Gas Injection into Geological Formations and Related Topics

John J. Carroll, Alice Wu, Mingqiang Hao, Weiyao Zhu

• Publisher: Wiley-Scrivener
• Year: 2020
• Print ISBN: 9781119592068
• eBook ISBN: 9781119593348
• Edition: 1
• Topic: Physical Sciences
• Subtopic: Energy

This is the eighth volume in the series, Advances in Natural Gas Engineering, focusing on gas injection into geological formations and other related topics, very important areas of natural gas engineering. This volume includes information for both upstream and downstream operations, including chapters detailing the most cutting-edge techniques in acid gas injection, carbon capture, chemical and thermodynamic models, and much more.

Written by some of the most well-known and respected chemical and process engineers working with natural gas today, the chapters in this important volume represent the most state-of-the-art processes and operations being used in the field. Not available anywhere else, this volume is a must-have for any chemical engineer, chemist, or process engineer in the industry. Advances in Natural Gas Engineering is an ongoing series of books meant to form the basis for the working library of any engineer working in natural gas today.

1
Modifying Effects of Hydrogen Sulfide When Contemplating Subsurface Injection of Sulfur

Mitchell J. Stashick, Gabriel O. Sofekun and Robert A. Marriott*

Department of Chemistry, University of Calgary, Calgary, Alberta, Canada

Abstract

Transportation and handling of molten sulfur is inevitably challenging due to the anomalous rheological behaviour of sulfur with changing temperature. After melting at 115 °C, sulfur’s viscosity remains close to 10 cP. The onset of the λ-transition region is observed at T ≈ 160 °C. The viscosity drastically rises in this region, increasing to a maximum of about 93000 cP at 187 °C. This anomaly is due to the cleavage of sulfur rings and production of reactive diradical sulfur species that concatenate to create sulfur polymers. The entanglement of these sulfur chains causes the dramatic rise in viscosity. Within this work, new data is reported that examines the modifying effects of hydrogen sulfide (H₂S) within liquid sulfur. This may be used when considering the potential injection of liquid sulfur into depleted reservoirs for safe long-term storage. H₂S, when present in liquid sulfur, can either physically dissolve or chemically react to generate polysulfane. The chemical reaction causes significant changes in the sulfur chain distribution and consequently changes the viscosity curve of liquid sulfur as a function of temperature. This study reports viscosity measurements performed from 120 < T < 280 °C with concentrations of H₂S in sulfur ranging from 0 ppmw to 284 ppmw.

Keywords: Rheology, viscosity, λ-transition, sulfur, polymers, hydrogen sulfide

1.1 Introduction

Sulfur requires transportation and handling on an industrial scale. After acknowledging that there were approximately eighty million metric tons of elemental sulfur produced globally in 2018, this becomes abundantly clear [1]. Sulfur recovery from oil refineries and sour gas treatment plants (sour gas is natural gas with hydrogen sulfide (H₂S) > 5.7 mg∙m^-3) has continued to increase, bringing about more deliberation on the utilization and/ or storage of sulfur product. When the value of sulfur is not high enough to economically justify transportation and sale of the material, it is often common to block pour for long-term storage. Block pouring sulfur is a relatively inexpensive method where sulfur is solidified within retaining walls on large plots of land. However, there are some disadvantages to this technique. The land on which the blocks are poured must be leased or owned and this can cause some financial strain. Also, bacteria classified as Thiobacilli are known to metabolize sulfur by oxidizing the material to sulfate

and in doing so produce sulfuric acid (H₂SO₄). This along with rain and further weathering results in the need for water treatment of the acid runoff, incurring additional cost. Lastly, large amounts of weathering sustained by sulfur blocks can yield high content of materials such as dirt, sand and moisture. This can create issues of purity if the price of sulfur rises and it makes economic sense to sell the product again [2]. Alternatively, producers have chosen to inject H₂S (acid gas injection) to mitigate stranded sulfur. With acid gas injection, one needs to consider the energy required for compression of gas, storage under pressure and the loss of energy due to eliminating the Claus plant.

In future operations, an alternative to block pouring or acid gas injection could include the potential injection of liquid elemental sulfur into depleted reservoirs for safe long-term storage. This method would diminish some of the issues experienced with block pouring, but would likely sustain other costs needed for infrastructure and operation. Also, other fundamental understanding is currently lacking in order to pursue this approach. The conditions under which an injection such as this would take place must be known and understood in how they will impact the rheological behavior of sulfur.

One of several conditions to consider is that all sulfur produced in Sulfur Recovery Units at refineries and gas processing facilities will contain some residual H₂S. This is because sulfur is recovered before complete conversion from H₂S. Generally, recovered sulfur from a plant process can have up to 380 ppmw of dissolved H₂S depending on the facility set up [3]. Another condition to consider is the temperature of the depleted underground reservoir. For this, the range of interest for potential injection was found to be around 120 < T < 280 °C. It should be recognized that this temperature range includes the λ-transition region of liquid sulfur. Also, high shear must be considered as this will be encountered in sulfur pumps and the near-wellbore region. Studying sulfur’s shear flow with and without H₂S over the specified temperature range could therefore greatly improve the fundamental understanding needed for injection of molten sulfur.

The viscosity temperature dependence of sulfur within the λ-transition region can be explained by a scission-recombination equilibrium for polymers and the term reptation. In this occurrence, reptation is defined as the thermal motion of entangled macromolecular sulfur chains. At T > 160 °C, cleavage of sulfur S₈ rings results in the generation of reactive diradical sulfur species that combine to create sulfur polymers [4]. The average polymer chain lengths increases as a function of temperature leading to more entanglement and higher viscosity values. At 187°C, the maximum polymer chain length is reached, along with the maximum viscosity. Beyond this temperature, the viscosity decreases due to the thermal scission of polymer chains; however, if H₂S is present, the viscosity profile of sulfur changes depending on concentration. H₂S is known to chemically react with diradical sulfur species during the λ-transition to produce polysulfane, as shown in Eq. (1-1). This reaction terminates the polymerization, which reduces the average sulfur polymer chain length. Therefore, a reduction in the viscosity of the liquid is observed [5-7].

(1.1)

1.2 Experimental

1.2.1 Materials

Oxygen-free, nitrogen gas (N₂; 99.998% as per certificate of analysis) was purchased from Praxair Technology, Inc. Hydrogen sulfide gas (H₂S; 99.6% containing N₂, Ar and trace CO₂ as per certifi...

Table of contents

• Cover
• Table of Contents
• Preface
• 1 Modifying Effects of Hydrogen Sulfide When Contemplating Subsurface Injection of Sulfur
• 2 Experimental Determination of CO2 Solubility in Brines At High Temperatures and High Pressures and Induced Corrosion of Materials in Geothermal Equipment
• 3 Experimental Study of the Liquid Vapour Equilibrium of the System Water-CO2-O2-NOx Under Pressure at 298 K
• 4 The Use of IR Spectroscopy to Follow the Absorption of CO2 in Amine Media – Evaluation of the Speciation with Time
• 5 Solubility of Methane, Nitrogen, Hydrogen Sulfide and Carbon Dioxide in Mixtures of Dimethyl Ethers of Polyethylene Glycol
• 6 Water Content of Hydrogen Sulfide – A Review
• 7 Acid Gas Injection at SemCAMS Kaybob Amalgamated (KA) Gas Plant Operational Design Considerations
• 8 Reciprocating Compressors in Acid Gas Service
• 9 Case Study: Wellbore Thermodynamic Analysis of Erhao Acid Gas Injection Project
• 10 Selecting CO2 Sinks CCUS Deployment in South Mid-West Kansas
• 11 Salt Precipitation at an Active CO2 Injection Site
• 12 The Development Features and Cost Analysis of CCUS Industry in China
• 13 CO2 Movement Monitoring and Verification in a Fractured Mississippian Carbonate Reservoir during EOR at Wellington Field in South Kansas
• 14 Simulation Study On Carbon Dioxide Enhanced Oil Recovery
• 15 Blowout Recovery for Acid Gas Injection Wells
• 16 The Comprehensive Considerations of Leak Detection Solutions for Acid Gas Injection Pipelines
• 17 Injection of Non-Condensable Gas in SAGD Using Modified Well Configurations - A Simulation Study
• 18 The Study on the Gas Override Phenomenon in Condensate Gas Reservoir
• 19 Study on Characteristics of Water-Gas Flow in Tight Gas Reservoir with High Water Saturation
• 20 The Description and Modeling of Gas Override in Condensate Gas Reservoir
• 21 Research on the Movable Water in the Pores of Tight Sandstone Gas Reservoirs
• 22 Probabilistic Petroleum Portfolio Options Evaluation Model (POEM)
• Index
• Also of Interest
• End User License Agreement