Phase Equilibrium of Methane Hydrate in the Presence of Aqueous Solutions of Quaternary Ammonium Salts
Families of various quaternary ammonium salts (QAS) have been of great interest to gas hydrate based investigations. In this work, an attempt has been made to understand the effect of QAS of the bromide family with increasing alkyl chain length, such as tetra-methyl, tetra-ethyl, and tetra-butyl ammonium bromide (TMAB, TEAB, and TBAB) at two different concentrations (0.05 and 0.1 mass fraction) in an aqueous solution on the hydrate-liquid-vapor (H-L-V) phase equilibrium of the methane hydrate system. Various experiments were performed to capture phase equilibrium data in the equilibrium pressure range of 7.6-4.2 MPa and temperature range of 282.4-276.8 K. It has been observed that the addition of TMAB and TEAB shifts the phase equilibrium curve of methane hydrate to higher pressure and lower temperature conditions. TMAB and TEAB have shown thermodynamic inhibition unlike TBAB which has shown a promotion effect. The Clausius-Clapeyron equation is used to calculate the enthalpy of dissociation of methane hydrate in various QAS aqueous solutions to examine the effect of QAS on methane hydrate structural information. The electrical conductivity measurements were also made to correlate the hydrate inhibition effectiveness of QAS on methane hydrate system. In addition, a phase equilibrium model has been extended to predict the phase behavior of methane hydrate + (TMAB, TEAB, or TBAB) aqueous solutions for a total 91 experimental phase equilibrium data points obtained from this work and the literature. The absolute average relative deviation in equilibrium pressure (AARD/P (%)) observed from the proposed model with the experimental equilibrium pressure data produced in this work and from several sources in the literature have been observed to lie within ±3.2%, indicating the robustness of the model.
Polymer Flooding in Artificial Hydrate Bearing Sediments for Methane Gas Recovery
Polymer flooding has been one of the most promising methods used for enhanced oil recovery from matured crude oil reservoirs across the globe due to its distinct advantages over simple water flooding. However, the use of polymer flooding has not yet been investigated for methane recovery from hydrate reservoirs. In our earlier work, we have investigated the effect of various molecular weights and concentrations of polyethylene glycol (PEG) polymer on the phase stability and kinetics of methane hydrate. This information has been explored for successful use of PEG as a chemical agent for polymer flooding from hydrate reservoirs. In this work, detailed experimental investigations on methane production from hydrate bearing sediments have been carried out using PEG polymer flooding in a three-dimensional hydrate reactor. Initially, methane hydrate formation has been investigated using two silica sand porous beds (viz., 0.16 and 0.46 mm), and pure water at an initial hydrate formation pressure of 8 MPa and 277.15 K. Subsequently, hydrate dissociation studies have been carried out using polymer flooding at a final hydrate reservoir pressure of ∼4.3 MPa and 277.15 K. The effect of molecular weights (200 and 600 kg/kmol, viz., PEG-200 and PEG-600, respectively), concentrations (0.2 and 0.4 mass fractions), and injection rates (1 and 5 mL/min) of PEG aqueous solution has been analyzed for methane gas recovery. PEG-200 is observed to be an effective flooding agent as compared to PEG-600 and other inhibitor such as ethylene glycol used in the literature. In addition, studies on the total dissolved solids (TDS) and electrical conductivity of PEG aqueous solutions have also been investigated before and after flooding to check the efficacy of polymer flooding for methane production. PEG has a much lower freezing point (208.15 K, i.e., -65 °C) compared to ethylene glycol (260.25 K, i.e., -12.9 °C); therefore, polymer flooding is expected to be more beneficial for methane gas production from hydrate bearing zones with low reservoir temperatures.
Polymer-Assisted Chemical Inhibitor Flooding: A Novel Approach for Energy Recovery from Hydrate-Bearing Sediments
Recent production technologies to extract methane from mysterious hydrate reservoirs are not effective and need additional efforts to develop novel technologies to improve methane production. Chemical inhibitor injection is appraised as an effective method due to ease in operation, improved energy efficiency, and reduced threat of hydrate reformation. In the current study, several experiments on methane recovery have been performed in a simulated laboratory-based hydrate reservoir by injecting chemical inhibitors and combinations of aqueous chemical inhibitor/polymer systems. Different combinations of inhibitors and polymers, viz., chemical inhibitors such as methanol, ethylene glycol, methanol + polyacrylamide, and so forth, with varying concentrations, have been explored. Polyacrylamide has been used as in our previous study, it was shown that it can act as a better kinetic hydrate inhibitor, and also, the same polymer is often used for the enhanced oil recovery process in the upstream oil industry. In total, seven different simultaneous hydrate formation and dissociation experiments were performed. The inhibitor + polymer aqueous solution was injected to produce methane by dissociating the hydrate. The gas production ratio and the effectiveness of inhibitor aqueous solution and pure inhibitor in terms of methane recovery from hydrate-bearing sediments have been discussed and analyzed. This study provides a good insight into the use of some of the conventional hydrate inhibitors along with the oilfield polymer for methane recovery from hydrate-bearing sediments.
Performance evaluation of esters and graphene nanoparticles as an additives on the rheological and lubrication properties of water-based drilling mud
In the practice of drilling horizontal, directional, and unstable well profiles, the friction produced by bit balling, wellbore instability, cavings, and dog-legs resulted in excessive torque and drag. The friction along with high torque and drag, which results from the drill string, casing, and wellbore contact, leads to pipe stucks, overpulls during tripping-outs, and even closure of the oil and gas well. Heat generated from metal contact between casing and drill string is the cause of wear of drill string and casing. Oil-based drilling fluids are identified to produce minimum friction and torque than that of water-based drilling fluid/mud (WBM). However, the use of oil-based drilling fluids is becoming obsolete due to stringent environmental regulations. Therefore, it is critical to identify and design a water-based drilling mud with lubricant additives that are environmentally friendly, cost-effective, and give better lubrication similar to oil-based and synthetic-based drilling fluid. The objective of this study is to investigate the effect of two additives PC60 (the product of the reaction of glycerol + tall oil fatty acid) and graphene nanoparticles on the rheological and lubrication properties of water-based drilling fluid. All together total 14 drilling fluid samples have been prepared for the detailed analysis. Extensive experimental work has been done to study the effect of lubricant additives (PC60 and graphene nanoparticles) on the rheology and lubrication of various WBMs with different additive concentrations (1, 2, and 3% by volume) at 30, 60, and 90 °C. All samples were investigated for their rheology, viscoelastic behavior, and lubrication properties before and after hot rolling. The experimental data generated in this work have been successfully utilized to find various fitting parameter for the Bingham plastic rheological model, followed by a discussion on foaming tendency of the samples and effect of pH on the rheological stability of drilling fluid. Subsequently, a relationship between the coefficient of friction (in the presence of different lubricant additives in the mud) and rheological properties (plastic viscosity and yield point) of different drilling fluid samples have been proposed.
Investigations on the thermal and electrical conductivity of polyethylene glycol-based CuO and ZnO nanofluids
In this experimental work, three different types of nanofluids were evaluated for their stability using dynamic light scattering and particle morphological study using scanning electron microscopy. The nanofluids used in this study are zinc oxide (ZnO) nanoparticle in water and 5 wt% polyvinylpyrrolidone (PVP) as a dispersant, and ZnO with polyethylene glycol (PEG 600) and CuO with PEG 600 with 5 wt% PVP at different concentration of 0.1, 0.3 and 0.5 wt%. Thermal and electrical conductivities were determined by KD-2 Pro® and PC 700 Eutech®. The result shows better enhancement in the thermal and electrical conductivity in the ZnO+PVP+Water system, followed by the CuO+PVP+PEG and ZnO+PEG systems. The highest percentage enhancement in thermal conductivity found to be 35.5% of ZnO+ PVP+water systems. The thermal conductivity results were compared with a theoretical model and show good agreement with results predicted by the model. The proposed model of Nan et al. (1997) is based on a hypothesis regarding the physical mechanism in heat transfer for nanofluids. This study is expected to form the basis for the development of nanofluid-based technologies with PEG as the primary additive in the upstream oil and gas industry especially in gas hydrates and drilling technology.
Phase Equilibrium of Methane Hydrate in Aqueous Solutions of Polyacrylamide, Xanthan Gum, and Guar Gum
The use of water-soluble polymers as natural gas hydrate inhibitors has gained interest in recent years. Variety of polymers have been studied for their kinetic performance in methane hydrate inhibition in the past; however, thermodynamic hydrate inhibition by water-soluble polymers is not fully understood and needs further investigation. This study investigates the effect of molecular weights and concentrations of aqueous solutions of various oilfield water soluble polymers on phase equilibrium of methane hydrate. Water-soluble polymers, such as polyacrylamide (PAM), xanthan gum (XG), and guar gum (GG) with two different molecular weights and varying concentrations, have been considered for the investigations. These are as follows: PAM (Mw: 1.1 × 106 g/mol, PAM-1 and 1.5 × 105 g/mol, PAM-2), XG (Mw: 6.4 × 105 g/mol, XG-1 and 2.4 × 105 g/mol, XG-2), and GG (Mw: 1.7 × 106 g/mol, GG-1 and 6 × 105 g/mol, GG-2), with varying concentrations of 100, 200, and 500 ppm each. These are referred to as high-molecular-weight polymers (PAM-1, XG-1, and GG-1) and relatively low-molecular-weight polymers (PAM-2, XG-2, and GG-2). The experiments have been conducted in the pressure and temperature range of 8.63-5.50 MPa and 284.6-279.8 K, respectively. The results indicate that the water-soluble polymers have shown thermodynamic hydrate inhibition with an average temperature depression ranging from 0.25 to 1.05 K. The molecular weight and the concentration of polymers have been shown to affect the hydrate inhibition tendency. We have also proposed a hypothesis for hydrate inhibition based on the mobility of the polymer chain in the solution with a desired functional group in relation to nonelectrolyte/electrolyte thermodynamic hydrate inhibitors. The presented study on methane hydrate phase stability in the presence of various oilfield polymers is vital for their use in the design and development of hydrate inhibitive drilling fluids for offshore wells, hydrate-bearing formations, and studies related to the recovery of methane from hydrate-bearing sediments using polymer injection.
Kinetics of methane hydrate formation in an aqueous solution of thermodynamic promoters (THF and TBAB) with and without kinetic promoter (SDS)
Kinetic studies concerning the combination of thermodynamic promoters (tetra-n-butyl ammonium bromide, TBAB and tetrahydrofuran, THF) and kinetic promoters (sodium dodecyl sulphate, SDS) have not yet been investigated in detail for methane hydrate system suitable for natural gas storage and transportation. In this work, experiments were conducted at an initial pressure conditions of 7.5 MPa and 276.15 K for pure water, SDS, TBAB, (TBAB + SDS), THF, (THF + SDS) and (THF + TBAB) aqueous systems for various concentrations. Similarly, at 5.5 MPa and 276.15 K, experiments were conducted for pure water, TBAB, (TBAB + SDS), THF and (THF + SDS) aqueous systems for various concentrations. In addition, at 3.0 MPa and 276.15 K, 0.05 and 0.1 mass fraction of TBAB, 0.005 and 0.01 mass fraction of THF and (0.01 + 0.1) mass fraction of (THF + TBAB) aqueous systems have been considered for the experiments. It has been observed that the methane hydrate formed from pure water with SDS shows higher moles of gas consumption per mole of water as compared to other aqueous systems at higher pressure. Also, the use of SDS with THF shows drastic increase in methane consumption as against semiclathrate hydrate/hydrate formed using TBAB aqueous system and pure water. At lower pressure, of about 3 MPa, gas consumption per mole of water in hydrate has found to enhance for a mixed promoter system containing (THF + TBAB) as compared with the other aqueous systems. Theoretical and actual gas storage capacity calculations has also been performed for various concentrations of THF and TBAB aqueous systems. This study essentially helps to understand the behaviour of TBAB and THF aqueous solution with and without SDS and mixed promoter system of (THF + TBAB) for methane hydrate formation desirable for applications like gas storage, transportation and gas recovery using hydrate-based gas separation method.
Phase Equilibrium of Methane Hydrate in Aqueous Solutions of Polyacrylamide, Xanthan Gum, and Guar Gum
The use of water-soluble polymers as natural gas hydrate inhibitors has gained interest in recent years. Variety of polymers have been studied for their kinetic performance in methane hydrate inhibition in the past; however, thermodynamic hydrate inhibition by water-soluble polymers is not fully understood and needs further investigation. This study investigates the effect of molecular weights and concentrations of aqueous solutions of various oilfield water soluble polymers on phase equilibrium of methane hydrate. Water-soluble polymers, such as polyacrylamide (PAM), xanthan gum (XG), and guar gum (GG) with two different molecular weights and varying concentrations, have been considered for the investigations. These are as follows: PAM (Mw: 1.1 × 10 6 g/mol, PAM-1 and 1.5 × 10 5 g/mol, PAM-2), XG (Mw: 6.4 × 10 5 g/mol, XG-1 and 2.4 × 10 5 g/mol, XG-2), and GG (Mw: 1.7 × 10 6 g/mol, GG-1 and 6 × 10 5 g/mol, GG-2), with varying concentrations of 100, 200, and 500 ppm each. These are referred to as high-molecular-weight polymers (PAM-1, XG-1, and GG-1) and relatively low-molecular-weight polymers (PAM-2, XG-2, and GG-2). The experiments have been conducted in the pressure and temperature range of 8.63-5.50 MPa and 284.6-279.8 K, respectively. The results indicate that the water-soluble polymers have shown thermodynamic hydrate inhibition with an average temperature depression ranging from 0.25 to 1.05 K. The molecular weight and the concentration of polymers have been shown to affect the hydrate inhibition tendency. We have also proposed a hypothesis for hydrate inhibition based on the mobility of the polymer chain in the solution with a desired functional group in relation to nonelectrolyte/electrolyte thermodynamic hydrate inhibitors. The presented study on methane hydrate phase stability in the presence of various oilfield polymers is vital for their use in the design and development of hydrate inhibitive drilling fluids for offshore wells, hydrate-bearing formations, and studies related to the recovery of methane from hydrate-bearing sediments using polymer injection.
Investigation on the Effect of Ionic Liquids and Quaternary Ammonium Salts on the Kinetics of Methane Hydrate
This study investigates the kinetics of gas hydrate (methane gas) in the presence of Ionic Liquids (ILs) and organic Quaternary Ammonium Salts (QASs). Aqueous solutions of eight ILs (five aromatic ILs and three aliphatic ILs) and three QASs have been studied for the kinetics of methane hydrate formation. In this study, five aromatic-based ILs with cations, viz., 1-hexyl-3-methylimidazolium, 1-butyl-3-methylimidazolium, and 1-octyl-3-methylimidazolium, and anions such as [Br]−, [Cl]−, and [HSO4]− were selected. Three aliphatic ILs with cations, viz., diethylammonium, tripropylammonium, and tributylammonium, attached with the [HSO4]− anion were also selected. In the case of QASs, varying carbon chain lengths such as tetra-n-methyl-, tetra-n-ethyl-, and tetra-n-butylammonium bromide (TMAB, TEAB, TBAB) have been considered for the study. The kinetics of methane hydrate formation were investigated at a pressure of 7.5 MPa and a temperature of 276.15 K in the presence of aqueous solutions of QASs at 0.05 mf (mass fraction) and 0.1 mf concentrations and ILs at 0.01 mf. The results show that 0.05 mf of TBAB assists the methane hydrate to nucleate very rapidly and enhances the rate of growth. Hence, TBAB at 0.05 mf is observed to be most promising for gas storage and gas separation/processing among all investigated QASs. TMAB and TEAB have shown slow kinetics; therefore, their presence in a gas hydrate system may not aid in hydrate gas storage/gas separation applications; nevertheless, they could be used as an inhibitor for the prevention of hydrates in systems where other inhibitors may become unsuitable. The aqueous solution of aromatic-based ILs generally shows hydrate promotion, except for shorter chain lengths. The shorter chain length of ionic liquid with suitable anion (Cl-) behaved as a hydrate as the inhibitor and with Br- as the promoter. In general, a bigger cation acts as a good nucleating agent. The anion [HSO4]− is common in both the categories of ILs (aromatic and aliphatic), and it looks like the hydrate inhibition (no hydrate formation) may have occurred due to its presence. ILs offer more scope to understand the tunability of cations and anions to derive a better solution for gas hydrate inhibition and promotion, which have more applications in the ares of methane storage and transportation.
Natural Gas Production from a Marine Clayey Hydrate Reservoir Formed in Seawater Using Depressurization at Constant Pressure, Depressurization by Constant Rate Gas Release, Thermal Stimulation, and Their Implications for Real Field Applications
The depressurization approach of methane production from a natural gas hydrate reservoir has been identified as the most energy-efficient production approach. However, some of the field-scale studies involving constant pressure depressurization (CPD) did not yield significant success. To address this, the constant rate gas release (CRD) depressurization approach was used to overcome the drawbacks of the CPD approach. The experimental investigations of these methods with and without thermal stimulation (TS) have not yet been investigated in detail for marine clayey hydrate reservoirs formed in seawater to understand their comparative effectiveness for methane gas recovery. Although common production approaches have been studied by many researchers on hydrate-bearing sand sediments, energy recovery from hydrate-rich clayey sediments has not yet been investigated in detail, which form the major dominant hydrate reservoirs of the hydrate resource pyramid across the globe. This work investigates in detail the potency of five different natural gas production techniques such as CRD, CPD, TS, and their combination to produce natural gas out of the marine clayey hydrate system. To simulate marine conditions, mud samples with 3 wt % of bentonite clay in seawater have been used for methane hydrate formation at an initial pressure of 8 ± 0.2 MPa and a temperature of 278.15 ± 1 K. The thermodynamic phase equilibrium study of methane hydrate in the marine clayey system has also been conducted to understand the phase stability of hydrates. Subsequently, a study on five different methane recovery approaches to recover natural gas from marine clayey hydrate systems has been carried out to understand their efficacy. For CRD depressurization, two rates, viz., 10 and 20 mL/min, have been used, whereas for CPD, two set pressures of 3.5 and 2.3 MPa have been used. TS was carried out by increasing the hydrate reservoir temperature from 278.15 to 298.15 K. Field implications of these five production schemes have also been discussed in detail for their real field applications.