Hydrates are crystalline water compounds that may form in deepsea pipelines and have the ability to quickly and efficiently plug flow. Given this issue, gas hydrate formation tests have been conducted and reported in a number of published articles. However, most published data has focused on continuous "steady-state" operations and a gap exists for the more complicated, yet interesting transient shut-in/restart scenarios. Motivation to study such systems are further exacerbated given that industrial fields can operate outside the gas hydrate formation region during continuous production. Hydrates become a major concern especially during unplanned shutdowns and restarts. Therefore, this work focuses only on hydrate transient results. Industrially relevant scenarios are investigated by looking into gas hydrate formation and its effect on fluid transportability through visualization and pressure drop during shut-in and restart in a laboratory-scale flowloop. The effects of parameters such as water content and dispersion state, shear, chemical injection, and oil properties on hydrate formation under transient conditions are reviewed and general agreement is shown between the studies. Overall, the general consensus is that lower water contents, dispersed water, high shear, thermodynamic inhibitor injection, dosing of anti-agglomerants or kinetic hydrate inhibitors, higher oil viscosities, and oils with natural chemical surfactant properties can be favorable for ensuring successful restart of hydrate forming systems. Flowloop tests in a gas-dominated system show that film growth over and around the liquid pool at the bottom of the pipe could lead to plugging in a significant portion of the flowline. This could continue to build up over time (with the addition of fresh hydrate forming materials in an actual system) and inhibit gas flow. Further tests on an oil-dominated system with an intermediate water content demonstrate how shut-in conditions could potentially increase the risk of plugging compared to dispersed lower water content systems. In the former case, water accumulation to low spots in the flowloop allowed for localized areas of high water concentration, where rapid hydrate bed formation in partially dispersed oil-water sections controlled the overall fluid transportability.

The formation of gas hydrates is considered a major flow assurance issue resulting from high pressure and low temperature conditions during petroleum production in deep water developments ( Sloan and Koh 2007 ). Gas hydrates are solid crystalline compounds, which can be formed when the pressure and temperature reaches the thermodynamically stable hydrate zone. Hydrates can plug deepwater flowlines, which may lead to the rupture of flowlines and spill or leakage of oil and gas ( Sloan 2010 ). As a result, production and economic losses may exist during operation. illustrates the oil-dominated pipeline plugging mechanism caused by hydrates in an oil dominated pipeline. The process is fairly complex, with phenomena such as: (1) water entrainment or dispersion of water droplets in the continuous oil phase due to fluid shear and surface-active components in the oil; (2) hydrate formation, with hydrate growth at the water-oil/water-gas interface under a certain degree of thermal driving force; (3) hydrate agglomeration and deposition; (4) particle jamming and hydrate plugging. Among these mechanisms, film growth, deposition (bedding) can be categorized into hydrate deposition. Traditionally, thermodynamic approaches are used to prevent the formation of hydrates in flowlines, including the injection of thermodynamic hydrate inhibitors (THIs), such as methanol or glycols. THIs work by shifting the hydrate phase equilibrium conditions to a lower temperature and higher pressure, which makes the condition unfavorable for hydrates to form ( Sloan and Koh, 2007 ). However, for THIs, large amounts of chemicals are needed, which will introduce high OPEX and CAPEX ( Creek, et al. 2011 ). Hydrate risk management methods have gained popularity, as they will largely reduce the cost. The latter more recent concept suggests that by injecting low dosage hydrate inhibitors (LDHIs), including kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs), the risk of flowline blockage can be controlled, even though the flowline may enter the hydrate stability zone. To support this concept, a comprehensive simulation tool is critical to predict the different hydrate plugging mechanisms mentioned above.

Two major concerns in offshore production are Methane Hydrates and Paraffin Plugs. They may stop wells for months, causing high financial losses. Sometimes, depressurization techniques allow hydrate removal. Another strategy is using coiled tubing or a similar unit to perform local heating or solvent injection. However, frequently these strategies are not successful. In those cases, a rig may be a suitable but expensive solution, or the line may be lost. The present project aimed to develop a robotic system capable of performing controlled local heating for removing Paraffin and Methane Hydrates. The robotic system accesses the line from the production platform. It uses a peristaltic self-locking traction system to exert high traction forces. An umbilical with quasi-neutral buoyancy and low friction coefficient reduces the cable traction. It also allows moving upwards and in pipes with a large number of curves, something that coiled tubing and similar units cannot. Carbon fiber vessels and compact circuits allowed downsizing it to move inside 4-inch flexible pipes. Initially, a theoretical model for the local heating system allowed the evaluation of this strategy. A prototype allowed testing the system in a cooled environment. This heating system removes the obstruction in a controlled manner, avoiding damages to the polymeric layer of the flexible line. Simultaneously, a modified Euler-Eytelwein equation allowed the development of a theoretical model for cable traction. Experimental tests validated this model. Those tests used straight and curved pipes, both empty and filled with fluid and using different loads. Also, the 20 kN (4.3 kip) traction system was modeled theoretically considering the self-locking system, the contact with the wall, and a diameter range. Prototypes allowed the comparison between electric and hydraulic systems. Those prototypes also validated the traction capacity. Besides, force transmission from the traction system to the umbilical occurs through an external aramid layer. A Universal Testing Machine validated the traction resistance of the external layer. Furthermore, carbon fiber vessels protect the electronic circuits from oil and external pressure. The power electronics designed can provide up to 4kW for the motors to operate the hydraulic system. The onboard computer runs with a real-time operational system and, together with a sensors network, is responsible for monitoring the pressures, temperatures, currents and tensions throughout the entire robot. The fail-safe design allows the robot to operate without risks of catastrophic accidents and guarantees that it can be pulled out at any time. A pressure vessel validated the collapse resistance, reaching more than 700 bar (10.000 psi). In addition, exhaustive integration tests validated the onboard electronics and the surface control system. Finally, factory tests validated the umbilical design.

As deep-water activities and development into deeper operations (depth of 6,000ft or more) increases, temperatures and pressures become favorable for hydrate nucleation and growth. This results in additional risk and challenges as to how to prevent formation of gas hydrates. This paper takes a look at the performance of a local surfactant derived from plant material in a laboratory mini flow loop made of a 0.5-inch internal diameter 316 stainless steel pipe enclosed in a 4-inch PVC pipe mounted on an external metal frame work. The performance of the local surfactant (Surf. X) was compared with that of the conventional hydrate inhibitor N-Vinyl Caprolactam (N-VCap). Varying weights of Surf. X were evaluated in the laboratory mini flow loop. Pressure versus Temperature, change in Pressure versus Time plots showed that Surf. X performed better than the conventional N-VCap in almost all the concentrations considered (except at 0.04wt %). The optimum concentration for inhibition was 0.02wt% with inhibition efficiency of 81.58% while that of N-VCap was 77.19%. The inhibition efficiency of Surf. X for 0.01, 0.03 and 0.04wt % were 72.81% and 75.44% respectively. Surf. X is locally sourced, readily available in commercial quantity and also eco-friendly because it is plant based unlike the N-VCap which is toxic and expensive. It is advised that the local surfactant X be developed as an alternative to the conventional inhibitor for gas hydrate inhibition.

The oil and gas production in deeper water scenarios (e.g. pre-salt) has been increasing due to the growth in industrial production. The exploration fields under more severe conditions is accompanied by concerns about solid precipitation/deposition and hydrate formation. Transient operations, involving shut-in and restart is the most challenging scenario with risk for hydrate problem. The residence time of the production fluids associated to the rate of heat loss to the ambient seabed during the period of shut-in may increase the potential risk of hydrate blockage. This work is focused on understanding the hydrate formation, breakup, agglomeration and deposition, reproducing the shut-in and restart conditions in a lab-scale. Experiments were performed using a high pressure cell coupled to a rheometer using a custom-designed impeller and a rocking cell experiments with visual capabilities. A two-phase (water and gas) and three-phase (water, oil and gas) systems were used in the experiments. Also, the impact of the shear applied at restart on the hydrate morphology was evaluated. The viscoelastic behavior was observed in most shut-in and restart tests. Understanding the mechanism of hydrate formation and agglomeration during transient conditions may help to develop strategies to avoid hydrate plugging and allow the formation of a hydrate slurry yielding flowable conditions.

Hydrate management is a major challenge for offshore oil and gas fields, and in subsea pipelines transporting gas from offshore platforms to the onshore processing facilities. This paper is intended to discuss the various hydrate control methods and strategies that have been evaluated and implemented during the project's design, startup, and operation stages to come up with the most efficient and economical solution for hydrate mitigation. Methanol, MonoEthylene Glycol (MEG) and kinetic hydrate inhibitors (KHIs), as well as Twister Technology, were evaluated to act as hydrate prevention mechanisms. Based on the CAPEX, OPEX and unmanned operation philosophy, KHI was used for hydrate inhibition in the gas Field-A. This paper will discuss different innovative strategies to eliminate hydrates during steady-state and transient operations. It will also consider cold startup, maximum flow and minimum temperature, planned and unplanned shutdowns, depressurization, and purge and pilot gas scenarios. The optimum hydrate management control for Field-A offshore platforms and subsea pipelines was a combination of different strategies. For the Field-A, KHI and MEG injection were utilized in combination or independently depending on the scenario. The challenges experienced during the commissioning, startup and operation of the first Saudi Aramco offshore facilities resulted in many potential innovations and patents as follows: Development and installation of the PMS resulted in reducing the operating cost. Development of variable speed pipeline pig technology. The challenges and lessons learned associated with hydrate management will be discussed in addition to the advantages and disadvantages of the used chemicals.

In subsea production operations, wellhead jumpers are one of the subsea facilities more liable to the formation of hydrate blockages during restart operations. To manage hydrate formation and optimize the amount of thermodynamic hydrate inhibitors (e.g. mono-ethylene glycol; MEG) injected, a newly-constructed jumper-like facility (the HyJump flowloop) has been developed in Perth, to simulate shut-down and restart operations over a range of superficial gas velocities. The test section of the flowloop has a unique geometry to mimic subsea jumpers, with three low points and two high points standing 13′ 2″ tall. The test section is fitted with twelve pressure and temperature sensors spread regularly, a MEG sensor, a valve to simulate the wellhead choke, and a viewing window. In each test, the jumper low points were loaded with aqueous solutions of MEG (0 to 30 wt%) and pressurized with domestic Perth natural gas at a pressure of 1200 psig and pipeline temperature ranging from 41°F to 25.8°F (+5 to -4°C). The extent of hydrate restrictions or blockages was evaluated through the dynamic pressure drop behavior observed throughout the flowloop. A closer assessment of the pressure drop trace during gas restart suggests that the severity of the hydrate restriction decreases as the MEG content is increased above 10 wt%. Further, our preliminary experimental results illustrate that severe hydrate deposition in the jumper could be completely avoided by injecting MEG at concentrations above 20 wt%. This corresponds to an approximately 50% reduction in MEG content, where ≈38 wt% MEG dosage was required for complete thermodynamic hydrate inhibition at the pressure and temperature conditions used in this trial. Our unique flowloop facility offers new insight toward hydrate formation in complex subsea jumper-like geometries. Our findings may assist operators in controlling the extent of hydrate formation and deposition in jumper geometries, by optimizing the MEG injection and subsequently supporting lower-CAPEX tieback development concepts.

Gas hydrate formation is considered one of the major problems facing the oil and gas industry as it poses a significant threat to the production, transportation and processing of natural gas. These solid structures can nucleate and agglomerate gradually so that a large cluster of hydrate is formed, which can clog flow lines, chokes, valves, and other production facilities. Thus, an accurate predictive model is necessary for designing natural gas production systems at safe operating conditions and mitigating the issues induced by the formation of hydrates. In this context, a thermodynamic model for gas hydrate equilibrium conditions and cage occupancies of N 2 + CH 4 and N 2 + CO 4 gas mixtures at different compositions is proposed. The van der Waals-Platteeuw thermodynamic theory coupled with the Peng-Robinson equation of state and Langmuir adsorption model are employed in the proposed model. The experimental measurements generated using a cryogenic sapphire cell for the pressure and temperature ranges of (5-25) MPa and (275.5-292.95) K, respectively, were used to evaluate the accuracy of this model. The resulting data show that increasing nitrogen mole percentage in the gas mixtures results in decreasing of equilibrium hydrate temperatures. The deviations between the experimental and predictions are discussed. Furthermore, the cage occupancies for the gas mixtures in hydrate have been evaluated. The results demonstrate an increase in the cage occupancy for both the small and large cavities with pressure.

Since their initial discovery in the 1960’s, gas hydrates have been considered to be an important potential source of unconventional natural gas. Significant progress has been made relative to our understanding of the geologic and engineering controls on the ultimate energy potential of gas hydrate; however, more work is required to realize the promise of gas hydrates as a future energy source. Gas hydrates have been encountered, recovered or inferred to exist in numerous sedimentary basins in Arctic permafrost settings, regions of alpine permafrost, marine sediments of outer continental margins and in deep lakes. Despite the great abundance of potential gas hydrate resources in the world, a large portion of these resources reside in clay-rich sediments and fracture dominated reservoir systems, and are not generally considered producible with existing technology, but may have future potential with the emergence of new technologies. For a large portion of the world, gas hydrate in sand reservoirs have become a viable production target and the focus of the first production testing efforts. Production tests in Arctic Canada (Mackenzie Delta) and Alaska have shown that gas can be produced from highly-concentrated gas hydrate accumulations in coarse-grained (i.e., sand rich) reservoir systems with conventional production technologies. Production can be achieved through the depressurization method and by more complex methods such as molecular substitution (e.g., CO 2 -CH 4 exchange). In 2013, the gas hydrate production test was conducted in a marine setting in the offshore of Japan. An additional test was conducted in Japan in 2017 to further evaluate alternative well completion technologies. Also in 2018, China initiated a 60-day gas hydrate production test in the Shenhu region of the South China Sea. This report reviews the results of gas hydrate engineering and production testing studies associated with the Mallik, Mount Elbert, and Iġnik Sikumi projects in northern Canada and Alaska. The results of the marine gas hydrate producing testing efforts in the Nankai Trough (Japan) and in the South China Sea (China) are also summarized.

Gas hydrates are naturally-occurring crystalline inclusion compounds. They comprise compressed molecules of gas (usually methane) that are ‘lodged’ within a solid lattice of water molecules. For this reason, the gas molecules are called ‘guests’ and the water molecules are called ‘hosts’. Gas hydrates form where there are sources of water and methane under favorable thermodynamic conditions of relatively high pressure and low temperature. Objective of the study is to evaluate Petrophysical Properties from drilled well of NGHP expedition 2 for Gas Hydrate. To identify different hydrate formation and estimation of hydrate saturation. The Work flow to estimate Petrophysical properties is guided by the high resistivity, low transit time and low density. It includes evaluation of different overlays and cross plots of wells like picket plot to firm up different parameters. Porosity is measured by density log, water saturation using Archie's equation; gas hydrate saturation using DMR method and its validation for the results obtained from Pressure core. Electrical resistivity and acoustic travel time mainly used to identify potential Gas Hydrate zones with overlay technique from density porosity and acoustic travel time and other density porosity with total NMR porosity, along with resistivity log are used for identifying potential Gas Hydrate zones in this study. Porosity estimated from density log is used for calculation Hydrate saturation. Gas Hydrate saturation is estimated using standard Archie's equation and Density Magnetic Resonance (DMR) method. Wherever NMR log data is good, saturation estimated from both are in good agreement. Log derived Gas Hydrate saturation are compared and validated with Gas Hydrate saturation obtained from pressure cores. Very good Gas Hydrate saturated zones are observed above BSR in 21 wells in the range of 40-90%. Out of these 21 wells, 16 wells are also having Gas Hydrate saturation in the range of 30-50%. Good Gas Hydrate saturation wells are mainly in area B and C in KG deep water Basin. This study will be very useful in preparation of Geological model for estimation of Gas Hydrate reservesaccurately. This study will also help in NGHP-3 for identifying suitable sites to carry out pilot production testing of Gas Hydrates.

Data acquired from major gas hydrate field programs over the past 20 years has led to much better understanding of the distribution of gas hydrate on the continental margins and how to detect them. Gas hydrate systems are extensions of the conventional hydrocarbon system but are much more closely related to biogenic gas systems. The temperatures at which most biogenic gas is generated is mostly below the base of gas hydrate stability which means that most biogenic gas has to migrate into the gas hydrate stability zone and has to be at levels in excess of solubility for gas hydrates to form. Gas hydrates had been considered ‘self-sealing’ but evidence from pressure cores and laboratory experiments indicate that gas hydrate deposits may need local seals. Detection of gas hydrates though seismic and other remote sensing methods has been demonstrated through drilling and coring programs. The GC955 site in the Gulf of Mexico is used as an example to demonstrate exploration concepts, through basin models, seismic detection, and drilling and coring results. Data from other locations are also discussed. A review of remote sensing data that could be used to delineate and quantify gas hydrate deposits is presented with an emphasis on low frequency exploration 3D seismic for imaging gas hydrate deposits at the base of gas hydrate stability.

Natural gas hydrate is an ice-like crystal formed by methane and water, which is a new type of strategic energy with huge reserves. The exploitation of deep-sea hydrate will cause a large amount of decomposition of hydrate, which will decrease the sediment strength. In this paper, firstly, the influence of three main distribution patterns of hydrate on mechanical parameters is analyzed and the hydrate reservoirs suitable for actual production are judged. Then, reservoir constitutive models and hydrate decomposition and flow models are established based on previous studies. Different distribution patterns of hydrate are established by changing the hydrate content in the reservoir. Finally, simulations are carried out under different production pressure, and parameters such as hydrate saturation are output. Then input those parameters into Mohr-Coulomb model to compare the changes of mechanical properties of reservoir during the exploitation and judge whether the hydrate reservoir is disturbed. Consequently, the critical production pressure is determined. Then, the optimal production rate of different types of reservoir can be determined by adjusting production pressure within the critical bottom hole pressure. The work of this paper will provide a certain reference value for the rational and safe production of hydrate in the future.

This study provides valuable insights into hydrate management strategies as the industry transitions away from complete hydrate avoidance, particularly for the development of deep-water reservoirs with stricter economic margins. Transient simulation tools, such as the deployed hydrate deposition model, extend our ability to estimate blockage likelihood from heuristics to quantitative predictions. The model is applied to an insulated subsea tieback to identify the optimal no-touch-time (NTT) and depressurization pressure (DPP) following an unplanned shutdown. Two water-production scenarios are considered, from the lowest expected to the highest manageable rates. A complete hydrate blockage is predicted when the NTT was extended several hours beyond the nominal value for the highest water-to-gas ratio (WGR). Complete blockages are predicted for both low and high WGRs when the flowline is only partially depressurized, however, longer cooldown times for the high WGR case (due to greater volumes of residual liquids) meant a blockage took more than twice as long to occur than for the low WGR case. Fully depressurized restarts are both difficult and time consuming, leading to hydrate volume fractions (with respect to the pipe volume) exceeding 30 vol.%. An alternative hydrate management strategy is identified for cases with high volumes of water production, in which the flowline is only partially depressurized once the nominal NTT has elapsed, utilising the increased heat capacity of residual liquids. This reduces the quantity of gas sent to flare and simplifies the restart procedure.

At the GFZ German Research Centre for Geosciences we have developed a safe and efficient method which allows for the decomposition of gas hydrates by the supply of heat inside the reservoir. The heat is generated in situ by a catalytic combustion of methane in a counter-current heat-exchange reactor. The reactor that Rudy Rogers, Professor Emeritus in Chemical Engineering at Mississippi State University, referred to as the "Schicks Combustor" is placed in a borehole in such way that the hot reaction zone is situated in the area of the hydrate layer. The counter-current heat-exchange reactor developed at GFZ generates heat via a flameless catalytic oxidation of methane at a noble metal catalyst. The system is closed i.e. there is no contact of the reactants, catalyst and environment. For safety reasons, methane and air are fed separately through a tube-in-tube arrangement into the mixing chamber. Due to its cooling effect and for safety reasons air instead of pure oxygen is used. From the mixing chamber the gas mixture arrives in defined quantities on the catalyst bed, where methane and oxygen are converted into carbon dioxide and water. The hot product gases release their heat via an aluminum foam to the outer wall of the reactor and then to the environment. Simultaneously, the incoming gases are preheated. The reaction runs stable and autonomous between 673 and 823 K. The counter-current heat-exchange reactor was designed as a lab reactor and a borehole tool. The lab reactor was tested in a reservoir simulator to investigate the heat transfer into gas hydrate bearing sediments. Therefore methane hydrate was generated in the LA rge R eservoir S imulator ( LARS ), an autoclave with a volume of 425 L. In a test with 80% hydrate saturation, the reservoir simulator warmed up within 12 hours after the ignition of the catalyst to such an extent that the temperature of the complete sample was above the dissociation temperature of the previously formed methane hydrate which dissociated completely and methane could therefore be produced. During this test, only 15% of the produced CH 4 was consumed to generate the energy needed for the thermal dissociation of the hydrates. The experience with the laboratory reactor served as basis for the design of a borehole tool which is suitable for the application in natural gas hydrate reservoirs. The borehole tool has a total length of 5120 mm, an outer diameter of 90 mm and weighs ca. 100 kg. First results from field tests at the continental deep drilling site KTB in Windischeschenbach, Germany, confirm that the borehole tool reliably produces heat at depth.

Deepwater natural gas hydrate resources potentially exceed all other conventional and non-conventional hydrocarbon resources on a world-wide basis. However, before these offshore gas hydrate resources can be classified as reserves, it must be demonstrated that gas hydrates can be produced under conditions that make economic sense. The purpose of this paper is to provide an overview of the technical issues that will challenge the development of deepwater natural gas hydrates.

In pipelines, solid compounds including gas hydrates and asphaltenes may form/precipitate and accumulate on the pipe surface, leading to a gradual stenosis of the flowline. As a result, production may become increasingly difficult or possibly interrupted if mitigation efforts are not enacted. Typically, injected chemicals will either inhibit nucleation or dissolve already-formed deposits to restore original flow conditions back to the system; however, this can be a costly option. More recently, management strategies have been proposed where solids are handled in a controlled fashion rather than completely avoided. One such proposed management strategy as suggested for wall deposit formation is the use of coatings. Here, coatings can provide a low surface energy layer on the pipe wall, which restricts liquid and solid accumulation, allowing for a stable slurry flow through a system. This study utilized two material formulations within several experimental setups to probe their interactions with water, gas hydrate, asphaltene, and crude oil. The results serve as part of an ongoing investigation into a surface treatment formulation that can be tested on larger-scale, fully flowing systems, which could be ultimately implemented into real-world production scenarios. The first surface treatment is a water-based polymeric surface that displays repellency to both oil and water phases (omniphobic). Testing of this material consisted of water contact angle measurements and static asphaltene/crude oil deposition quantification at atmospheric conditions, as well as visual confirmation of hydrate deposition prevention at high pressures. Additionally, an experimental superomniphobic surface treatment, which displays elevated resiliency to both water and hydrocarbons, was also examined within the asphaltene/crude oil test as a comparison to the omniphobic surface treatment. Static contact angle results showed that the omniphobic surface treatment had reduced surface interaction with water droplets in air, increasing the low contact angles of corroded surfaces (0-31°) to slightly hydrophobic conditions of 91.5°. Additionally, rocking cells tests indicated that these omniphobic surface treatments may prevent gas hydrate deposition under high-pressure, semi-flowing conditions. Multiple tests found that formed hydrate agglomerants did not deposit for at least 48 and 72 hours. Finally, static deposition tests conducted in crude oil with forced asphaltene precipitation suggested that the omniphobic surface treatment displayed a resistance to both asphaltenes and crude oil when compared to untreated and superomniphobic surfaces.

Recently the concept of "no external gas hydrate control measures" has been proposed, whereby gas hydrate formation can occur in oil and gas subsea pipelines during steady state and transient operations, with the operational window defined by predictive analytic tools. Flow assurance engineers routinely use computer programs, including transient multiphase flow simulators coupled to a gas hydrate kinetics model to simulate gas hydrate formation and transportability. Given the complexity in multiphase flow modeling, modern machine learning technologies, especially artificial intelligence, could be applied to solve high-level, non-linear problems, such as evaluating gas hydrate risk based on measurable process parameters. In this work, several machine learning techniques, such as regression, classification, feature learning with an algorithm/framework like support vector machine (SVM) and neural networks (NN), are applied to analyze the data sets on: 1) hydrate tests conducted at pilot-scale flowloop facilities (4,500 data points), as well as 2) transient operation field data. The classification/regression model based on flowloop test data uses several independent input variables (features), such as water cut, gas-oil ratio, hydrate particle cohesive force, fluid velocity, oil viscosity, specific gravity, interfacial tension, and time in the hydrate stable zone, to output the hydrate fraction and probability of hydrate plugging in the pipeline. The semi-supervised learning model was applied based on the field data use as input, including water cut, shut-down time (where applicable), and gas-oil ratio to determine the level of hydrate resistance to flow during restart or dead oil displacement after production shut-down. The flowloop based machine learning model exhibited good prediction accuracies in test and validation processes, and was used to assess the hydrate risks in an actual field. The field data based machine learning model demonstrated the ability to construct field risk maps. The machine learning technique could be potentially applied in hydrate management to evaluate hydrate risks in subsea oil/gas pipelines. As a complement to more complex transient multiphase flow simulations, this machine learning approach can aid in the development of advanced hydrate management strategies.

Methane hydrates (MHs) have been considered as the future clean energy resource because of the vast resource volume and the capability to store methane effectively. To synthesize MH-bearing samples in laboratory for analysis of the thermophysical/geomechanical properties and the formation/dissociation behavior is important because of the scarcity of obtaining naturally-occurring MH cores. With the aim to achieve maximum uniformity in the MH-bearing samples, we designed experiment involving a three- stage cooling process to induce MH formation in the sandy medium under an excess-water condition. The experimental measured P and T were used to estimate the phase saturations of all phases (aqueous, gas and hydrate) over time based on a pore-volume balance method. In the absence of direct visualization capability, we further analyzed the experimental results through numerical simulation to derive the spatial distributions of all phases in the sample. Heterogeneity was identified because of the heat inflow from the surrounding resulting from the imperfect insulation of the reactor. We reached the conclusion that creating homogeneous MH-bearing samples in laboratory is extremely challenging and may not be possible. Our results offer explanations for MH formation at preferential locations and shed light on alternative innovative designs of experimental apparatus or cooling processes (with increased number of cooling steps and longer duration) to create uniform MH-bearing core samples.

The objective of this study is to analyze in detail a process for designing by means of numerical simulation a field test of gas production from hydrate deposits, and to discuss modeling results associated with several such planned tests. The paper discusses comprehensively the data required for a reliable estimate of gas production, and provides insights into production conditions and test well operating parameters that can adversely affect a planned test. The design process begins with the development of a reliable geologic model. It is followed by an analysis of the system stratigraphy, the identification of the hydrate-bearing zones and the associated interlayers, the definition of the initial conditions (pressure, temperature, phase distributions, and geomechanical stresses), the identification of all key media properties (flow, thermal, geomechanical), and the definition of success criteria for hydrate production tests. The geologic model is of paramount importance because it can define the system boundaries. We explore the relative importance of lateral vs. top and bottom flow boundaries within the context of the limited time frame of a field test. Initial pressures P in hydrate accumulations are relatively predictable as they are almost invariably hydrostatic. The initial temperature T distribution is important because T is the dominant parameter controlling the hydrate behavior. Knowledge of the P and T distributions are important in determining true time-invariant P- and T-boundaries. Other important initial conditions are (a) the spatial distribution of the possible phases and (b) the geomechanical stresses in the system and its surroundings. We discuss possible sources of the necessary data through analogs even when direct measurements are unavailable. We investigate the effect of heterogeneity in various parameters, and in the choice of the coordinate system. We explore the impact of spatial discretization, an important subject that has yet to be fully investigated. Finally, we provide modeling results covering a wide range of designs for production tests in oceanic and permafrost-associated hydrate deposits that describe fluid production and the flow and geomechanical system response, as well as implications for the well design and construction. To the authors' knowledge, this is the first paper discussing in detail the recommended process for the design of field tests of gas production from hydrates, and of the key issues that can affect not only production but also the flow and geomechanical behavior of the system during the test and the definition of the well construction requirements.

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.