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Current technology limits the distance over which subsea produced well fluids may be transported to approximately 10-15 miles. Many offshore leases exist in water depths in the order of 4,000 feet that could require transportation distances of 50-60 miles. The prevention of hydrate formation in the flowline is of concern for this service. Injecting a chemical inhibitor has typically been considered as the primary method for preventing hydrate formation. The current knowledge of subsea insulation, particularly for deepwater applications, is very limited.
The purpose of this study is to develop data needed to evaluate the effectiveness of flowline insulating systems in maintaining the fluid temperature above the hydrate formation temperature for a typical Gulf of Mexico application.
As oil and gas exploration moves into deeper waters offshore, flow assurance challenges become more prevalent and system design must address these issues from a fresh perspective. In addition to structural and economic issues, the decision to employ either a wet tree (subsea) or dry tree solution needs to especially consider the flow assurance aspects that ultradeepwater production presents. The riser, rather than the flowline, will now dominate the overall hydraulic and thermodynamic performance of the system. An increased liquid column height in the riser, a greater potential energy change, and an enhanced Joule-Thomson effect will all contribute to significant temperature and pressure drops for an ultradeepwater riser, relative to its shallow water counterpart.
Dry trees are traditionally perceived as having less severe flow assurance issues than subsea tiebacks, primarily because of easier access to the tubing string if wax or hydrates are formed. However, aside from significant temperature losses in the riser, dry trees in ultradeepwater are particularly susceptible to hydrate formation upon shutdown. Because of warmer seabed temperatures and lower reservoir pressures, shallow water dry tree risers can provide adequate cooldown times with only minimal insulation. For ultradeepwater developments, the same shallow water dry tree design can fall into the hydrate formation region within two to three hours.
For both the dry tree and wet tree riser systems, it may not be possible to depressurize the system below hydrate formation conditions without gas lift (which may not be available for an emergency shutdown). The focus of this discussion is to evaluate the merits and drawbacks for both wet and dry tree systems from a flow assurance standpoint in ultradeepwater.
For oilfield developments in ultradeepwater, flow assurance issues can have a significant impact on the final system design. Therefore, it is necessary to consider both the structural and flow assurance requirements simultaneously when designing the optimal production system. Once a specific riser type has been determined to be structurally feasible in ultradeepwater, the flow assurance aspects may prove to be the bottleneck in implementation of this configuration. Conversely, the flow assurance assessment may lead to system requirements that are structurally unachievable at these water depths. Both of these issues, along with the economic cost associated with each, need to be viewed together in order to arrive at a viable solution.
It is imperative that all relevant flow assurance issues be addressed as early as possible, preferably in the conceptual design phase, to properly define the optimal production system for a given development. More and more, the oil industry is conducting parametric studies of their developments, evaluating a wide range of possible operating conditions in order to properly evaluate the merits and pitfalls of both subsea tiebacks and dry tree completions before deciding on which system to implement. The following sections discuss the flow assurance issues for a hypothetical black oil field in 7,000 ft. water depth for both a subsea tieback and dry tree riser option. At these water depths, the transient behavior of the system (cooldown, depressurization, etc.) becomes increasingly important and will often dictate the system design. Whether or not to develop a field with a subsea tieback or a dry tree solution obviously entails a variety of inputs other than just flow assurance issues, namely reliability and capital expenditure. However, proper flow assurance work early on can better frame the problem and alert the operator to potential issues that may be detrimental to the development.
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Deepwater developments such as the one depicted in Fig 1 rely on production flowlines to carry raw, production flowlines to carry raw, unprocessed reservoir fluid, called full wellstream (FWS) production, from wells to production facilities. As the search for reserves has taken the petroleum industry into deeper water and colder environments, the feasibility of producing FWS lay become questionable due to the possibility of hydrates in the flowlines. possibility of hydrates in the flowlines. The lower capital investment of FWS production flowlines is also attractive production flowlines is also attractive in shallower water. Even here, the risk of hydrates raises questions of feasibility in shallow, cold water environments.
When hydrates form in production streams, they can pose problems with economic consequences. Field experience indicates that hydrates occasionally obstruct production flowpaths (Ref 1 and 2). In the event of a partial obstruction, hydrate formation is a nuisance, slowing the production stream until the obstruction can be removed. And, in the event of a complete obstruction, full stoppage of production can last for weeks while production can last for weeks while mobilizing equipment to remove the obstruction. The cost of the mobilization on top of the lost revenue from the interruption in production can have serious economic production can have serious economic repercussions.
Figure 2 is a hydrate formation curve for a crude oil reservoir fluid with a gas-oil-ration (GOR) of 1000 SCF/STB (177 SCM/STCM). Note that increasing pressure or decreasing temperature favours hydrate formation. The worst exposure to hydrate formation usually is associated with a prolonged interruption in prolonged interruption in production, when the pressure rises production, when the pressure rises to shut-in wellhead pressure (SIWHP) and the contents of the flowline cool to seabed temperature. While hydrate formation will be more likely in deep water, even at typical seabed temperatures in the North Sea (40-45 degrees F or 4-7 degrees C), hydrate formation is possible.
2 HYDRATE MITIGATION STUDY
A study was conducted to identify methods of supporting FWS production in a hydrate forming environment. The study was set in the context of the system depicted in Fig 1 to exploit an oil field yielding a crude with a GOR of 1000 SCF/STB (177 SCM/STCM). The water depth at the field location was 2000 ft (610m). The temperature on the seabed was 38 degrees F (3.3 degrees C). The search for hydrate mitigating techniques was confined to existing technology. Only those alternatives which were both feasible and cost effective were carried through the study. Feasibility and cost effectiveness were weighed for the whole path from the wells through the production facilities.
The field development plan specified water injection to maintain reservoir pressure. Since gas sales had been pressure. Since gas sales had been ruled out, produced gas would be reinjected into the reservoir. A portion of the wells at the multiwell portion of the wells at the multiwell subsea templates were designated as water injection wells and gas injection wells. The single satellite wells were production wells. All satellite wells and template wells were completed for through-flowline (TFL) maintenance. The single satellite wells required a pair of 3-1/2-inch (90mm) TFL pair of 3-1/2-inch (90mm) TFL flowlines which doubled as FWS production flowlines. Each template production flowlines. Each template required a total of five lines to connect it with the riser based manifold:
Abstract Risk of gas hydrates occurring in subsea flowlines presents serious problems to offshore oil and gas production operations. Hydrate incidents can occur in oil and gas production systems provided that the favourable compositional mix and thermodynamic conditions exist. The principal method used to mitigate hydrates in subsea flowlines is the injection of hydrate inhibitor chemicals. Thermodynamic hydrate inhibitors (THIs) have traditionally been used but these have disadvantages, namely high OPEX with increasing chemical volume demand, space constraints, high CAPEX, and safety and toxicity concerns. Recently, low dosage hydrate inhibitors (LDHIs) such as kinetic hydrate inhibitors (KHIs) and antiagglomerants (AAs) which offer advantages of minimal volume and space requirements have received considerable attention. However, widespread application of these new classes of inhibitors has been limited by yet a number of concerns including water-cut and/or subcooling temperature range limits, lack of predictive models, toxicity, biodegradability, compatibility, and produced water quality and disposal issues. This paper presents a case study of an alternative "do-nothing" operational technique involving the comingle flow of well streams from different reservoirs at a pre-determined volume flow ratio, with temperature monitoring. Effective well-stream volume flow ratio was determined by predictive model studies of fliud systems hydrate equilibrium and pipeline operating envelops, followed by field trials. Results show that risk of hydrates in flowlines with multi reservoir fluids can be minimised by the control of the in-line fluid compositional mix by conventional flow control operation. Conceptual assessment studies suggest that this method of hydrate control could provide a cost-effective alternative to the use of chemical inhibitors, on a short-medium term basis, particularly in cases of seasonal hydrates and minimum-facility marginal oil production. Further study of effect of salinity of the produced crude on hydrate formation, given anticipated water-cut breakthrough with time, would further confirm the economics of this strategy on a field lifecycle basis.