Hydrate Control Design Philosophies
Steady-state temperature calculations from the flow assurance process are used to indicate the flow rates and insulation systems that are needed to keep the system above the hydrate formation temperature during normal operation.Transient temperature calculations are used to examine the conditions of transient action such as start-up and shutdown process. It is essential for each part of the system to have adequate cooldown time.
Dosing of hydrate inhibitor is the way hydrate formation is controlled when system temperatures drop into the range in which hydrates are stable during the transient actions. Dosing calculations of thermodynamic hydrate inhibitor indicate how much inhibitor must be added to the produced water at a given system pressure. The inhibitor dosing requirements are used to determine the requirements for inhibitor storage, pumping capacities, and number of umbilical lines in order to ensure that the inhibitor can be delivered at the required rates for treating each subsea device during start-up and shut-down operations.
Contents
Selection of Hydrate Control
Injection rates of thermodynamic inhibitors are a function of water production and inhibitor dosage. Inhibitor dosage is a function of design temperature and pressure, and produced fluid composition. Water production multiplied by the methanol dosage is the inhibitor injection rate, which will change throughout field operating life due to typically decreasing operating pressures and increasing water production.
Hydrate control strategies for gas and oil systems are different. Gas systems are designed for continuous injection of a hydrate inhibitor. Water production is small, typically only the water of condensation. Inhibitor requirements are thus relatively small, of the order of 1 to 2 bbl MeOH/mmscf.
Oil systems produce free water. Continuous inhibition is generally too expensive so some alternative control system is adopted. Insulation is often used to control hydrates during normal production, and some combination of blowdown and methanol injection is used during start-up and shutdown. But insulation is costly, and the more serious drawback may be lengthening of the hydrate plug remediation time, because insulation limits the heat transfer required to melt the hydrate solid, for cases in which hydrates have formed.
The selection of hydrate mitigation and remediation strategies is based on technical and economic considerations and the decision is not always clear-cut. While continuous injection of THIs is expected to remain the most economic and technically feasible approach to hydrate control, LDHIs or subsea processing will offer advantages for some developments. Whatever the hydrate control strategy, these decisions are critical in the early design stage because of the many impacts on both the subsea and topside equipment selection and design.
The main benefits of the thermodynamic hydrate inhibitors are their effectiveness, reliability (provided sufficient quantities are injected), and proven track records. However, these benefits are outweighed by significant limitations, including the high volumes, high associated costs (both CAPEX and OPEX), and their toxicity and flammability. In addition, they are harmful to the environment and significant disposal into the environment is prohibited. Kinetic hydrate inhibitors are injected in much smaller quantities compared to thermodynamic inhibitors and therefore offer significant potential costs savings, depending on the pricing policies of major chemical suppliers. They are also typically nontoxic and environmentally friendly. Moreover, considerable field experience is nowavailable following a number of successful trials.
However, they have some important limitations, including restrictions on the degree of subcooling (typically only guaranteed for less than 10 C) and problems associated with residence times, which as implications for shutdowns. In addition, the effectiveness of KHIs appears to be system specific, meaning that testing programs are required prior to implementation. Unfortunately adequate testing can require appreciable quantities of production fluids, which may not be available, particularly for new field developments. Furthermore, KHIs can interact with other chemical inhibitors.
The benefits and limitations of anti-agglomerates are largely similar to those for KHIs, although AAs do not have the same subcooling limitations. However, there is uncertainty about the effectiveness of AAs under shutdown or low flow rate conditions and it is postulated that agglomeration may still proceed. In addition, the one major limitation of AAs compared to KHIs or THIs is that they are limited to lower water cuts due the requirement for a continuous hydrocarbon liquid phase. Finally, compared to both THIs and KHIs, field experience with AAs appears to be lacking, which is reflected by the relatively small number of publications available in the open literature.
Thermal management can assist with maintaining some room for response by assisting with adequate temperatures for both hydrate and paraffin control. Passive thermal management is by insulation or burial. Pipe-in-pipe and bundled systems can extend the production cooldown time before continuous hydrate inhibition is required. However, there may not be sufficient thermal capacity to provide the necessary cooldown time for a shutdown greater than 4 to 8 hours. Phase change material insulation systems that provide heat “storage” are beginning to appear as commercial systems. Burial can provide extended cooldown times due to the thermal mass of the soil. Warm-up and cooldown times can be optimized with insulation and thermal mass.
Both electrical and heating media systems belong to the active thermal management process. Heating media systems require pipe-in-pipe or bundle flowline designs to provide the flow area required for the circulation of the heating media. When design, installation, and corrosion management issues are successful, the heating media systems can be reliable. However, the heat transported is still limited by the carrier insulation and heat input at theplatform.
Cold Flow Technology
Cold flow technology is a completely new concept that is designed to solve hydrate blockage problems during steady-state operating conditions. It has been recently developed and is owned by SINTEF. It is different from the chemical-based technologies (THIs, LDHIs) and insulation/heating technologies for hydrate protection, and concerns the cost-effective flow of oil, gas, and water mixtures in deepwater production pipelines, from wellhead to processing facility without using chemicals to prevent hydrate or wax deposition. In cold flow technology the hydrate formation occurs under controlled conditions in specialized equipment. The formed hydrate particles flow easily with the bulk fluid mixture as slurry and do not form wall deposits or pipeline blockage. Cold flow technology is environmentally friendly because of the envisaged reduction in the use of bulk and specialty chemicals. This technology provides an exciting challenge and could result in significant economic savings.
Hydrate Control Design Process
The hydrate control design process in subsea hydrocarbons system is summarized as follows:
- Determine operating conditions: pressure, temperature,GOR,water cut.
- Obtain good representative samples of oil, gas, and water.
- Measure chemical composition and phase behavior.
- Analyze reservoir fluids to determine hydrate formation conditions.
- Perform hydrate prediction calculations.
- Estimate the effects of insulation and thermodynamic inhibitors.
- Determine thermodynamic hydrate inhibitor dosing and sizes of umbilical and inhibitor storage; consider the use of LDHIs.
Hydrate Control Design and Operating Guidelines
The guidelines utilized for hydrate control in subsea hydrocarbon system designs and operations are summarized as follows:
- Keep the entire production system out of the hydrate formation envelope during all operations. Current knowledge is not sufficient to design a system that can operate in the hydrate region without hydrate or blockage formation.
- Inject thermodynamic inhibitors at the subsea tree to prevent the formation of hydrates in the choke and downstream during transient operations.
- Use LDHIs only for transient start-up/shutdown operations and not for continuous operation.
- Insulate flowlines and risers from heat loss during normal operation and to provide cooldown time during shutdown. Insulation of subsea equipment (trees, jumpers, and manifolds) should also be done.
- Consider wellbore insulation to provide fast warm-up during restart operations and to increase operating temperatures during low flow rate operation.
- Determine minimum production rates and flowing wellhead temperatures and check consistency with technical and economic criteria.
- Establish well and flowline start-up rates to minimize inhibitor injection while assuring that the system warms in an acceptable amount of time.
- Ramp-up well production rates sufficiently fast to outrun hydrate blockage formation in wellbores.
- Provide system design and operating strategies to ensure the system can be safely shut down.
- Monitor water production from individual wells.
- Locate SCSSVs at a depth where the geothermal temperature is higher than the hydrate temperature at shut-down pressure.
- Remediate hydrate blockages via depressurization or heating.
References
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[8] S. Cochran, Hydrate Control, Remediation Best, Practices in Deepwater Oil Developments, OTC 15255 (2003).
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[10] F.M. Pattee, F. Kopp, Impact of Electrically-Heated Systems on the Operation of Deep Water Subsea Oil Flowlines, OTC11894, Offshore Technology Conference, Houston, Texas, 2000. May.
[11] P.F. Pickering, B. Edmonds, R.A.S. Moorwood, R. Szczepanski, M.J. Watson, Evaluating New Chemicals and Alternatives for Mitigating Hydrates in Oil & Gas Production, IIR Conference, Aberdeen, Scotland, 2001.
[12] J.S. Gudmundsson, Cold Flow Hydrate Technology, 4th International Conference on Gas Hydrates, Yokohama, Japan (2002). May.
[13] D. Lysne, Ultra Long Tie-Backs in Arctic Environments with the SINTEF-BP Cold Flow Concept, Oil and Gas Developments in Arctic and Cold Regions, U.S.–Norway Oil & Gas Industry Summit, Houston, Texas, 2005. March.
