A.C. Todd

Improving the Accuracy of Gas Hydrate Dissociation Point Measurements

Abstract: Following our previous communications on the impact of the amount of water phase on the time required at each temperature‐step 1 and the limitations of visual techniques in determining hydrate dissociation points, 2 a series of tests were conducted in this laboratory to investigate the impact of measuring techniques, mixing efficiency, heating method and heating rate on the accuracy of hydrate dissociation point measurements. The results showed that nonvisual techniques combined with stepwise heating and satisfactory mixing could save a significant amount of time while providing accurate hydrate dissociation data.

Equilibrium data and thermodynamic modelling of cyclopentane and neopentane hydrates

Abstract 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

Abstract 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.

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.

Improving predictions of equation of state by modifying its parameters for super critical components of hydrocarbon reservoir fluids

The parameters of equations of state of van der Waals type have been generally correlated by matching the properties of pure substances, and extended to mixtures by employing mixing rules commonly with binary interaction parameters. It is proposed to use equilibrium data on binary systems to determine the attraction term in equations of state (EOS) for super critical components instead of data of pure substances. The proposed method was applied to the Peng-Robinson EOS, as an example, resulting in a significant improvement in predicting the phase behaviour of different types of fluids. As no binary interaction parameters are required in this method the computational requirement for flash calculations is drastically reduced for fluids with many components. The proposed method is particularly advantageous for predicting fluid phase equilibria in compositional reservoir simulators, where the reservoir fluid can be described with any desirable number of components without any significant increase in computational time.

A residual viscosity correlation for predicting the viscosity of petroleum reservoir fluids over wide ranges of pressure and temperature

Abstract The method of Lohrenz–Bray–Clark, which relates the residual viscosity to the reduced density, is the most widely used engineering tool to predict the viscosity of reservoir fluids. Systematic investigation of the viscosity of pure compounds at various pressure and temperature conditions indicated the requirement of including the structural and thermal effects for accurate viscosity prediction of dense fluids. The method has been modified to include the above-mentioned effects. Reliability of the modified method for calculating viscosity of mixtures and in particular of high-pressure high-temperature fluids has been demonstrated.

Equilibrium data and thermodynamic modelling of isopentane and 2,2-dimethylpentane hydrates

Experimental hydrate equilibrium data and thermodynamic modelling of isopentane and 2,2-dimethylpentane (2,2-DMP) are presented. Both compounds are reported to form structure-H gas hydrates in the presence of a help gas. Hydrate dissociation data for isopentane and 2,2-DMP in their binaries and ternaries with methane and/or nitrogen are measured and successfully modelled using an equation of state-based thermodynamic model. Indication of a change in the stable hydrate structure (structure-H to structure-I) for isopentane and 2,2-DMP in their binaries with methane at higher temperatures is also discussed.

Measurement and prediction of hydrate-phase equilibria for reservoir fluids

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.

Viscosity and Density of Methane+cis-Decalin from 323 to 423 K at Pressures to 140 MPa

Dynamic viscosity (η) and density (ρ) data are reported for methane+cis-decahydronaphthaline (decalin) binary mixtures of 25, 50, and 75 mass% (74, 90, and 96 mol%) methane at three temperatures (323, 373, and 423 K) from saturation pressure to 140 MPa. A capillary tube viscometer was used for measuring the dynamic viscosity, with the density being calculated from measurements of sample mass and volume. The overall uncertainties in the reported data are 1.0 and 0.5% for the viscosity and density measurements, respectively.

A novel approach for oil and gas separation by using gas hydrate technology

Abstract: It is known that gas hydrates remove the light ends from reservoir fluids. Therefore, controlled hydrate formation in reservoir fluids could be an attractive option for separating oil and gas; that is, to replace conventional production facilities. In this communication we present the results of an integrated experimental and modelling study on the feasibility of the process, and the impact of the various parameters on the rate of hydrate formation. The study investigated the impact of parameters, such as mixing, water history, temperature, pressure, volume of reactor, heat removal requirements, and the quality of separated liquid. The work identified the major parameters and some of the technological requirements. Based on the experimental data, a simplified mass transfer model was constructed to simulate the kinetics of the separation process and to calculate the reactor volume and heat requirements at a specified degree of conversion. The results showed that it is possible to remove most of the lights from the liquid hydrocarbon phase by hydrate formation. The resulting liquid phase could be suitable for pipeline export or tanker loading after some treatment. Associated gas could be recovered locally from the hydrate phase. Alternatively, in cases where there is no infrastructure for transporting this gas, it might be exported as a hydrate slurry, as proposed by Gudmundsson and coworkers.