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Cold finger tests are a standard method for testing paraffin inhibitors, but there is no standard testing protocol, and sometimes different labs can see inconsistent results. Shell and BHGE studied the root causes of these issues. As operators rely on longer subsea tiebacks, an upward trend in the number of plugs caused by paraffins and hydrates has been seen. New prevention and remediation methods are discussed to help solve these challenges. A test method is being developed to screen paraffin chemistries in the presence of brine, closer resembling dynamic field conditions.
A computational fluid dynamics model is proposed to analyze the effect of hydrate flow in pipelines using multiphase-flow-modeling techniques. The results will identify the cause of pipeline failure, regions of maximum stress in the pipeline, and plastic deformation of the pipeline. The 9th International Conference on Gas Hydrates featured discussions on key advancements in flow assurance, including the concept of risk management and anti-agglomerates being applicable strategies in transient operations. A BP flow assurance manager explains a methodology for determining and mitigating flow assurance risks. A BP flow assurance engineer discusses the shift in hydrate management strategy from complete avoidance to risk mitigation for an offshore dry tree facility.
As operators rely on longer subsea tiebacks, an upward trend in the number of plugs caused by paraffins and hydrates has been seen. New prevention and remediation methods are discussed to help solve these challenges. A former technical manager with Petrobras discusses the development of the company’s flow assurance philosophies and strategies.
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Summary The common occurrence of massive methane hydrate in numerous gas-chimney structures, located in Joetsu Basin, Sea of Japan, has stimulated great interest in academia, industry, and national institutes to develop technologies that produce the potential energy resource. Unlike other deep methane-hydrate deposits in formations a few hundred meters below the seafloor (mBSF), the hydratechimney structures are at the seafloor or up to 100 mBSF; therefore, previously field-tested production methods such as depressurization are not applicable. In this work, we proposed a new potential production method of jetting from the openhole section of a wellbore to excavate the hydrate bearing. However, jetting will create large empty chambers below the seafloor and could possibly jeopardize the stability and safety of wellheads and the production facility on the seafloor. This paper presents a 3D geomechanical simulation study to evaluate the feasibility of the jetting method to produce methane from the hydrate chimneys in the Sea of Japan. Dynamic numerical simulation using a 3D finite-element simulator was conducted to simulate the jetting process to excavate a 16-m-diameter chamber from the bottom of the borehole (approximately 100 mBSF) progressively up to the bottom of the conductor of the wellbore, approximately 10 mBSF. The numerical simulation shows that jetting is likely to be feasible because all simulation cases resulted in tolerable vertical displacement and equivalent plastic strain under ideal conditions [e.g., lateral homogeneous formation, constant chamber pressure (equal to formation pore pressure), and blowout-preventer (BOP) weight of 20 tons]. In these cases, the plastic zone only extends to a limited area (10-20 cm) from the sidewall. Additional complexities were considered in the numerical simulation to evaluate the operational risks during actual jetting operations, such as faulting, fluctuation of chamber pressure, and change of BOP weights. This numerical simulation evaluated potential risks related to jetting operations of hydrate chimneys in the Sea of Japan and provided critical information for the engineering design of the proposed field test of jetting operations to produce this valuable resource in the Sea of Japan. Introduction Methane hydrate is an ice-like compound with gas molecules trapped in the cage of water molecules (Sloan and Koh 2008).
Kumar, Asheesh (Centre for Long Subsea Tiebacks, Department of Chemical Engineering, The University of Western Australia, 35 Stirling Hwy, Crawley WA 6009, Australia) | Di Lorenzo, Mauricio (CSIRO Energy, 26 Dick Perry Avenue, Kensington WA 6151, Australia) | Kozielski, Karen (CSIRO Energy, 26 Dick Perry Avenue, Kensington WA 6151, Australia) | Glénat, Philippe (TOTAL S.A.– CSTJF, Avenue Larribau, Pau Cedex 64018, France) | F. May, Eric (Fluid Science and Resources Division, Department of Chemical Engineering, The University of Western Australia, 35 Stirling Hwy, Crawley WA 6009, Australia) | M. Aman, Zachary (Centre for Long Subsea Tiebacks, Department of Chemical Engineering, The University of Western Australia, 35 Stirling Hwy, Crawley WA 6009, Australia)
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.
Sadeq, Dhifaf (University of Baghdad – Department of Petroleum Engineering) | Al-Fatlawi, Omar (University of Baghdad – Department of Petroleum Engineering) | Iglauer, Stefan (Edith Cowan University) | Lebedev, Maxim (Curtin University) | Smith, Callum (Curtin University) | Barifcani, Ahmed (Curtin University)
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 N2 + CH4 and N2 + CO4 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.
Kakitani, Celina (Federal University of Technology of Parana UTFPR) | Marques, Daniela C. (Federal University of Technology of Parana UTFPR) | Neto, Moisés A. Marcelino (Federal University of Technology of Parana UTFPR) | Teixeira, Adriana (Petrobras Research Center CENPES) | Valim, Leandro S. (Petrobras Research Center CENPES) | Morales, Rigoberto E. M. (Federal University of Technology of Parana UTFPR) | Sum, Amadeu K. (Colorado School of Mines)
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.
Elechi, Virtue Urunwo (Ace-Cefor, University of Port Harcourt) | Ikiensikimama, Sunday Sunday (University of Port Harcourt) | Akaranta, Onyewuchi (University of Port Harcourt) | Ajienka, Joseph Atubokiki (University of Port Harcourt) | Onyekonwu, Mike Obi (University of Port Harcourt) | Okon, Okon Efiong (University of Port Harcourt)
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.
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: 1. Development and installation of the PMS resulted in reducing the operating cost.