: Introduction to Offshore Petroleum Production System

Yutaek Seo

Period Contents

1 Week General introduction, outline, goals, and definition

2 Week

Type of reservoir fluids : Dry gas / Wet gas / Gas condensate / Volatile oil / Black oil PVT laboratory testing : Constant mass expansion / Differential vaporization / Compositional analysis / : Oil densities and viscosity / SARA, Asphaltenes, WAT

3 Week Fluid sampling and characterization : Bottom hole samples / Drill stem test samples / Case studies

4-5 Week Thermodynamics and phase behavior : Ideal gas / Peng-Robinson (PR) / Soave-Redlich-Kwong (SRK) : Peneloux liquid density correction / Mixtures / Properties calculated from EoS

6 Week Subsea Field Development : Field configuration / Artificial rift / Well layout 7 Week Well components : Christmas tree / surface wellhead

8 Week Subsea manifolds/PLEM and subsea connections : Components / design / installation

9 Week Umbilical / risers / flowlines : Design criteria/ analysis

10 Week Flow regime : Horizontal and vertical flow / Stratified flow / Annular flow / Dispersed bubble flow / Slug flow

11 Week Flowline pressure drop : Frictional losses / Elevation losses / Acceleration losses / Errors in P calculation / Pipe wall roughness

12 Week Liquid hold up : Cause / Prediction / Field & experimental data / Three phase flow

13 Week Flow assurance issues : Hydrate/Wax/Asphaltene/Corrosion/Scale

14 Week Field operation : Operational procedures for offshore petroleum production

15 Week Application Example: Offshore platform (Pluto fields), Floating production system (Ichthys fields)

16 Week Final Test

Subsea development challenges

Res

. Pre

s. G

radi

ent

Subsea Wells Dry Wells

Tieback Distance 6 - 8 km 10 - 100 km

Lift, Boost and Separation Options

Flow Assurance Wax Hydrates Scale

Water D

epth

Pressure drop in production facilities

Artificial Lift

Artificial lift methods are used to continuously remove liquids from a liquid loaded gas well.

The lack of energy in a reservoir can affect the flow rate of oil, gas, or water and artificial lift is used to supplement the reservoir energy. Using this method, energy is transferred downhole and the fluid density in the wellbore is reduced.

Artificial lifts also boost well production by reducing bottomhole pressure at wells that are deemed not economically viable.

A variety of artificial lift methods are used, with each method configured for specific lifting requirements and operational constraints.

During the selection of the lift systems, elements such as reservoir and well parameters, and field development strategies should be taken into consideration.

Basic methods

The basic methods for artificial lift are : Gas lift : Subsea boosting : Electric submersible pumps.

Gas lift

The traditional artificial lifting methods are used to produce fluids from wells that are already dead or need to increase the production rate

Side pocket mandrel and gas lift valve

During the initial part of the field architecture survey, the need for gas lifting is assessed based on the following information:

a. Fluid composition and properties such as solution gas-oil

ratio, oil formation volume factor, oil viscosity, and gas compressibility factor;

b. Maximum water content, etc.; c. Multiphase flow correlations; d. Well profile, production rate data, bottomhole flowing

pressure, average reservoir pressure at midperforation, and surface gas-lift pressure as needed to optimize the gas-lift system.

Gas lifts employ additional high-pressure gas to supplement formation gas as shown in Figure 2-15.

Produced liquids are extracted by reducing fluid density in the wellbore, to lighten the hydrostatic column, or back-pressure, loads on formations.

Continuous injection is popular because it utilizes the energy from formation gas.

At specific depths, special gas lift valves will be injected with external gas, which mixes with produced liquid.

The pressure gradient will be reduced from the injection point to the surface. Bottomhole pressure reduction will create a pressure differential for required flow rates.

Insufficient drawdown can be remedied using instantaneous high-volume injection, or intermittent gas lift to displace slugs of liquid to the surface.

This condition will create surface gas handling difficulties apart from surges downhole resulting in sand production. Gas-lift expenditures depend on the gas source and pressure, but can be costly if additional surface compressors and processing facilities are needed.

Subsea pressure boosting

The impact on the production flow rate and pressure as a result of pressure boosting is illustrated in Figure 2-16.

: System resistance is characterized by the specific system configuration and water depth. : Natural well flow rate is dependent on the specific reservoir conditions. : As indicated in the figure, both the production flow rate and pressure are increased as a result of the pressure boost.

For a long tie-back and in a deepwater operating environment, the system resistance curve becomes steep, and the intersection with the production curve will be at a much lower flow rate.

Similarly, a low-pressure reservoir results in a production curve that starts out with a lower shut-in pressure and decreases faster. The intersection with the resistance curve will again be at a lower production rate.

Subsea pumps can be used to increase the pressure of the fluid.

The subsea pump systems are designed to operate for long periods of time without maintenance.

Regular maintenance may be required every 5 years due to general wear. The pumps are of a modular insert design and consist of a driver unit and a pumping unit. The driver can be either an electric motor or a water turbine.

The driver shaft power depends on production flow and required differential pressure increase, and single-driver units are available ranging from 200 kW to more than 2.5 MW.

In most applications, one single pump will be sufficient, but if required, several pumps can be installed in parallel to cater to a higher flow rate or in series to provide higher pressure.

Pumps are available to pump oil, water, or multiphase fluid. Such a boosting system is installed in the Ormen Lange gas field located 100 km (62 miles) off the northwest coast of Norway in water depths of 850 to 1150 m (2800 to 3800 ft).

Two main booster pump technologies are available : Positive displacement pump : Centrifugal booster pump.

Electric Submersible Pump (ESP)

ESP technology is an ideal solution to produce significantly higher fluid volumes and provide the necessary boost to deliver the production flow to the host platform.

ESP systems require a large electricity supply. Providing electricity to ESP systems, however, is less complex and more efficient than delivering gas to gas-lift systems.

The high-volume capacity, wide operating range, and efficiencies up to 40% higher than the gas-lift process make ESP systems more attractive for deepwater subsea wells.

Traditionally, ESP systems are installed downhole.

Economic benefits Seabed ESP systems can be deployed with vessels of

opportunity versus semi-submersible rigs, reducing both the overall cost of installation and intervention and deferred production resulting from a waiting period for a rig.

Seabed ESP systems can be configured to provide a backup system to maximize run life and minimize deferred production.

Some seabed ESP system alternatives use existing infrastructure to house the systems, which also significantly reduces overall development costs.

Seabed ESP booster systems are not as space constrained as in-well systems. Production from several wells can be boosted with only one seabed ESP booster system.

Vertical Booster Station : The vertical booster stations require installation of a large pipe, such as a 36-in (0.91 m). conductor pipe, by drilling or suction pile if the seabed is muddy.

The booster station can be located at any point between the well and host facility.

If more than one field is connected to the host production platform, the booster station may be closer to the platform and boost production from several fields.

In developments where several wells are in one seabed location, the booster station may be installed closer to the wells.

Horizontal booster station : The horizontal ESP system is a variant of the ESP jumper, placed on a permanent subsea base. The advantage of this system is the ease of changing out equipment and the ability to have systems in series, in parallel, or as redundant systems. : All of these configurations improve overall runtime and reduce any deferred production if one pumping system goes down. : Plus, these systems can be used for boosting pressure for the production wells or boosting seawater downhole for water injection. : The ESP booster systems can also be bypassed to clean the flow lines.

ESP Jumper system : The ESP jumper system configuration shown in Figure 2-18 is the most cost-effective seabed ESP boost system available. : This system places the ESP equipment in the existing subsea flowline jumper infrastructure either between the wellhead and the manifold or the manifold and the pipeline end termination.

The incremental costs of this system are negligible since the infrastructure is already a sunk cost and no significant modifications are necessary.

Like the other systems, ESP jumpers can boost one well, providing the opportunity for individual well optimization, or several wells, depending on the needs of the fields.

The ESP system can be installed in the jumper onshore to minimize costly seabed installation expenses. The lower costs associated with ESP jumpers make the technology ideal for brown field applications where existing subsea fields can benefit from seabed booster systems.

Subsea processing

Subsea processing (SSP) can be defined as any handling and treatment of the produced fluids for mitigating flow assurance issues prior to reaching the platform or onshore. This includes:

a. Boosting; b. Separation; c. Solids management; d. Heat exchanging; e. Gas treatment; f. Chemical injection

The benefits of introducing subsea processing in a field development could be:

a. Reduced total CAPEX, by reducing the topside processing and/or pipeline CAPEX;

b. Accelerated and/or increased production and/or recovery; c. Enabling marginal field developments, especially fields at

deepwater/ultra-deepwater depths and with long tie-backs; d. Extended production from existing fields; e. Enabling tie-in of satellite developments into existing

infrastructure by removing fluid; f. Handling constraints; g. Improved flow management; h. Reduced impact on the environment.

Subsea boosting, as explained in an earlier section, is one means of increasing the energy of the system.

Subsea separation can be based either on two- or three-phase separation:

a. Two-phase separators are used for separation of any gasliquid system such as gasoil, gaswater, and gascondensate systems.

b. Three-phase separators are used to separate the gas from liquid phase and water from oil.

Subsea processing evolution

TIME

CA

PAB

ILIT

Y /

CO

MPL

EXIT

Y

Multiphase & Injection Pumping

Water Removal & Debottlenecking

Full Subsea Processing

Key features of evolution Stepwise in capability and complexity Small steps to manage risk Modular system approach

Subsea Gas Compression

3 Phase Separation

Subsea Water Removal Boosting & Injection

A three-phase separator is useful for the crude consisting of all three phases, namely, oil, water, and gas, whereas a two-phase separator is used for the system consisting of two phases such as gasoil, gaswater, or gas condensate.

Further, subsea separation could have a positive effect on flow assurance, including the risk related to hydrate formation and internal corrosion protection derived from the presence of the produced water in combination with gas.

As opposed to the traditional methods of processing reservoir fluids at a process station, subsea processing holds great promise in that all of the processing to the point where the product is final salable crude is done at the seabed itself. This offers cost benefits and also improves recovery factors from the reservoir.

Other advantages include a lesser susceptibility to hydrate formation and lower operating expenditures.

SUBSEA PROCESSING EQUIPMENT

MULTI PHASE PUMP

Application: Well stream energy enhancement Advantages: Drawdown of wellhead pressure Increased production rates Increase reservoir recovery Increased tie-back distance Separated liquids evacuation Status: Helico-axial pumps in operation subsea Twinscrew pumps qualified pilot subsea application 2005

SUBSEA PROCESSING EQUIPMENT

INJECTION PUMP Application Water injection pressure boosting Advantages Increased injection rates Increased tie-back distance Ability to inject produced water or sea water subsea Status Pump designs well proven topside Critical parts qualified in MPP programme Detail design of production version complete

SUBSEA PROCESSING EQUIPMENT

SUBSEA GAS COMPRESSOR Application: Subsea gas compression Advantages: Drawdown of wellhead pressure Increased production rates Increase reservoir recovery Increased tie-back distance Separated gas evacuation High tolerance for liquid droplets Status: In development by various specialist

companies

SUBSEA PROCESSING EQUIPMENT

COMPACT SEPARATION TECHNOLOGY Application: Compact gas, oil and water 2 or 3 phase separation Advantages: Small size and weight Status: Separation performance qualified topside Gas/Liquid 2 phase unit in operation offshore Concept design for subsea unit complete

SUBSEA PROCESSING EQUIPMENT

COMPACT ELECTROSTATIC COALESCER Application: Removal of water from oil after separation Advantages: Small size and weight Oil polishing to 0.5% water in oil Status: Topside pilot unit on Petrojarl FPSO Design for subsea unit complete Subsea equipment components qualified Next step subsea pilot testing

HSP

Power Fluid

X-over

Injection Zone

Oil to surface

Production Zone

H-Sep

Application: Remove water from well stream and re-inject into reservoir Advantages: Improvement on production rate Improves reservoir recovery Produces export-quality oil Good quality injection water Status: Land base testing complete Offshore pilot testing next step

DOWNHOLE SEPARATION

SUBSEA PROCESSING EQUIPMENT

Well layout

Field development planners need to work closely with the reservoir and drilling engineers early in the planning stages to establish a good well location plan.

Once the reservoir is mapped and reservoir models created, the number of wells, types of wells, and their locations can be optimized.

Well layout is usually an exercise of balancing the need to space the wells out for good recovery of the reservoir fluids against the cost savings of grouping the wells in clusters.

Add to this the consideration of using extended reach wells, and the number of possible variables to consider becomes great.

A further consideration, reservoir conditions permitting, is the use of fewer, high production rate wells through horizontal well completions or other well technology. Here again, there are cost trade-off considerations.

Satellite well system

A satellite well is an individual subsea well. Figure 2-20 illustrates a typical satellite tie-back system.

: The wells are widely separated and the production is delivered by a single flowline from each well to a centrally located subsea manifold or production platform.

Various field layouts must be examined. This evaluation must involve hydraulic calculations and cost sensitivity analyses taking into consideration flowline cost, umbilical cost, and installation cost and flow assurance issues.

Template and Clustered well system

If subsea wells can be grouped closely together, the development cost will usually be less than that for an equivalent number of widely dispersed wells.

Well groupings may consist of satellite wells grouped in a cluster, or a well template, in which the well spacing is closely controlled by the template structure.

Clustered satellite wells

Clustered satellite subsea well developments are less expensive than widely spaced satellite wells mainly because of flowline and control umbilical savings.

If several satellite wells are in proximity to one another, a separate production manifold may be placed near the wells to collect the production from all of the wells and deliver it in a single production flowline that is connected to the production facility.

In addition, a single umbilical and umbilical terminal assembly (UTA) can be used between the well cluster and the production platform.

In the case of clustered satellite wells, wells may be placed from several meters to tens of meters from one another.

The wider well spacing is often dictated by a desire to be able to position the drilling rig over one well without imposing dropped object risk on adjacent wells.

It is hard to precisely control the spacing of individual satellite wells, so crossover piping and control umbilicals must be able to accommodate the variations in spacing.

Example: comparison study using OLGA simulation

Detailed design of manifold

Production well templates

Another way of clustering wells is by means of a well template. Well templates are structural weldments that are designed to

closely position a group of well conductors. Well templates may support two wells or more than a dozen wells.

Apart from reservoir considerations, the number of wells in a well template is only limited by the size of the well template that can be handled by the installation vessel.

Small templates are usually deployed from the drilling rig. Larger ones may require a special installation vessel with heavier lift capacity or better handling characteristics.

Benefits of production well templates as compared to clustered satellite wells:

a. Wells are precisely spaced. b. Manifold piping and valves can be incorporated. c. Piping and umbilical jumpers between the trees and manifolds may

be prefabricated and tested prior to deployment offshore. d. Piping and umbilical interfaces are less expensive than for clustered

wells. e. Installation time is reduced by modularizing much of the equipment. f. Short flowline piping distances (compared to a cluster) reduce the

problems associated with flow assurance (e.g., wax and hydrate formation) and the need for extensive pipe insulation.

g. Horizontal loads imposed by drilling can be taken by the template structure as opposed to the tree and conductor in the case of a satellite well.

Disadvantages of production well templates as compared to clustered satellite wells.

a. Design and fabrication time may be longer due to greater complexity.

b. There may be safety concerns related to simultaneous drilling and production operations.

c. Heavy templates may be more susceptible to subsurface instability, such as shallow-water flows.

d. There is less flexibility in determining well locations. e. ROV access may be limited due to space constraints.

Daisy chain

The daisy chain subsea wells consist of two or more subsea satellite wells joined by a common flowline (and possibly umbilical in series). Each subsea tree may have a choke installed to avoid pressure imbalances in the flows.

Using daisy-chained wells allows for the combined use of infield flowlines by more than one well, and may provide a continuous loop for round-trip pigging if needed.

The dual flowlines provide the capability for: a. Round trip pigging; b. Diverting both production flows into a single flowline if the

second is damaged; c. Individually testing the two wells whenever needed through

independent lines.

As more subsea wells are needed, the attraction of daisy chains disappears and a manifold becomes more feasible.

Advantages of a daisy chain completion a. Similar to a single satellite well, cost is only incurred if and when a

completion is purchased and installed; the operator doesnt have to purchase significant infrastructure before it is needed.

b. Some sharing of flowlines may be possible. c. Round trip pigging is possible. d. Wells are not mechanically linked and can therefore be located over

a wide area, which is especially important in oil fields where low permeability exists.

e. In situ access to the installed equipment by ROV or divers is good because of the absence of adjacent equipment.

f. Potential damage from dropped objects is constrained to (at worst) a single completion.

g. Simultaneous production and drilling does not present a problem.

Disadvantages of daisy chain wells include these: a. The possible need for subsea chokes on each well. b. Absence of a common datum for flowline connections and

umbilical tie-in c. Necessity for the drilling rig or dynamic positioning (DP) vessel to

relocate in order to reach another well.

Subsea field development assessment

Critical design factors may consist of a. Engineering and design; b. Cost and schedule involved; c. Well placement and completion complexity; d. Flexibility of field expansion; e. Ease of construction and fabrication for the subsea hardware; f. Intervention capability (easy, moderate, or difficult to intervene); g. Rig movement (offset from mean under extreme environmental

conditions); h. Installation and commissioning, such as ease of installation and

commissioning, flexibility of installation sequence; i. Reliability and risk of the field architecture; j. ROV accessibility.

The inputs from the entire project team are used to assign percentage weights to each of these design factors.

Normally, all of the various types of field layout designs, such as the subsea tie-back, subsea stand-alone, or subsea daisy chain, can be applied in the field.

Reliability, risk assessment, and economic balance are the dominant factors when deciding what kinds of field layout will be chosen.

Next Class : Well and tree components

: Introduction to Offshore Petroleum Production System 2Subsea development challengesPressure drop in production facilitiesArtificial LiftBasic methodsGas liftSide pocket mandrel and gas lift valve 9 10 11Subsea pressure boosting 13 14 15Electric Submersible Pump (ESP) 17 18 19 20 21 22Subsea processing 24 25 26 27Subsea processing evolution 29SUBSEA PROCESSING EQUIPMENTSUBSEA PROCESSING EQUIPMENTSUBSEA PROCESSING EQUIPMENTSUBSEA PROCESSING EQUIPMENTSUBSEA PROCESSING EQUIPMENTSUBSEA PROCESSING EQUIPMENTWell layoutSatellite well system 38Template and Clustered well systemClustered satellite wells 41 42 43 44Production well templates 46 47Daisy chain 49 50 51Subsea field development assessment 53 54