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Collaborating Authors
Glenat, P.
Abstract Deepwater gas field development and/or gas field's production in remote locations require long tiebacks with low temperature and high pressure flow paths and complex seabed topographies. Hydrate formation and plugging is one of the most probable Flow Assurance risks under those conditions, and there is an urgent need for a better knowledge of these gas dominant systems behaviour regarding hydrate plug formation as well as effects of additives (Thermodynamic, KHI- and AA). Indeed, during the design phase of new field development, oil companies have to choose a hydrate mitigation strategy. To do that, important questions rapidly arise:What about the gas layer protection? How can non-volatile additives act/protect the non-wetted top of the line from condensed water hydrate formation in stratified flow? Is there a need to take/run some specific procedures (such as slug of additives) to avoid hydrate problems? The AHToL JIP phase 1 project's objective was to acquire knowledge and data in multiphase Lyre pilot loop in such gas dominant conditions. The paper presents Lyre loop pilot tests performed with gas dominant systems without additive. The hydrate formation was performed in multiphase flow. The pilot and tests results flow are shown. The influence of the flow pattern on the hydrate formation and plugging were investigated. Tests were performed in stratified flow and in annular flow. The water to hydrate conversion rates are calculated. Photos of hydrate deposits inside the flow loop are shown. The plugging mechanisms identified show a direct correlation with the flow pattern inside the line.
- Europe > United Kingdom (0.28)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
Hydrate Plug Management Using Electrically Trace Heating Pipe in Pipe: A Full Scale Experimental Study
Gainville, M. (IFP Energies Nouvelles) | Cassar, C. (IFP Energies Nouvelles) | Sinquin, A. (IFP Energies Nouvelles) | Tzotzi, Ch. (Technip) | Parenteau, T. (Technip) | Turner, D. (ExxonMobil Development Company) | Greaves, D. (ExxonMobil Development Company) | Bass, R. (ExxonMobil Development Company) | Decrin, M-K. (Total E&P) | Glenat, P. (Total E&P) | Gerard, Fl. (Total E&P) | Morgan, J.E.P. (Woodside Energy Limited) | Zakarian, E. (Woodside Energy Limited)
Abstract There are many ways to prevent hydrate formation in production flowline and riser systems. The most common and traditionally trusted means of prevention is a combination of thermal insulation during production and depressurization with chemical injection and inert fluid flushing during shutdown, all of which can be operationally expensive, as well as environmentally and logistically demanding on offshore real estate. Recently, actively heated pipelines are being considered for hydrate plug prevention, whereby heating is applied to maintain the production fluid operating temperature above the hydrate formation temperature either continuously during normal production, or intermittently during shutdown and restart periods. However, the transition from maintaining a minimum temperature in the production system to hydrate plug dissociation by using active heating is a change requiring qualification prior to operator implementation. The purpose of the work described here is to validate the use of active heated pipelines for safe hydrate plug dissociation.
- North America > United States (0.47)
- Europe > Norway (0.46)
- Research Report > New Finding (0.40)
- Research Report > Experimental Study (0.40)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BC-20 > Papa Terra Field (0.99)
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > PL 043 DS > Block 3/15 > Alwyn Area > Islay Field > Brent Formation (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Hydrates (1.00)
ABSTRACT: The addition of a small amount of flexible organic polymers in a turbulent flow can strongly decrease friction pressure drop, allowing thereby substantial increase in crude export pipeline capacity. This effect, known as "Drag Reduction", is widely implemented on various industrial sectors: petroleum, medicine, hydrodynamics, etc. Only a few tens of parts per million by weight of Drag Reducing Agents (DRA) are required, making these additives economically attractive. These long-chain polymers are known to be very sensitive to high shear and are for example completely destroyed through boosting pressure pumps in place throughout long export crude pipelines (> 300 km), requiring the installation of new DRA injection skids at the downstream of each pump station. However these long-chain polymers have been shown to be sensitive to mechanical degradation occurring during the transport within the pipeline, phenomenon which progressively reduces the overall DRA efficiency. An original experimental study, combining two experimental apparatus, a classical rheometer and a specially designed laboratory turbulent flow loop, was carried out to monitor such degradation phenomenon. Different commercial oil soluble DRAs have been tested on various fluids including crude oil and model kerosene, under a large range of experimental conditions in terms of geometrical configuration, temperature and flow rates. The experimental results highlight a clear link between degradation kinetics and flow dissipated energy and led to a patented law allowing the evaluation of DRA efficiency as a function of the dissipated energy, which is directly correlated to pipeline length. This new law is aimed at optimising polymer initial concentrations in order to achieve the desired DRA efficiency by covering the degradation which will occur during transport. Such model will allow better implementation of DRA usage in crude export pipes at the design development stage and not just using them for flow de-bottlenecking cases.
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (0.70)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.60)
Abstract The Canyon Express transportation system consists of two 12- inch flow lines running parallel from Camden Hills through Aconcagua and Kings Peak to Canyon Station Platform. The three subsea fields are in 6200 to 7250 ft. of water depth. Canyon Express is one of the longest subsea tiebacks in theGulf of Mexico. Production from the fields is predominantly methane gas with some condensate and formation water. The chosen hydrate mitigation strategy is continuous injection and regeneration of methanol (MeOH) for flow assurance. The Low-Dose Hydrate Inhibitor's (LDHI) were investigated because of increasing water production in the mid life of the Canyon Express production system. Both Anti-Agglomerants (AA's) and Kinetic Hydrate Inhibitors (KHI's) were evaluated for severity of operating conditions at Canyon Express. This paper presents the step evaluation process including the engineering and laboratory studies which were performed for evaluation of LDHI's. It highlights LDHI limitations and presents the field operational changes which both resulted in the non-implementation of this technology. Introduction With the deep and ultra-deepwater thrust in the oil and gas industry, long-distance subsea tiebacks are becoming a preferred field development option. At high pressures and low ambient temperatures, the multiphase fluid is in the hydrate region close to the wellhead requiring continuous injection of thermodynamic inhibitors. Severe operating conditions require high injection volumes of thermodynamic inhibitors to be outside of the hydrate regions resulting in high OPEX and challenging operability. LDHI's for long distance subsea tiebacks will be an optimal field development option resulting in lower treatment rates, pumping costs, and logistic costs. Risk associated with hydrate mitigation will result in comprehensive step evaluation of Low-Dose Hydrate Inhibitors for a long distance subsea tieback in ultra-deep water. Major operational drivers for transitioning from thermodynamic inhibitors to LDHI's for the Canyon Express System were identified. Canyon Express System The Canyon Express transportation system consists of two 12- inch flowlines running parallel from Camden Hills (Marathon Oil Company operated) through Aconcagua (Total operated) and Kings Peak (ATP operated) to a host platform (Canyon Station) located approximately forty miles north of the northernmost Kings Peak well. Production from the fields is predominantly gas with condensate and produced water. The wells are tied together via a ‘daisy-chain’ arrangement. The Canyon Express field and liquid management have been described in previous papers,. Refer to attached Canyon Express schematic, Figure A-1. During the period of this evaluation there were four producing wells on the easterly flow line and four producing wells on the westerly flow line. The two flow lines are loop connected at the ends and are isolated from one another via a subsea isolation valve located just upstream of MC305-1.
- Europe (1.00)
- North America > United States > Texas (0.29)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.42)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
- (2 more...)