Eni Exploration & Production Division
In the last 10 years, more than half of new global oil and gas reserves have been discovered offshore, much of it in deepwater. Usually such hydrocarbons reservoirs are in remote areas many kilometers from existing facilities.
For marginal fields with relatively small reserves, maximizing production is crucial to economic development.
Subsea processing, coupled with innovative field architectures, is one attractive tool currently used by the oil and gas industry to open new opportunities and to achieve more effective development of marginal reservoirs.
Currently Eni Exploration & Production Division is committed to development scenarios characterized by satellite fields in conventional and deepwater areas, severe environmental conditions, and sensitive areas. For these scenarios, a development scheme with long tieback to shore or existing offshore facilities, joined to installation of processing equipment on the seabed, can be an effective solution from both technical and economic points of view.
Innovative solutions need to be found to develop and enhance recovery from these challenging reservoirs mainly because standard engineering methods and technological solutions have intrinsic limits.
A marginal field is usually defined as "a field that may not produce enough net income to make it worth developing at a given time; should technical or economic conditions change, such a field may become commercial." Therefore, marginal fields are a challenge to exploit in a cost-effective manner, especially considering capex/opex minimization, reserves/revenues enhancement, and standardization with existing infrastructures or equipment.
|Comparison of oil (left) and water (red) and liquid (black) production (right) for do-nothing (dashed lines) and boosted configurations. The comparison is of oil production rate profiles with and without subsea boosting. Considering the total oil production rate curves, MPP installation can extend field life and increase production in subsequent years.|
Satellite fields are, in most cases, constituted of a reservoir too small to be considered a stand-alone project and to justify the costs associated to its own surface processing facilities and flowlines. To be economically viable, such fields need to share the cost of the surface and subsea facilities with the larger main development.
However, a satellite field can be produced by tieback to a nearby existing host offshore facility using a complete subsea architecture solution or a minimal floating facility (floating production unit) when distance from the host, flow assurance issues (including operational strategy), or existing topside treatment capacity limitation render subsea tieback an unfavorable option.
To remediate such transportability and subsea umbilical, riser, and flowline (SURF) system thermal performance issues (linked to hydrates for example), new subsea processing technologies are becoming viable options to improve technical and economic performance of these types of field development.
Different devices have been developed to increase fluid pressure. These include multiphase pumping, liquid pumping, and wet gas compression. Recently, technologies to separate the gas phase from a liquid stream and produced water from hydrocarbons have been installed and tested.
To obtain particular benefits for the production system, separation and boosting technologies are deployed together, actively enhancing each other. Such subsea processing devices also are an enabling evolution for subsea field architecture, opening the way to solutions other than conventional loop like single flowline, coupled with a non-insulated service line or electrically heated and hybrid loops.
Field production with conventional loop or single production line has been simulated from a facility point of view to investigate the impact of subsea processing devices application (separation and/or boosting). In particular, raw well stream boosting and subsea gas/liquid separation performed at the wellhead or riser base have been analyzed.
Field development architectures
The most common subsea tieback architecture is the conventional loop, consisting of two insulated production lines and risers connected at subsea manifold headers and in communication by means of a dedicated pigging loop. This offers the greatest operating flexibility and redundancy because it is possible to manage production at different pressure levels in the two branches, the well testing operation is eased, turn-down ability is at top, and pigging ability is guaranteed.
Shutdown is managed by dead oil or diesel flushing. Conventional loop seems to be the correct solution for medium-short tieback, but when the distance is more than 20 km (12.4 mi), or reservoir temperature is in the range of 50-60°C (122-140ºF) or lower, the limits of this architecture immediately appear. Assuming, for example, a tieback of 20 km (12.4 mi), coupled with a dead oil displacement velocity of 1 m/sec (3.3 ft/sec) when pig is launched, the time for a complete loop flushing will exceed 11 hours. Considering a minimum of six hours for no touch time and well jumpers methanol displacement plus loop depressurization, the cool down time (CDT) requirement will exceed 17 hours.
Moreover, since the marginal field tied back to the central host is generally an infilling during facility operating life, displacement time of already existing field loops or flowlines shall be taken into account in the global CDT requirements calculation. The result is that the satellite field tieback requires double flowlines, often with an overall heat transfer coefficient lower than 0.6 W/m2K, practically at the limit of pipe-in-pipe technology.
Single line concept, looped with a service line (bare or with light insulation), could decrease the associated development capex due to simpler flowline design by lower CDT requirements.
Referring to the example, saving a minimum of five hours on CDT could be achieved thanks to this architecture, relaxing insulation needs and allowing standard and cheaper pipe technology. The service line will be the same diameter as the production line if pigging is activated from the topside facilities, or lower diameter with a subsea pig launcher (so far not common for routine operations).
The main drawbacks are less flexibility and turn-down ability due to the single production path.
As an alternative to a single production line with service line, an electrically heated single line represents a solution when the tieback distance renders all standard solutions technically and economically unattractive. Direct electrical heating or heat tracing (by electric cables or hot water heated bundle) generally are the methods used. Depending on the wellhead flowing temperature and the fluid hydrate formation curve or wax appearance temperature, electrical heating could be used in steady-state operations or only for transient, after a shutdown, until a field restart, or for a turn-down operation.
The typical advantage of conventional architecture with a double flowline is saving one flowline and riser, other than preservation of facilities on topsides. The trade-off is that electrical heating has to be implemented.
Subsea multiphase boosting
Subsea boosting can add energy to the produced fluid directly on the seabed to partially or completely overcome frictional and hydrostatic losses in the subsea flowlines and risers. This means that, due to less backpressure on the system, flowing tubing head pressure can be lowered and thus flowing bottomhole pressure is reduced, allowing more fluids to be produced due to increased drawdown.
The result is that subsea boosting can increase the production rate and reserve recovery from a lower abandonment pressure. Especially for a low pressure/low quality oil reservoir (not rare for marginal or satellite fields), it could represent an enabler when tieback distance, water depth, and fluid characteristics (low temperature, low GOR, or high viscosity) make the recovery particularly poor and the field development economic unfavorable.
Subsea multiphase boosting technology has evolved rapidly during recent years, and more than 30 field applications have been achieved.
Since each pump technology has its particular features, accurate pump selection is recommended to target a selected field application, keeping in mind typical challenges that could lower attractiveness of multiphase boosting technology or represent in some cases real show-stoppers. They can be related to multiphase fluid dynamic (slugs, transient operations, or restart), production fluid characteristics (viscosity, emulsion and foaming tendency, asphaltene scaling/naphthenate deposition), reservoir behavior and response to bottomhole pressure lowering, well completion design (maximum drawdown to avoid formation damage), sand and solids production, synergy with other IOR methods (water and gas injection, bottomhole or riser-base gas lift), subsea field characteristics (water depth, tieback distance, or layout architecture).
Moreover, boosting system reliability (not only relating the pump itself) should be deemed among the top priorities, considering, particularly in case of an unplanned failure event, subsea intervention time and replacement cost, limited subsea access for maintenance, and missed revenues due to pump stop.
Brownfield development case
This brownfield is an oil field in the Mediterranean Sea, in production since early 2000, approximately 100 km (62 mi) from shore in about 300 m (984.25 ft) of water. Oil, with 25° API density and GOR in the range of 500 cf/bbl (varying during life), is affected by the presence of wax (WAT = 36°C) and scales. The reservoir is characterized by a strong aquifer that helps mitigate production pressure-depletion issues.
Four subsea wells cluster around a manifold, approximately 5 km (3.1 mi) from an existing platform, and connected by two insulated 8-in. production lines. The dual 8-in. flowline system is arranged in a loop through the pipeline end manifold (PLEM) to allow pigging, depressurization, and diesel flushing of the flowlines. A 3-in. service line is also provided to allow general well services/operational interventions.
The field shows slightly decreased production profiles and shorter forecasted duration than that made during project development, mainly due to a faster increase of water cut. Even though the strong aquifer helps in pressure support, reservoir pressure has been insufficient to overcome an increasing hydrostatic head, thus leading to decreased field production over time compared with the initial plateau.
As a consequence, the subsea development operative life may be affected in future years due to anticipated well shutdown.
After a pre-screening evaluation, taking into account technology availability/readiness and a rough capex and time estimation for deployment, subsea multiphase boosting has been selected to mitigate the described reservoir issue and to enhance deliverability and production performance. The following were considered:
- Analysis of existing subsea field layout and tie-in points availability
- Availability of platform power supply for subsea pump
- Availability of free space on platform deck for power and control systems
- Free J-tube availability
- Impact on existing and new/planned topside treatment facilities.
Production enhancement evaluation
The first step to determine the production increase with subsea multiphase boosting equipment is to evaluate historical production data and well performances. The history match of the reservoir model has been performed and wells VLP (vertical lift performance)updated with the latest production fluid data.
Flow rates, flowing tubing head pressure, manifold pressure, separator pressure, flowing bottom and wellhead temperature, fluid composition, GOR, and WC are the main parameters screened.
For each subsea well, the following production profiles were generated:
- Base case: Production profile with no action to improve reservoir issue
- MPP (multiphase pumping) case: Maximum liquid production increased in order to maximize oil recovery.
It should be noted that MPP case profiles are characterized by the following constraints with respect to the Base case:
- Increased maximum water cut limit from 60% (typical value when production wells shut-in in natural depletion) to 80% (on the basis of performed wells restart analysis)
- Maximum well drawdown to not damage reservoir formation and well completion, equal to 500 psia
- Flowing wellhead abandonment pressure reduced from 350 (Base case) to 100 psia (MPP case). It should be highlighted that the wellhead pressure of 350 psia is absolutely insufficient to deliver the oil production to topside first stage separator (pressure of 300 psia). An FTHP (flowing tubing head pressure) around 600 psia fits better with actual manifold flowing pressure, allowing production to reach the topside separator, and 350 psia could be reached if all subsea production is switched to a second-stage separator (50 psia), with negative impact on separation performances and on compressor duty. It means that multiphase boosting is actually benchmarked with a case foreseeing production delivery to a second-stage separator, which in reality does not represent a Base case, but an operational strategy that could be pursued as "back-up" in future years. Nevertheless, this approach adds a sort of conservatism to the comparison in terms of added production/reserves and wells life extension.
Comparing oil production rate profiles with and without introduction of subsea boosting in the field, and considering the total oil production rate curves, MPP installation allows extended field life and increased production in following years.
The summarized results are:
- + 40% of oil production @ year one
- + 70% of oil production @ year three
- + 25% cumulated oil recovery over the entire subsea cluster life
- + Three years of production
- + 55% @ year one, + 150% @ year three of liquid production. Maximum liquid rate is fixed by facilities constraint.
Transportability analysis is intended to provide a hydraulic characterization of the subsea production system, accounting for the implementation of a boosting system. Production characterization has been carried out through the following:
- Start-up analysis: Intended to check streaming production capability after the increased water production during the extended boosting production period
- Actual flow verification and pump requirements: Both analyses are intended to characterize production fluid inside the boosting system and to evaluate characteristic parameters for optimized selection of pump technology
- Pressure drop analysis: Intended to evaluate the pressure drop of streamed fluid from production manifold to arrival platform over years.
The start-up analysis has been addressed to verify the pump functionality, eventual system criticality, and, overall, to demonstrate that wells can restart even when water cut increases. The analysis uses a simplified model to fit historical data, and then was extended using a complete well model to simulate steady-state and transient conditions as shutdown and start-up. The steps are:
- 1. Preliminary tuning and sensitivity analysis to assess the numerical model
- 2. Steady-state analysis to determine the theoretical well limitation in terms of production
- 3. Transient simulations to determine the well limitation in terms of restartability.
It has been demonstrated that, when MPP is implemented, the water cut threshold is for all four wells is around 80%. Higher than that, restartability is not guaranteed due to flow instabilities along production tubing and flowlines.
Actual inlet flow verification and pressure drop analysis have been carried out to find out inlet GVF, pump differential pressure, and power requirements for different suction pressures, 100 and 150 psia, over the entire field life. Finally, subsea multiphase pump selection, boosting module sizing, and umbilical design have been performed to fully understand the impact on existing facilities.
This article is based on a presentation that won a "Best Paper" award at the Deep Offshore Technology International Conference & Exhibition, held in New Orleans, Louisiana, USA, Oct. 11-13, 2011.
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