Hydrate Free Zone Research Articles

Microbial communities associated with thermogenic gas hydrate-bearing marine sediments in Qiongdongnan Basin, South China Sea

Biogenic and thermogenic gas are two major contributors to gas hydrate formation. Methane hydrates from both origins may have critical impacts on the ecological properties of marine sediments. However, research on microbial diversity in thermogenic hydrate-containing sediments is limited. This study examined the prokaryotic diversity and distributions along a sediment core with a vertical distribution of thermogenic gas hydrates with different occurrences obtained from the Qiongdongnan Basin by Illumina sequencing of 16S rRNA genes as well as molecular and geochemical techniques. Here, we show that gas hydrate occurrence has substantial impacts on both microbial diversity and community composition. Compared to the hydrate-free zone, distinct microbiomes with significantly higher abundance and lower diversity were observed within the gas hydrate-containing layers. Gammaproteobacteria and Actinobacterota dominated the bacterial taxa in all collected samples, while archaeal communities shifted sharply along the vertical profile of sediment layers. A notable stratified distribution of anaerobic methanotrophs shaped by both geophysical and geochemical parameters was also determined. In addition, the hydrate-free zone hosted a large number of rare taxa that might perform a fermentative breakdown of proteins in the deep biosphere and probably respond to the hydrate formation.

Water content measurements for liquid propane in equilibrium with water or hydrates: New measurements & evaluation of literature data

Propane is utilised primarily for industrial sector and domestic applications. However, propane is considered a hydrate former. Thus, it is necessary to establish pressure and temperature conditions that ensure a hydrate-free zone. This requires determining the minimum amount of water required for the formation of hydrates and providing a thermodynamic model capable of determining the water content and predicting pressure and temperature conditions for hydrate dissociation. Consequently this study investigated the water content of liquid propane in equilibrium with liquid water or hydrates at pressures up to 8.274 MPa and temperatures between 211.15 K and 313.15 K. Using three different methods: a quartz crystal microbalance (QCM), a silicon oxide-based hygrometer and the new method developed by Burgass et al. (2021). In general, water content measurements determined from the new method and QCM were found to be in good agreement. The fluid phase behaviour of the system (propane + water) was modelled using the simplified Cubic-Plus-Association (sCPA-SRK) and the Soave-Redlich-Kwong (SRK) equation of state combined with the van der Waals classical and non-density-dependent (NDD) mixing rules, respectively. Both models provided similar results, although the sCPA-SRK model used only one adjustable parameter in contrast with the SRK model, which used three adjustable parameters. The experimental measurements from the new method and QCM to the sCPA-SRK and SRK-NDD models presented 4.5% and 4.5% deviation, respectively over temperature range of 276.15–313.15 K. In all cases, the hydrate-forming conditions were modelled using the van der Waals and Platteeuw's solid solution theory. Additionally, the sCPA-SRK + van der Waals and Platteeuw model calculations were compared against hydrate dissociation conditions, using used two adjustable Kihara parameters and showed overall good agreement when compared to data from the literature.

The Effects of the Length and Conductivity of Artificial Fracture on Gas Production from a Class 3 Hydrate Reservoir

Natural gas hydrate is considered as a potential energy resource. To develop technologies for the exploitation of natural gas hydrate, several field gas production tests have been carried out in permafrost and continental slope sediments. However, the gas production rates in these tests were still limited, and the low permeability of the hydrate-bearing sediments is identified as one of the crucial factors. Artificial fracturing is proposed to promote gas production rate by improving reservoir permeability. In this research, numerical studies about the effect of fracture length and fluid conductivity on production performance were carried out on an artificially fractured Class 3 hydrate reservoir (where the single hydrate zone is surrounded by an overlaying and underlying hydrate-free zone), in which the equivalent conductivity method was applied to depict the artificial fracture. The results show that artificial fracture can enhance gas production by offering an extra fluid flow channel for the migration of gas released from hydrate dissociation. The effect of fracture length on production is closely related to the time frame of production, and gas production improvement by enlarging the fracture length is observed after a certain production duration. Through the production process, secondary hydrate formation is absent in the fracture, and the high conductivity in the fracture is maintained. The results indicate that the increase in fracture conductivity has a limited effect on enhancing gas production.

Hydrate mitigation for subsea production multiphase pipeline by flow assurance approach

Nowadays, gas and oil production through subsea pipeline are moving to deeper developments. It affects pressure and temperature conditions decrease within hydrate stability region. The composition of fluid, including mixed produced water, liquid, and gas also affects the formation of hydrate inside pipeline. It is potentially leads to serious operational and safety problems. The aim of this study is to predict the hydrate free zone in multiphase fluid, chemical inhibitor, and insulation designed for subsea production pipeline by flow assurance approach. This study was conduct using steady state multiphase simulation to build a model for predicting the hydrate free zone and build the sensitivity of chemical inhibitor and thermal insulation for optimizing the hydrate free zone. Data used for this study are gas rate, fluid composition includes 10% bbl/bbl water, pipeline data, and chemical hydrate inhibitors include Methanol, Monoethylene Glycol (MEG), Triethylene Glycol (TEG). This study yield sensitivity of gas flow rate, the composition of hydrate inhibitor, the effect of insulation thickness to shifting hydrate free zone. This study can be concluded that variation of gas rate could be more effective depends on fluid composition and injection of methanol inhibitor is the most effective methods to mitigate the hydrate formation.

Comparison and application of different empirical correlations for estimating the hydrate safety margin of oil-based drilling fluids containing ethylene glycol

Abstract As the oil and gas industries continue to increase their activity in deep water, gas hydrate hazards will become more serious and challenging, both at present and in the future. Accurate predictions of the hydrate-free zone and the suitable addition of salts and/or alcohols in preparing drilling fluids are particularly important both in preventing hydrate problems and decreasing the cost of drilling operations. In this paper, we compared several empirical correlations commonly used to estimate the hydrate inhibition effect of aqueous organic and electrolyte solutions using experiments with ethylene glycol (EG) as a hydrate inhibitor. The results show that the Najibi et al. correlation (for single and mixed thermodynamic inhibitors) and the Ostergaard et al. empirical correlation (for single thermodynamic inhibitors) are suitable for estimating the hydrate safety margin of oil-based drilling fluids (OBDFs) in the presence of thermodynamic hydrate inhibitors. According to the two correlations, the OBDF, composed of 1.6 L vaporizing oil, 2% emulsifying agent, 1% organobentonite, 0.5% SP-1, 1% LP-1, 10% water and 40% EG, can be safely used at a water depth of up to 1900 m. However, for more accurate predictions for drilling fluids, the effects of the solid phase, especially bentonite, on hydrate inhibition need to be considered and included in the application of these two empirical correlations.

Key Factors for Depressurization-Induced Gas Production from Oceanic Methane Hydrates

Oceanic methane hydrate (MH) deposits have been found at high saturations within reservoir-quality sands in the Eastern Nankai Trough and the Gulf of Mexico. This study investigates the key factors for the success of depressurization-induced gas production from such oceanic MH deposits. A numerical simulator (MH21-HYDRES: MH21 Hydrate Reservoir Simulator) was used to study the performance of gas production from MH deposits. We calculated the hydrate dissociation behavior and gas/water production performance during depressurization for a hypothetical MH well. Simulation runs were conducted under various initial reservoir conditions of MH saturation, temperature, and absolute permeability. A productivity function (PF) was introduced as an indicator of gas productivity, which is a function of gas production rate, water production rate, and discount rate. The simulations showed that recovery factors over 36% and maximum gas production rates over 450 000 Sm3/d were expected for the most suitable conditions of a class 3 deposit (i.e., an isolated MH deposit that is not in contact with any hydrate-free zone of mobile fluids). However, gas productivity was affected by formation temperature and initial effective permeability. The values of PF increased with increasing formation temperature when the initial permeability of the deposit was higher than a threshold value (the threshold permeability); however, it decreased for the deposit below the threshold permeability. The threshold permeability was estimated to be between 1 and 10 mD in the class 3 deposit. These results suggest that key factors for the success of depressurization-induced gas production from oceanic MH are as follows: (1) The initial effective permeability of the MH deposit is higher than the threshold value, and (2) the temperature of the MH deposit is as high as possible.

Geomechanical response of permafrost-associated hydrate deposits to depressurization-induced gas production

In this simulation study, we analyzed the geomechanical response during depressurization production from two known hydrate-bearing permafrost deposits: the Mallik (Northwest Territories, Canada) deposit and Mount Elbert (Alaska, USA) deposit. Gas was produced from these deposits at constant pressure using horizontal wells placed at the top of a hydrate layer (HL), located at a depth of about 900 m at the Mallik site and 600 m at the Mount Elbert site. The simulation results show that general thermodynamic and geomechanical responses are similar for the two sites, but with substantially higher production and more intensive geomechanical responses at the deeper Mallik deposit. The depressurization-induced dissociation begins at the well bore and then spreads laterally, mainly along the top of the HL. The depressurization results in an increased shear stress within the body of the receding hydrate and causes a vertical compaction of the reservoir. However, its effects are partially mitigated by the relatively stiff permafrost overburden, and compaction of the HL is limited to less than 0.4%. The increased shear stress may lead to shear failure in the hydrate-free zone bounded by the HL overburden and the downward-receding upper dissociation interface. This zone undergoes complete hydrate dissociation, and the cohesive strength of the sediment is low. We determined that the likelihood of shear failure depends on the initial stress state as well as on the geomechanical properties of the reservoir. The Poisson's ratio of the hydrate-bearing formation is a particularly important parameter that determines whether the evolution of the reservoir stresses will increase or decrease the likelihood of shear failure.

Hydrate phase equilibria of a near critical fluid: Effect of inhibition and separation

AbstractThe hydrate phase boundary of a near critical fluid (NCF) was measured at 275–289 K in the presence of distilled water, synthetic formation water, and synthetic formation water with 10.41 wt. % methanol. The results agreed well with the predictions of an in‐house model, based on a cubic equation of state and statistical thermodynamics. To simulate a typical oil/gas production scenario, the NCF was flashed at 298.1 K and 17.189 MPa, and the resulting liquid was subsequently flashed at 298.0 K and 4.089 MPa. Hydrate free zones of the resulting liquid fractions were measured to investigate the physical separation effect on the hydrate phase boundary. The in‐house thermodynamic model was used to simulate the separators conditions and to predict the hydrate free zone of the resulting liquid and the vapor fractions. The predictions agreed closely with the experimental data, demonstrating reliability of the thermodynamic model. The results also showed that the hydrate phase boundaries of the vapor and liquid phases, which resulted from physical separation, are similar to that of the NCF.

Hydrate Equilibrium Data of Multicomponent Systems in the Presence of Structure-II and Structure-H Heavy Hydrate Formers

The effect of six newly discovered heavy hydrate-forming compounds on the hydrate phase boundary of a gas mixture, a natural gas, and a model oil has been measured. The study, which is a continuation of a previous work,1 investigates the effect of cyclopentane, cyclohexane, neopentane, isopentane, methylcyclopentane, and methylcyclohexane at various concentrations. The first three compounds form structure-II hydrates, while the last three compounds are known to promote structure-H hydrates. The experimental hydrate dissociation data have been successfully predicted by the use of a thermodynamic model. The results show that structure-II is the stable hydrate structure for the systems investigated at various heavy hydrate former concentrations (from 0.27 mol % to 59.66 mol %). Also, the structure-II heavy hydrate formers promoted structure-II hydrate formation whereas the structure-H heavy hydrate formers (at the concentrations used) did not change the stable hydrate structure to structure-H and hence inhibited hydrate formation in the above fluid systems. On the basis of the above study, it was concluded that the inclusion of structure-II heavy hydrate formers in the thermodynamic modeling would improve the reliability of hydrate-free zone predictions in real reservoir fluids.

A General Correlation for Predicting the Hydrate-Free Zone of Reservoir Fluids

Summary A new correlation for predicting the hydrate-free zone of reservoir fluids, from black oil to lean natural gas, has been developed. The method correlates the hydrate dissociation pressure against the specific gravity and the concentration of the hydrate-forming components in the fluid, as well as the temperature of the system. The effect of nitrogen and carbon dioxide on the hydrate-free zone has also been taken into account. The correlation has been developed using hydrate phase boundaries for 31 fluids generated by a well-proven comprehensive thermodynamic model. Hydrate phase boundaries for 13 independent reservoir fluids calculated by the new correlation and the thermodynamic model have been compared, showing a maximum error of 1.0 K in the calculated potential hydrate-forming temperature.

Gas Hydrates and Offshore Drilling: Predicting the Hydrate Free Zone

Abstract: A well‐recognized hazard in offshore drilling is the formation of gas hydrates in the event of a hydrocarbon flow into the well bore from the reservoir (e.g., a kick). This could potentially block the BOP stack, kill lines and chokes, obstruct the movement of the drill string, and cause serious operational and safety concerns. Currently, salts are added to the drilling fluids to inhibit hydrate formation in offshore and arctic drilling. For deep water drilling, even saturated saline solutions may not provide the required protection, unless combined with chemical inhibitors. The reported experimental data on gas hydrate formation in drilling fluids are very limited and in some cases inconsistent. The available predictive methods are generally empirical correlations based on limited data and with limited application. In this presentation, a thermodynamic model capable of predicting the hydrate free zone in the presence of salts (NaCl, KCl, CaCl2, NaBr, Na‐formate, etc.) and chemical inhibitors (methanol, ethanol, ethylene glycol, glycerol, etc.) is presented. The model developed has been employed to predict the hydrate free zone in drilling fluids designed for offshore and deep water applications. The predictions are compared with experimental data and an empirical correlation, demonstrating the reliability of the thermodynamic model.

Equilibrium data and thermodynamic modelling of cyclopentane and neopentane hydrates

Cyclopentane and neopentane have only recently been recognised as a potential hydrate former, forming structure-II gas hydrates. However, no information on their hydrate phase boundary or modelling has yet been reported. In this paper, experimental hydrate dissociation data for cyclopentane and neopentane in their binaries and ternaries with methane or/and nitrogen (i.e., methane/cyclopentane, nitrogen/cyclopentane, methane/nitrogen/cyclopentane, methane/neopentane, nitrogen/neopentane, and methane/nitrogen/neopentane) over a wide range of temperature (282–301 K and 276–293 K, respectively) have been reported. The results of comparison with other newly discovered hydrate forming compounds showed that cyclopentane is the strongest hydrate promoter with neopentane in the second place. The predicted hydrate free zone is in good agreement with the experimental data, demonstrating the success of modelling.

Hydrate-free zone for synthetic and real reservoir fluids in the presence of saline water

The application of extended-reach subsea gathering networks and transportation of unprocessed wellstreams are serious considerations for reducing field development costs. These lines will convey a mixture of gaseous and/or liquid hydrocarbons, condensed or saline water. A good knowledge of the hydrate phase boundary for the above systems is essential in the confident and economical design and operation of associated fields, pipelines and processing facilities. In this paper, experimental data for the hydrate-free zone of several pure and multicomponent systems in the presence of single and mixed electrolyte solutions are presented. The paper, which is a continuation of three previous communications, presents data on C 2, C 3, CO 2, two synthetic multicomponent gas mixtures, and a black oil sample. The comparison of results with recent literature data shows some discrepancy at high salt concentrations, where a possible source of error is identified. An in-house numerical model has been used for predicting the experimental data with good results.

Vapor−Hydrate Equilibrium Ratio Charts for Heavy Hydrocarbon Compounds. 1. Structure-II Hydrates: Benzene, Cyclopentane, Cyclohexane, and Neopentane

The most successful empirical method for predicting hydrate-phase equilibrium in water−hydrocarbon system is based upon vapor−solid equilibrium ratio (Kvs values) correlations. Equilibrium ratio charts for known hydrate formers, with n-butane as the heaviest compound, are available in the literature. With the discovery of heavier hydrate-forming compounds, their equilibrium ratio charts are required for reliable prediction of the hydrate-free zone of hydrocarbon mixtures, particularly reservoir fluids. In this work, an in-house thermodynamic model, validated against experimental hydrate equilibrium data of four structure-II heavy hydrate formers (HHF), benzene, cyclopentane, cyclohexane, and neopentane, has been used for generating their Kvs value charts. The resulting Kvs values have been used in predicting a hydrate-free zone of binary and ternary mixtures of HHF with methane and/or nitrogen, demonstrating success when compared with experimental data.

Measurement and Prediction of Hydrate-Phase Equilibria for Reservoir Fluids

Summary Problems associated with gas hydrates in the production and transportation of unprocessed wellstreams can be avoided by either preventing hydrate formation or allowing the formation of hydrates, but preventing their aggregation, and transporting them as slurry. The first approach, which is the current practice in the industry, can be made more cost effective by determining the hydrate-phase boundary more reliably. For the second approach, it is necessary to determine the amount of hydrates to be transported as slurry. This paper reviews the effect of electrolyte solutions and heavy hydrate formers (such as benzene, cyclohexane, and methylcyclopentane) on the hydrate-free zone and discusses new methods and equipment for measuring the amount and composition of different phases in hydrate-forming conditions. An in-house numerical model has been successfully employed for prediction of the hydrate-free zone and the compositional data.