Srivastava, Vishal (Colorado School of Mines) | Majid, Ahmad A. A. (Colorado School of Mines) | Warrier, Pramod (Colorado School of Mines) | Grasso, Giovanny (Colorado School of Mines) | Koh, Carolyn A. (Colorado School of Mines) | Zerpa, Luis E. (Colorado School of Mines)
Gas hydrates are considered a major flow-assurance challenge in subsea flowlines. They agglomerate rapidly and form hydrate blockages. During transient operations [shut-in and restart (RS)], risk of blockage formation owing to hydrates can be greater compared to that during the continuous operations. In particular, hydrate formation during an unplanned shut-in and subsequent restart could lead to increased operational hazards. In this work, flow-loop tests were conducted under both continuous-pumping (CP) and RS conditions, using Conroe crude oil with three different water fractions (30, 50, 90 vol%) at 5 wt% salinity, over a range of mixture velocities (from 2.4 to 9.4 ft/sec). It was determined that RS operations resulted in an earlier onset of hydrate particle bedding—twice as fast as those in CP tests—from the interpretation of pressure-drop and mass-flow-rate (MFR) measurements. Droplet imaging using a particle vision and measurement (PVM) probe suggested larger water droplets (100–300 µm) during the shut-in, as compared to the CP tests (=40 µm) at 50 and 90 vol% water cuts (WCs). For the tests performed using a demulsifier at 200 ppm, PVM images suggested larger water droplets (mean droplet size = 94 µm), as compared with the test with no demulsifier (mean droplet size = 21 µm). The test using a demulsifier resulted in higher pressure drops and lower MFRs compared with the test with no demulsifier, indicating poor hydrate transportability when water was partially dispersed in the oil phase. The current study indicated that partially dispersed systems present greater risks of hydrate plugging as compared with the fully dispersed systems in the range of water volume fractions from 50 to 95 vol% WC, which was the phase inversion point of the water-in-crude-oil (Conroe14 crude) system. The flow-loop-test analyses presented in this work can potentially aid in an improved mechanistic understanding of RS operations, involving unplanned shut-ins and restarts.
In this paper, we present for the first time, a classification system for naturally-occurring gas hydrate deposits existing in the permafrost and marine environment. This classification is relatively simple but highlights the salient features of a gas hydrate deposit which are important for their exploration and production such as location, porosity system, gas origin and migration path. We then show how this classification can be used to describe eight well-studied gas hydrate deposits in permafrost and marine environment. Potential implications of this classification are also discussed.
A general formulation for a coupled Thermal-Hydraulic-Mechanical with hydrate Dissociation (THMD) system is developed and applied to sand prediction for conventional gas and gas hydrate bearing sediments (GHBS). Two-phase fluid and conductive heat flow are coupled to an elastoplastic geomechanics model. Series of solutions for simplified models are presented. Fundamental geomechanics behaviors before and after plastic yielding, sanding, and gas hydrate dissociation are defined, discussed, and simulated differently and sanding onset for both conventional gas formations and GHBS are defined by an effective plastic strain (EPS) criterion. The accuracy and reliability of the proposed conventional model are verified by comparing the model prediction with the results of hollow cylinder tests on two different types of sandstone. The advantages of using the EPS over stress-based criteria as an indicator for onset of borehole collapse and sand production are discussed. Introducing a moving gas hydrate dissociation zone (front), the fundamental geomechanics behaviour and elastoplastic deformation of the skeleton formation are highlighted. The effects on sand prediction due to the characteristics of nonlinear plastic yielding criteria and gas flow in porous media are also emphasized.
Introduction Of the three permafrost regions, our calculations show Mohe Basin has the thickest hydrate stability (1300 m). This is followed by Qinghai-Tibet Plateau (1200 m) and Qilian Mountain (800 m).
Prasad, Siddhant K. (Indian Institute of Technology Madras) | Mech, Deepjyoti (Indian Institute of Technology Madras) | Nair, Vishnu Chandrasekharan (Indian Institute of Technology Madras) | Gupta, Pawan (Indian Institute of Technology Madras) | Sangwai, Jitendra S. (Indian Institute of Technology Madras)
Asphaltenes are heavy and polar fractions present in crude oil. Literature survey reveals that studies underlying the effect of individual components of crude oil on hydrate formation are rare. In this work, asphaltene fractions were extracted from a vacuum residue of the crude oil according to method based on IP143/90 (AlHumaidan et al., 2017) and characterized by FTIR, element analysis, SEM and MALDI-TOF MS. Thereafter, the effect of asphaltenes was studied on the phase stability of pure methane hydrate system at 1000 ppm and 10000 ppm concentration. It has been observed that the asphaltene plays an important role in elucidating the phase stability of methane hydrate systems.
Ever increasing energy demands have forced oil and gas exploration and production activities towards unconventional reserves (offshore oil and gas fields, gas hydrates, shale gas, etc.) and their development. Due to higher operating pressure and lower temperature in offshore pipelines, there is an increased risk of hydrate formation and deposition thus challenging flow assurance. Offshore oil and gas installations are hugely expensive to develop with the cost going frequently upwards of US$ 1 billion (IHS Global Inc., 2016). Also, expenses are frequently incurred in upwards of US$ 1 million per mile of subsea flowline to tackle hydrate deposition (Jassim et al., 2008). Hydrate inhibition is an important precursor to mitigate these issues.
Gas hydrates are ice-like, crystalline and non-stoichiometric structure and form when low molecular weight hydrocarbons known as guest molecules are entrapped in a three-dimensional cage-like structures made of water molecules or host molecules (Fadnes, 1996). Natural gas is composed of molecules including methane, ethane, propane, and carbon dioxide (Sloan and Koh, 2008). Fig. 1 shows how the cross-section of a flowline can narrow down with the deposition of gas hydrates. They can also form provided there is a presence of nucleation site like weld slag (Sloan, 2011). Points prone to hydrate deposition in an offshore installation can be better understood with the help of a simplified schematic given in Fig. 2. These can be places downstream of free water accumulation caused by a change in geometry of the multiphase fluid flow, downstream of valves (SCSSV or surface controlled subsurface safety valve) or in the flowline connecting the platform to the onshore facility due to insufficient dehydration.
Aman, Zachary M. (University of Western Australia) | Qin, Hao (Center for Hydrate Research, Colorado School of Mines) | Pickarts, Marshall (Center for Hydrate Research, Colorado School of Mines) | Lorenzo, Mauricio Di (CSIRO) | May, Eric F. (University of Western Australia) | Koh, Carolyn A. (Center for Hydrate Research, Colorado School of Mines) | Zerpa, Luis E. (Center for Hydrate Research, Colorado School of Mines)
Over the past decade, the paradigm of gas hydrate research has transitioned from avoidance via thermodynamic inhibition toward management, where a limited amount of hydrate may be allowed to form in the flowline. This new paradigm enables new field development concepts, including longer-distance subsea tie-backs and limited chemical inhibition. This presentation reviews research datasets from flowloops on hydrate deposition phenomena and includes an initial analysis on the impact of shear stresses on hydrate deposits.
This study integrates experimental data from unique high-pressure laboratory flowloops, including single-pass, gas-dominant and recirculating, liquid-phase flowloops. The flowloops have visual observation ports that allow video imaging to be performed throughout the high pressure tests. These apparatuses together are estimated to provide coverage over 1-200 Pa of flowing shear stress at the wall, over a range of total liquid inventories and water holdup.
For this work, conceptual diagrams of deposition in oil, water, and gas-dominant systems are presented. Film growth rates are derived at the Colorado School of Mines (CSM) from visual observation in a deposition loop. Hydrate particle deposition rates are determined from a gas-dominant flowloop in Western Australia by fitting experimental data obtained from gas-dominant systems. The results demonstrate that the absolute shear stress required to prevent hydrate particles from depositing at the wall, or to remove/slough deposited hydrate from the wall, can vary with the primary fluid phase. Initial shear stress calculations from a specific test estimate that less than 5 Pa can be required to remove/slough hydrates from the wall in the aqueous phase, while more than 100 Pa may be required in a gas-continuous pipeline. This review suggests that deposition and flowing shear stress may be critical considerations in the design and operation of hydrocarbon systems, to help prevent hydrate blockage in industrial operations.
This paper is to represent reviews of low dosage hydrate inhibitor's (LDHI) evolution and advances, and to provide a general guide for LDHI considerations, historically, hydrate risk has been managed by keeping the fluids warm, removing water, and/or by injecting thermodynamic hydrate inhibitors (THI), commonly methanol or glycol. THIs require high dosage rate therefore production systems can reach a treatment limited by supply, storage, and umbilical injection constraints. Besides, high dosage of MeOH can cause crude contamination for downstream refineries, which may result in penalty.
Over last two decades LDHIs have been extensively researched and developed as an alternative hydrate management chemical for oil and gas industry. LDHIs are divided into two main categories; Kinetic Hydrate Inhibitor (KHI) and Anti-Agglomerant (AA), both have been successfully used in field applications, but each comes with their unique challenges for applications, OPEX and CAPEX considerations. LDHIs have proven track records in numerous fields in their performance, either as stand-alone chemical treatment or reducing amounts of methanol/glycol usage, which has directly resulted in CAPEX and OPEX reduction. LDHIs have been instrumental in managing risks of early water breakthrough, high cost of THI storage and transportation, HSSE concerns around THI handling, and undersized pump capacity for required chemical volumes. Switching to LDHIs also offers an economic advantage by reducing umbilical line diameter. Latest advances in the LDHI technology is breaking barriers and pushing limits.
The paper summarizes historical advancements in LDHIs over the last two decades, discusses application advantages and limitations, and the criterions to consider for selecting LDHIs.
Lu, Haidan (Schlumberger) | Tracy, Noah (The University of Tulsa) | Johnson, SC (The University of Tulsa) | Volk, Micheal (The University of Tulsa) | Delle-Case, Emmanuel (SPUR Industrial LLC) | Ozbayoglu, Evren M. (University of Tulsa)
The risk of gas hydrate formation is one of the major concerns for offshore flow assurance. Solutions of methanol (MeOH) and mono-ethylene-glycol (MEG) are most often employed as thermodynamic inhibitors (THI) to prevent the formation of hydrate plugs. This study involves experimental and modeling work to investigate and compare the suitability and effectiveness of methanol and MEG on inhibiting and displacing the water in jumper type configurations during flushing procedures. Numerical analysis aims to investigate the mixing and displacing mechanisms that occur during jumper flushing to optimize key factors such as the position of the injection port and the flowrate of a required chemical inhibitor.
This paper presents the experimental results with respect to effect of inhibitor type, injection rate, brine salinity and liquid loading. All experiments were carried out in a 3" jumper system at The University of Tulsa. Simulations using 1D transient multiphase flow simulator were conducted to evaluate its capacity to predict the thermodynamic inhibitor dispersion by using the inhibitor tracking module. The 3D computational fluid dynamic (CFD) simulations were performed with the commercial software to help predict the amount and flowrates of chemicals required, and to serve optimizing the location of injection ports. Comparisons were made between the simulation results and experimental data from full fresh water loading jumper displacement tests with MEG and methanol.
From the experiments, several conclusions are drawn. Different dispersion and partitioning mechanisms were observed for methanol and MEG through experiments, especially in the vertical sections and low spots of the jumper. Methanol overriding the water phase at horizontal low spots was captured for the low velocity experimental cases, leaving a large amount of water behind that could result in under-inhibited situations. For the 12% brine tests, less water was displaced for each MEG injection rate, whereas a better mixing of methanol with brine was measured. The 1D and 3D simulations provided reasonable prediction for THI distribution along the jumper after displacement tests, except that neither was able to reproduce methanol overriding the water phase at both low spots. 3D CFD simulations results obtained generally gave better agreement with the results from the experiment.
This study provides a better understanding of the displacement and mixing mechanisms of thermodynamic hydrate inhibitors. It helps operators minimize operational risks, reducing the size of the umbilical and decreasing capital costs related to equipment and chemicals.
Wang, Zhiyuan (China University of Petroleum (East China)) | Zhao, Yang (China University of Petroleum (East China)) | Zhang, Jianbo (China University of Petroleum (East China)) | Wang, Xuerui (China University of Petroleum (East China)) | Yu, Jing (China University of Petroleum (East China)) | Sun, Baojiang (China University of Petroleum (East China))
Hydrate-associated problems pose a key concern to the oil and gas industry when moving toward deeper-offshore reservoir development. A better understanding of hydrate-blockage-development behavior can help flow-assurance engineers develop more-economical and environmentally friendly hydrate-management strategies for deepwater operations. In this work, a model is proposed to describe the hydrate-blockage-formation behavior in testing tubing during deepwater-gas-well testing. The reliability of the model is verified with drillstem-testing (DST) data. Case studies are performed with the proposed model. They indicate that hydrates form and deposit on the tubing walls, creating a continuously growing hydrate layer, which narrows the tubing, increases the pressure drop, and finally results in conduit blockage. The hydrate-layer thickness is nonuniform. At some places, the hydrate layer grows more quickly, and this is the high-blockage-risk region (HBRR). The HBRR is not located where the lowest ambient temperature is encountered, but rather at the position where maximum subcooling of the produced gas is presented. As an example case—a deepwater gas well with a water depth of 1565 m and a gas-production rate of 45 × 104 m3/d—the hydrate blockage first forms at the depth of 150 m. In the section with a depth from 50 to 350 m, hydrates deposit more rapidly and this is the HBRR. As the water depth increases and/or the gas-flow rate decreases, the HBRR becomes deeper. Inhibitors can delay the occurrence of hydrate blockage. The hydrate problems can be handled with a smaller amount of inhibitors during deepwater well-testing operations. This work provides new insights for engineers to develop a new-generation flow-assurance technique to handle hydrate-associated problems during deepwater operations.