A viscosity model of waxy-hydrate slurry
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Abstract:
With the exploration and development of oil and gas fileds going towards into deep-water fields, high waxy reservoir has much more flow assurance issues of encourage complex solids depositions in the transportation system, especially hydrates and wax. Applying risk management such as hydrate slurry technology to control hydrate blockage, has much more economic and technical advantages, comparing to the traditional methods. It is significant to understand the viscosity of the waxy-hydrate slurry using hydrate slurry technology in high wax content reservoir. In this work, based on a simplification idea by coupling the wax content effect into the viscosity, volume and density of the water-in-waxy oil emulsion, a new viscosity model of waxy-hydrate slurry is established according to the Einstein effective medium theory, based on the experiments carried out in a high-pressure rheology system with different wax contents ranging from 0.5 wt%∼2.0 wt%. The effect of the complex aggregate coupling wax-hydrate-water is considered by function the non-Newtonian coefficient by four dimensionless parameters. Well-fitting results within an improved deviation of ±15% indicate the feasibility of this method is feasibility. This work can provide a valuable reference for the application of hydrate slurry technology in deep-water fields with high wax content reservoir.Keywords:
Clathrate hydrate
Flow Assurance
Low temperature and high pressure conditions in deep water wells and sub-sea pipelines favour the formation of gas clathrate hydrates which is very undesirable during oil and gas industries operation. The management of hydrate formation and plugging risk is essential for the flow assurance in the oil and gas production. This study aims to show how the hydrate management in the deepwater gas well testing operations in the South China Sea can be optimized. As a result of the low temperature and the high pressure in the vertical 3860 meter-tubing, hydrate would form in the tubing during well testing operations. To prevent the formation or plugging of hydrate, three hydrate management strategies are investigated including thermodynamic inhibitor injection, hydrate slurry flow technology and thermodynamic inhibitor integrated with kinetic hydrate inhibitor. The first method, injecting considerable amount of thermodynamic inhibitor (Mono Ethylene Glycol, MEG) is also the most commonly used method to prevent hydrate formation. Thermodynamic hydrate inhibitor tracking is utilized to obtain the distribution of MEG along the pipeline. Optimal dosage of MEG is calculated through further analysis. The second method, hydrate slurry flow technology is applied to the gas well. Low dosage hydrate inhibitor of antiagglomerate is added into the flow system to prevent the aggregation of hydrate particles after hydrate formation. Pressure Drop Ratio (PDR) is defined to denote the hydrate blockage risk margin. The third method is a recently proposed hydrate risk management strategy which prevents the hydrate formation by addition of Poly-N-VinylCaprolactam (PVCap) as a kinetic hydrate inhibitor (KHI). The delayed effect of PVCap on the hydrate formation induction time ensures that hydrates do not form in the pipe. This method is effective in reducing the injection amount of inhibitor. The problems of the three hydrate management strategies which should be paid attention to in industrial application are analyzed. This work promotes the understanding of hydrate management strategy and provides guidance for hydrate management optimization in oil and gas industry.
Clathrate hydrate
Flow Assurance
Cabin pressurization
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The developed clathrate hydrate has latent-heat over the temp. range of 5〜12℃, and a mixture of clathrate hydrate and aqueous solution (referred to as hydrate slurry) has grater cooling capacity compared to cold water. The utilization of the hydrate slurry in air-conditioning system is expected to reduce the pumping power consumption dramatically. Densities of the aqueous solution , the clathrate hydrate and the hydrate slurry were measured. The measured density of hydrate slurry showed a good agreement with a calculated value.
Clathrate hydrate
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Abstract Offshore flowlines transporting hydrocarbons have to be operated very carefully to avoid the formation of gas hydrates as they are considered one of the largest concerns for flow assurance engineers. The oil and gas industry is generally relying on chemical injection for hydrate inhibition; however hydrate blockages can occur in many different places of offshore production system due to unexpected circumstances. Once hydrate blockage formed considerable efforts are required to dissociate the hydrate via depressurization. Because residual hydrate structures known as gas hydrate precursors will be present in the aqueous phase after dissociation, the risk of hydrate re-formation becomes extremely high. Although the KHIs are becoming popular in many fields as hydrate inhibitors are considered not effective to inhibit the hydrate formation in the presence of residual hydrate structures, so that the use of KHIs for shut-in and restart operations is not recommended. In this study, new experimental procedures composed of three stages are designed to simulate the dissociation of hydrate blockages and transportation of well fluids experiencing hydrate formation. The obtained experimental results have shown that gas hydrates are rapidly re-formed when the temperature of dissociated water falls into the hydrate formation region. With an injection of KHIs before transporting the well fluids, the subcooling increased significantly indicating the possible use of KHIs for transporting the well fluids after dissociation of hydrate blockage. Moreover, the inhibition performance of KHIs is also investigated with two different gases to study the effect of gas composition. This study is confirmed that KHIs are possible candidate to prevent the hydrate re-formation in well fluids experiencing hydrate formation if the KHI is carefully evaluated. Introduction Gas hydrates are nonstoichiometric crystalline compounds that are classified into three structural families of cubic structure I, cubic structure II, and hexagonal structure H. Offshore flowlines transporting hydrocarbons have to be operated very carefully to avoid the formation of gas hydrates as they are considered the largest concern for flow assurance engineers. For many years industrial practice to prevent hydrate-related risks is the injection of thermodynamic hydrate inhibitors (THI) at the wellhead, commonly methanol or monoethylene glycol (MEG), to shift the hydrate equilibrium curve toward higher pressure and lower temperature, so that the operating condition of offshore flowlines are outside of the hydrate formation condition. However as the search for hydrocarbon resources moves into deeper and colder waters further offshore, these conventional techniques are becoming uneconomic due to higher injection rate of inhibitors and accompanying operational issues such as logistics and storage requirement. Although the MEG injection is considered to be the standard method for the offshore gas production system, Kinetic Hydrate Inhibitor (KHI) is also becoming popular as its dosage rate is expected in the range of 0.5~3.0 wt%, which is much lower than MEG's 30~60 wt%. Kinetic hydrate inhibitors (KHIs) are water-soluble polymers and delay the formation of hydrate crystals. These include homo- and co-polymers of the N-vinyl pyrrolidone (PVP) and N-vinyl caprolactam (PVCap). The KHIs available to date are only effective in subcoolings up to 14 oC and their performance can be affected by the presence of other chemicals such as corrosion inhibitors. There have been attempts to develop a KHI evaluation method based on a hydrate precursor where the hydrate-forming gas was a binary mixture of methane and propane that forms structure II. In this work, we conduct experiments to investigate hydrate formation in the presence of hydrate precursors and the effects of KHI on the inhibition of hydrate re-formation simulating the cold start-up after remediation of hydratep plug.
Clathrate hydrate
Flow Assurance
Cabin pressurization
Subcooling
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The formation of methane−ethane (C1−C2) clathrate hydrate was studied with high-resolution, solid-state 13C NMR and density functional theory techniques. The 13C NMR experiments yield a number of significant findings: (1) the hydration number of C2(aq) is 26, (2) the initial quantity of C2−51262 sI hydrate cages outnumber C1−512 cages at 274 K, (3) C1−C2 sII hydrate forms at a C1−C2 gas phase composition where only sI hydrate is thermodynamically stable, (4) the initial composition of C1−C2 sII hydrate at 268 K contains less than the original amount of C1, (5) a quasi-liquid water layer solvating both C1 and C2 exists at 268 K, (6) any C1(qll) and C2(qll) present at 253 K is too small to be detected, (7) the initial amounts of C1−C2 sI and sII hydrates formed at 253 K are much smaller than those formed at 268 and 274 K, and (8) C1(aq), C2(aq) and C1(qll), C2(qll) facilitate the formation of C1−C2 sI and sII clathrate hydrate at 268 and 274 K, respectively. On the basis of these experimental observations, a model is developed that states that the aqueous hydration number of the most water-soluble clathrate hydrate former controls the structure of the clathrate hydrate that forms during the initial stages of the clathrate hydrate formation reaction. For methane−ethane clathrate hydrate, this means that ethane in a water liquid phase or quasi-liquid layer eliminates or adds two water molecules to its hydration shell to form the ethane-filled 51262 or 51264 cage building blocks of structure I or structure II clathrate hydrate, respectively. Density functional theory computations on methane-filled 512, 51262, and 51264 and ethane-filled 51262, 51263, and 51264 clathrate hydrate cages yield the stabilization energy of the gas-filled cages and provide theoretical evidence consistent with the experimentally based clathrate hydrate formation model. The proposed model is found to explain the results of other clathrate hydrate formation reactions.
Clathrate hydrate
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Gas Hydrate is considered as the main flow assurance concern in energy industry, especially in East Asia such as Malaysia, where the oil reservoirs include significant amount of methane gas. This issue has encouraged scientists to conduct serious studies for prediction of gas hydrate formation in order to efficiently prevent blockage of transportation line by solid hydrate. In fact, the flowability in any zone of pipeline will be at risk due to hydrate formation, especially the inactive parts of the flow. Inhibition methods for hydrate formation have been under constant investigations since early 1930’s when hydrate was found to be the main responsible component for gas transmission line blockage. However, usually hydrate prevention practice requires the large amount of chemical inhibitors, which in turn makes these methods significantly expensive. Therefore, an accurate prediction of flow behavior is required in order to estimate the possibility of hydrate formation in any part of flow, in order to optimize the amount of inhibitors or accurately design other preventive methods. In this study the main focus is on the available computer tools for hydrate formation predictions. Some software packages such as AspenHysys v 8.3, CSMHYD and Hydrate Plus have been analyzed and their outcome is compared to some experimental data. In addition, some correlations have been investigated in order to choose the most suitable tool for Hydrate formation prediction in pipeline. The result of this study can help Flow Assurance engineers to precisely predict where and when hydrate forms in order to prevent the environmental and safety crisis associated with its formation in pipeline.
Flow Assurance
Clathrate hydrate
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Gas hydrate represents a mixture of natural gas and water molecules formed at high pressures and low temperatures near the freezing point of water. Physically, the hydrates are ice-shaped and among the water molecules, there is a cavity filled by a hydrate gas called clathrate. The hydrates can be formed because there is gas injected in water molecules at high pressure condition having temperature above the freezing point of water. Then it is exposed to a force that can dissolve gas inside the water. A lot of research has been conducted to investigate the performance of the gas hydrate itself. The performances include the rate of hydrate formation, the hydrate stability, and the hydrate storage capacity. Several studies have been studied, among others, to observe the effect of initial gas injection pressure on gas hydrate process, the effect of rotation in a vessel tank as a container for gas hydrate formation, and the hydrate formation process on stirrer tank. One of the most important things in the gas hydrate process is how the hydrate can be formed, which can be seen from the rate of hydrate formation by investigating how much the gas pressure will penetrate into water molecules. It is due the hydrate formation requires low temperature and high pressure. However, a conditioning of the gas hydrate formation at high pressure and low temperature is a matter that requires considerable energy. Therefore, it is needed a system in which the pressure of hydrate formation is not too high. One method to lower the hydrate pressure in order to the hydrate-forming pressure is not too high, CO2 will be mixed to the gas hydrate. It is because CO2 is soluble in water molecules. It make an effect that the pressure of gas formation will be lower. In the previous research, it is showed that CO2 was able to make the pressure in methane gas mixture lower. By decreasing its pressure, CO2 is expected to improve the hydrate performances. The study was conducted by varying the percentage of CO2 volume from 0% to 100%. Each percentage of CO2 will be seen as its effect on the gas hydrate performance. The gas used in this experiment were propane-butane gas mixture of 50% each. The mixture of propane-butane gas and CO2 were then fed into the water molecules. The water used was a demine water of 50 cm3. The initial pressure of the formation rate was 0.3 MPa and the temperature formation was 273 K. Meanwhile, the temperature used to stabilize the hydrate was 268 K. The vessel tank, used to process the occurrence of hydrate has the capability of high pressure has a cavity diameter material of 4 cm, height 12 cm, 0.5 cm thick and total volume of 150 cm3. The vessel tanks were inserted into the cooling bath that was set at a temperature of 273 K. The results showed that as greater the CO2 content, as smaller the initial hydrate initiation phase, However, it has an impact to decrease the hydrate stability. For hydrate storage capacity performance, pure CO2 hydrate has the highest storage capacity, while the lowest storage capacity was CO2 with gas-CO2 mixed percentage of 50%. It shows that CO2 is capable to decrease the pressure effect on 50% composition variation.
Clathrate hydrate
Triple point
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Abstract Low temperature and high pressure conditions favor the formation of gas clathrate hydrates which is undesirable during oil and gas industries operation. The management of hydrate formation and plugging risk is essential for the flow assurance in the oil and gas production. This study aims to show how hydrate management in the deepwater gas well testing operations in the South China Sea can be optimized. To prevent the plugging of hydrate, three hydrate management strategies are investigated. The first method, injecting thermodynamic hydrate inhibitor (THI) is the most commonly used method to prevent hydrate formation. THI tracking is utilized to obtain the distribution of mono ethylene glycol (MEG) along the pipeline. The optimal dosage of MEG is calculated through further analysis. The second method, hydrate slurry flow technology is applied to the gas well. Pressure drop ratio (PDR) is defined to denote the hydrate blockage risk margin. The third method is the kinetic hydrate inhibitor (KHI) injection. The delayed effect of KHI on the hydrate formation induction time ensures that hydrates do not form in the pipe. This method is effective in reducing the injection amount of inhibitor. The problems of the three hydrate management strategies which should be paid attention to in industrial application are analyzed. This work promotes the understanding of hydrate management strategies and provides guidance for hydrate management optimization in oil and gas industry.
Flow Assurance
Clathrate hydrate
Cabin pressurization
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The hydrate is an important issue that the flow assurance has to face in the oil and gas industry, especially in the deepwater area. With high pressure and low temperature, the hydrate formation is easily happened and leads to plug in the pipeline. In addition to the traditional thermodynamic inhibitor, the low dosage hydrate inhibitors (LDHI) has been increasing used as a costly effective technology for gas hydrate control. The LDHI include kinetic hydrate inhibitor (KHI) and anti-agglomerant (AA), the former can inhibit the hydrate formation in the pipeline, and the latter can prevent the agglomeration and plug of hydrate particles. According to the properties of oil and gas of South China Sea, a new KHI and AA were developed, a field test of the KHI has been undertaken and the results indicate that it can prevent the hydrate formation and plug in the pipeline well, the lab evaluation of the developed AA is in progress and the field test will be performed by the next year.
Flow Assurance
Clathrate hydrate
Spark plug
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The flow assurance problem of pipelines in offshore production is becoming more and more serious because oil fields in more and more unusual environments have been brought in production.HCFC-141b and THF were selected as the substitutes to study the flow behavior and mechanism of hydrate blockage in pipelines on the newly built flow loop,which was a two pass loop consisting of a 42 mm diameter stainless pipe,30 m long.Slurry-like hydrates and slush-like hydrates were observed with the formation of hydrates in pipeline.There are critical hydrate volume concentrations of 37.5% for HCFC-141b hydrate slurry and 50.6% for THF hydrate slurry respectively.The pipeline would be free of hydrate blockage when the hydrate volume concentration was lower than the critical volume concentration; while otherwise the pipeline would be easily blocked.A safe region,which is defined according the critical hydrate volume concentrations,is firstly proposed for hydrate slurry,and it can be used to judge if the pipeline can be run safely or not.
Flow Assurance
Clathrate hydrate
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To better understand clathrate hydrate mechanisms, nuclear magnetic resonance (NMR) and viscosity measurements were employed to investigate tetrahydrofuran (THF) hydrate formation and dissociation processes. In NMR experiments, the proton spin lattice relaxation time (T1) of THF in deuterium oxide (D2O) was measured as the sample was cooled from room temperature down to the hydrate formation region. The D2O structural change around THF during this process was examined by monitoring the rotational activation energy of THF, which can be obtained from the slope of ln(1/T1) vs 1/T. No evidence of hydrate precursor formation in the hydrate region was found. T1 measurements of THF under constant subcooling temperature indicate that THF hydration shells do not undergo much structural rearrangement during induction. The T1 of THF was also measured as the sample was warmed back to room temperature after hydrate dissociation. T1 values of THF after hydrate dissociation were consistently smaller than those before hydrate formation and never returned to original values. It was proposed that this difference in T1 after hydrate dissociation indicates that the THF−D2O solution is more microscopically homogeneous than before hydrate formation. In viscosity experiments, a Champion Technologies hydrate rocking cell (CTHRC) was used to probe the residual viscosity phenomenon after Green Canyon (GC) gas hydrate as well as THF hydrate dissociation. The residual viscosity reported in the literature was observed after GC hydrate dissociation but not after THF hydrate dissociation. Because GC hydrate behavior involves significant amounts of gas mass transfer while THF hydrate does not, one might conclude that the residual viscosity observed after GC hydrate dissociation was likely caused by the supersaturated gas concentration and its general effect on solvent viscosity, not necessarily by a clathrate water structure lingering from the solid.
Clathrate hydrate
Tetrahydrofuran
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Citations (29)