formation of solid hydrates in the near-wellbore area during CO2 injection can cause permeability impairment and, eventually, injectivity loss. In this study, flow remediation in hydrate-plugged sandstone was assessed as function of hydrate morphology and saturation. CO2 and CH4 hydrates formed consistently at elevated pressures and low temperatures, reflecting gas-invaded zones containing residual brine near the injection well. Flow remediation by methanol injection benefited from miscibility with water; the methanol solution contacted and dissociated CO2 hydrates via liquid water channels. Injection of N2 gas did not result in flow remediation of non-porous CO2 and CH4 hydrates, likely due to insufficient gas permeability. In contrast, N2 as a thermodynamic inhibitor dissociated porous CH4 hydrates at lower hydrate saturations (<0.48 frac.). Core-scale thermal stimulation proved to be the most efficient remediation method for near-zero permeability conditions. However, once thermal stimulation ended and pure CO2 injection recommenced at hydrate-forming conditions, secondary hydrate formation occurred aggressively due to the memory effect. Field-specific remediation methods must be included in the well design to avoid key operational challenges during carbon injection and storage.

Flow-Assurance Strategy Manages Subsea Asset Without Continuous MEG Injection

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 195784, “A New Flow-Assurance Strategy for the Vega Asset: Managing Hydrate and Integrity Risks on a Long Multiphase Flowline of a Norwegian Subsea Asset,” by Stephan Hatscher, SPE, and Luis Ugueto, Wintershall Norge, prepared for the 2019 SPE Offshore Europe Conference and Exhibition, Aberdeen, 3-6 September. The paper has not been peer reviewed. The Vega field on the Norwegian Continental Shelf has been producing successfully using continuous monoethylene glycol (MEG) injection, topped with means of corrosion inhibition. A topside reclamation process allows reuse of MEG but limits the possibilities of producing saline water. The complete paper presents a discussion of a feasibility study of a new flow-assurance and -integrity philosophy to manage wells without continuous MEG injection. The paper describes options for hydrate and integrity management and the required modifications to both subsea and topside facilities to enable an operational philosophy change. Current Subsea Flow-Assurance Approaches Gas-hydrate formation in wet gas flowlines is considered one of the primary challenges seen in subsea assets. Its mitigation requires considerable capital expense and often significant operating expense (OPEX) over field life. Although the thermodynamic stability of the ice-like structures is well understood, the same is not the case for the kinetics of their formation or the dispersion in multiphase systems, which might be a crucial aspect in hydrate plug formation. Traditionally, the approach to hydrate mitigation has been to keep the system outside the hydrate-formation region by various means, including the following: Insulation of flowlines or direct heating possibilities Depressurization on shutdown Hydrate inhibition by thermodynamic or low-dosage hydrate inhibitors Subsea separation and drying of gas For long multiphase flowlines, options are limited. Insulation or direct heating often is uneconomical. Depressurization on shutdown requires significant storage space on a host facility for liquids and leads to massive volumes of flared gas. Subsea separation and gas drying are not yet fully mature, so use of hydrate inhibitors is common. Hydrate inhibitors can be classified as either thermodynamic or kinetic inhibitors. The latter are also called low-dosage hydrate inhibitors (LDHI) because of the lower concentration required. The main advantage of thermodynamic inhibitors is that they shift the hydrate curve to fully protect the system, whereas the kinetic inhibitors tend to wear off after time, leaving the systems un- or underprotected. However, their use often allows for infrastructure reduction and simplified production operations. The most typical thermodynamic inhibitors are based on salts (as from the formation water) or alcohols such as methanol, ethanol, or glycols. The advantage of the latter is that their separation from water is technically viable, so they can be used in a recycle, or closed-loop, system, which can only function well in systems free of salinity or with limited saline formation water ingress.

Hydrate management in deadlegs: Effect of driving force on hydrate deposition

In oil and gas pipeline networks, deadlegs are sections of process pipes equipped for providing maintenance services. As they are gas-filled with stagnant water saturated gas, gas hydrates are often deposited on the pipe wall and grow into a hydrate plug, which causes severe safety risks and flow assurance problems. One strategy for hydrate mitigation is to apply external heating to the pipe wall to lower the driving force for hydrate formation. Here, we studied how hydrate deposition under water saturated gas is affected by the driving force (temperature gradient) with a 1-in. vertical pipe system. Pipe wall temperatures are varied from −10 to 15 °C, corresponding to 29 to 4 °C subcooling temperatures using a gas mixture of methane/ethane (74.2/25.8 mol%) at 100 bar. Pipe wall temperature is found to affect the temperature gradient in the pipe, and this greatly alters the hydrate kinetics. At high driving forces, most of the water droplets condensed on the pipe wall readily convert into dry hydrate deposits, which are confirmed by dielectric constant responses from a permittivity probe and visual inspection of surface morphologies. As the driving force becomes lowered, some free water remains on the wall, resulting in wet hydrate deposits due to reduced hydrate kinetics. When increasing the pipe wall temperature from −10 to 10 °C, the plug time increases from 35 to 500 h. These results demonstrate that control of the driving force is a promising strategy for hydrate management in deadlegs.

Annelida, a Robot for Removing Hydrate and Paraffin Plugs in Offshore Flexible Lines: Development and Experimental Trials

Summary Methane hydrates and paraffin plugs on flexible lines are concerns in offshore production. They may stop wells for months, causing high financial losses. Sometimes, operators use depressurization techniques for hydrate removal. Another strategy is using coiled tubing or a similar unit to perform local heating or solvent injection. However, frequently these strategies are not successful. In those cases, a rig may perform the operation, or the line may be lost. We developed a robotic system to perform controlled local heating and remove obstructions. The system developed can access the line from the production platform. It uses a self-locking system to exert high traction forces. An umbilical with neutral buoyancy and low friction coefficient allows significant friction reduction. It allows moving upward and in pipes with a large number of curves. Coiled tubing and similar units cannot do that. Carbon fiber vessels and compact circuits give the flexibility to move inside 4-in. flexible pipes. In addition, a novel theoretical model allows the cable traction calculation using an evolution of the Euler-Eytelwein equation. Experimental tests validated this model using curved pipes, both empty and filled with fluid, and using different loads. Experimental tests also confirmed the external layer traction resistance. Furthermore, the carbon fiber vessels were pressure tested, indicating a collapse resistance of 57 MPa (8,300 psi). Besides, exhaustive tests of the onboard electronics and the surface control system guarantee the communication reliability. In addition, a theoretical model allowed the design of the 25 kN (5.6 kip) traction system considering the self-locking system, the contact with the wall, and a diameter range. Four prototypes allowed us to compare hydraulic and electric drive systems, validate the self-locking mechanism up to its limit, analyze the hydraulic system for leg opening and translation, and prove the traction capacity. Finally, a theoretical model allowed the local heating system and the temperature to increase. The experimental validation of the system on a cooled environment demonstrated its ability to increase temperature. Further, it allowed the obstruction removal in a controlled manner, avoiding damage to the polymeric layer of the flexible line.

Mechanical analysis of coiled tubing in the process of hydrate and wax plugs removal in subsea pipelines

ABSTRACT Hydrate formation and wax deposition in submarine pipelines hinder the transportation of oil and gas. Pigging operation is an important means to ensure pipeline flow assurance. In this paper, the idea of coiled tubing (CT) intervening in hydrate and wax removal of underwater pipeline is put forward, and the feasibility of this method is discussed from the point of view of the ultimate extension capacity of coiled tubing. To this end, theoretical analyses and experimental tests are performed on the mechanical behaviour of coiled tubing in submarine pipelines. The present paper mainly analyses the axial force transfer characteristic of coiled tubing with different sizes and the contact force coefficient values of coiled tubing with fixed and loaded end conditions under different boundary conditions. Besides, the effects of CT size and friction coefficient on the reachable depth of hydrate or wax plugs removal are also studied and the obtained maximum depth of the CT inlet is compared with the total length of the five-segment centreline of the South China Sea submarine pipelines. The results show that CT can further achieve more plug removal as the reduction of friction coefficient, while the depth of plug removal reduces with the decrease of CT size. CTs only with limited sizes can be used to complete the plug removal process in submarine pipelines.

Real-Time Estimation and Management of Hydrate Plugging Risk During Deepwater Gas Well Testing

Summary Hydrate formation and deposition are usually encountered during deepwater gas well testing, and if hydrates are not detected and managed in time, a plugging accident can easily occur. In this study, we demonstrate a method for estimating and managing the risk of hydrate plugging in real time during the testing process. The method includes the following steps: predicting the hydrate stability region, calculating the hydrate formation and deposition behaviors, analyzing the effect of the hydrate behaviors on variations in wellhead pressure, monitoring the variations in wellhead pressure and estimating the hydrate plugging risk in real time, and managing the risk in real time. An improved pressure-drop calculation model is established to calculate the pressure drop in annular flows with hydrate behaviors, and it considers the dynamic effect of hydrate behavior on fluid flow and surface roughness. The pressure drops calculated at different times agree well with experimental and field data. A case study is conducted to investigate the applicability of the proposed method, and results show that with the continued formation and deposition of hydrates, both the effective inner diameter of the tubing and the wellhead pressure decrease accordingly. When the wellhead pressure decreases to a critical safety value under a given gas production rate, a hydrate inhibitor must be injected into the tubing to reduce the severity of hydrate plugging. It is also necessary to conduct real-time monitoring of variations in wellhead pressure to guarantee that the risk of hydrate plugging is within a safe range. This method enables the real-time estimation and management of hydrate plugging during the testing process, and it can provide a basis for the safe and efficient testing of deepwater gas wells.

Hydrate management in deadlegs: Limiting hydrate deposition with physical restriction

In the oil/gas production and transportation systems, deadlegs are pipe sections filled with stagnant water saturated gas. Deadlegs are often uninsulated, resulting in cold pipe walls that can readily lead to the formation of gas hydrates. Hydrate deposits consequently can build up in the deadleg, and sometimes result in hydrate plug, which cause severe operational issues. In some instances, deadlegs are used for maintenance purposes, but they pose significant hydrate challenges at the same time. Establishing strategies for hydrate management in deadlegs is therefore important for economic and safety reasons. Here we applied a physical restriction to an 1-in. vertical pipe system at several different locations to verify that the restriction can limit hydrate deposition in water saturated gas. The motiviation of this study is that the presence of a physical restriction, which can also be called an orifice plate, can change water condensation and the following hydrate deposition phenomena. At a given header/pipe wall temperature condition, when the restriction is installed lower than the position where most hydrates are supposed to form, hydrate deposition is limited by changing the temperature profile in th pipe, and thus the water condensation and hydrate deposition. If the restriction is far enough from the header, it has negligible effect on hydrate deposition as the water vapor is sufficiently cooled down. The experimental results provide a demonstration that hydrate deposition in certain types of deadleg may be limited by applying a physical restriction (e.g. a valve) to the pipe or shortening the vertical pipe length.

Premelting-Induced Agglomeration of Hydrates: Theoretical Analysis and Modeling.

Resolving the long-standing problem of hydrate plugging in oil and gas pipelines has driven an intense quest for mechanisms behind the plug formation. However, existing theories of hydrate agglomeration have critical shortcomings, for example, they cannot describe nanometer-range capillary forces at hydrate surfaces that were recently observed by experiments. Here, we present a new model for hydrate agglomeration which includes premelting of hydrate surfaces. We treat the premelting layer on hydrate surfaces such as a thin liquid film on a substrate and propose a soft-sphere model of hydrate interactions. The new model describes the premelting-induced capillary force between a hydrate surface and a pipe wall or another hydrate. The calculated adhesive force between a hydrate sphere (R = 300 μm) and a solid surface varies from 0.3 mN on a hydrophilic surface (contact angle, θ = 0°) to 0.008 mN on a superhydrophobic surface (θ = 160°). The initial contact area is 4 orders of magnitude smaller than the cross-sectional area of the hydrate sphere and can expand with increasing contact time because of the consolidation of hydrate particles on the solid surface. Our model agrees with the available experimental results and can serve as a conceptual guidance for developing a chemical-free environmentally friendly method for prevention of hydrate plugs via surface coating of pipe surfaces.

Fundamental investigation of the adhesion strength between cyclopentane hydrate deposition and solid surface materials

Hydrate agglomerations and hydrate depositions are two main processes that form hydrate plugging in deep-water oil and gas pipelines. Hydrate that directly grows and sinters on the pipe wall is an important hydrate-deposition case, which has been rarely studied. Understanding the adhesion strength of the sintered hydrate depositions is crucial in advancing the management of hydrate formation to avoid plugging in pipelines. In this work, a multi-spray method was first applied to form a hydrate-deposition layer on a solid surface. Further, the adhesion strength was measured using a self-built adhesion-strength measurement apparatus. The effects of subcooling, formation time, surface roughness, and material types on the hydrate-adhesion strength were investigated. The water content in the deposition was found to decrease with the increase in the subcooling and formation time, which led to higher adhesion strength. The adhesion strength was also significantly influenced by the surface roughness and material types, and surfaces with low roughness and strong hydrophobicity (i.e., high contact angle) resulted in lower adhesion strength. After obtaining the adhesion force, a model was developed to evaluate the feasibility of sintered hydrate deposition on the pipe wall in gas and oil systems. The simulation results revealed that the critical velocity required to remove the deposition would increase and decrease with the length and thickness of the deposition, respectively. Compared with the settling-down hydrate particle on the pipe wall, the required critical removal velocity for sintered hydrate deposition was much higher, which was beyond most of the pipeline operating conditions.

Investigation on the Synergistic Effect of Tetra Butyl Phosphonium Bromide with Poly(N-isopropylacrylamide) Based Kinetic Hydrate Inhibitor

The problem of clathrate hydrate plugging in flow pipes has been the most important issue in the off-shore exploitation since hydrates were found in transport facilities. In recent years, low dosage hydrate inhibitors have attracted much interest among researchers in place of thermodynamic hydrate inhibitors such as methanol and mono ethylene glycol (MEG). Poly-vinyl caprolactam and poly-isopropylacrylamide (PNIPAM) are among the hydrate inhibitors that are typically used for polymers containing amide groups. Furthermore, various kinds of polymer inhibitors containing amide group including tetrabutylphosphonium bromide(TBPB), which is a quaternary salt, were synthesized and studied in a methane gas hydrate environment. In this experiment, the injection of 0.1 wt% inhibitor at 276 K and 5 MPa was followed by stirring the water to induce nucleation. From the result, when PNIPAM alone was used as a single KHI, PNIPAM exhibited worst performance among the KHIs tested in this study. But the mixing of TBPB with PNIPAM further extended the induction time and reduced the CH4 hydrate growth rate. The real-time in situ Raman system used to understand the inhibition principle was recorded during CH4 hydrate formation, as a result, PNIPAM showed that the large hydrate cage affected, while TBPB prevented the CH4 molecule from occupying the small cage. TBPB was excellent synergist in blends with PNIPAM for kinetic hydrate inhibition of structure I forming CH4 hydrate.

Toward a Robust, Universal Predictor of Gas Hydrate Equilibria by Means of a Deep Learning Regression.

Due to offshore reservoirs being developed in ever deeper and colder waters, gas hydrates are increasingly becoming a significant factor when considering the profitability of a reservoir due to flow disruptions, equipment, and safety hazards arising from the hydrate plug formation. Due to low-dosage hydrate inhibitors such as kinetic inhibitors competing with traditional thermodynamic inhibitors such as methanol, accurate information regarding the hydrate equilibrium conditions is required to determine the optimal hydrate control strategy. Existing thermodynamic models can prove inflexible regarding parameter adjustment and the incorporation of new data. Developing a multivariate regression model capable of generalizing hydrate equilibria over a wide range of conditions, with results competing with thermodynamic models is worthwhile. A multilayer perceptron neural network of three hidden layers has undergone supervised training means of a backpropagation to accurately predict uninhibited hydrate equilibrium pressure for a range of gas mixtures with nine input features, excluding hydrogen sulfide and electrolytes, from a dataset of 1209 equilibrium points, 670 of which are multicomponent gases, sampled in a rigorous data sampling campaign from existing experimental studies. Statistical significance of results has been emphasized, with models validated using 10-fold cross-validation and holdout validation, facilitating hyperparameter optimization without overfitting, while stratified holdout ensures testing a wide range of conditions. The developed model has proven to outperform two popular thermodynamic models. Various scoring metrics are used, with an average cross-validated R2 of 0.987 ± (0.003). An R2 of 0.993 and mean absolute percentage error of 5.56% are yielded for holdout validation. Auxiliary models are included to determine the multicomponent prediction capability and dependency on individual data sources. Multicomponent data prediction has proven successful; results prove that the model accurately generalizes hydrate equilibria and is well suited to predicting unseen data. Positive results are largely insensitive to exact model parameters, thus indicating a robust, replicable methodology.