Scenario Evaluation for Subsea Production System
Tlago R Estefen^ Daniel S. Werneck% Diogo do Amaral% Joao Paulo C. Jorge',
Leandro C. Trovoado", Jian Su«, Edson Labanca'' and Segen F. Estefen»
a COPPE/ Federal University o f Rio de Janeiro, Brazil. Corresponding author: segen@lts.coppe.ufrJ.br
b P E T R O B R A S
Abstract
Scenarios f o r a subsea production system are evaluated considering technical feasibility, operational reliability and financial r e t u r n for the investment. A case study based on an offshore gas field is adopted as well as three associated subsea production scenarios i n order to p e r f o r m the relevant analyses which could lead to the recommendation of the best option. The field is located at a distance o f 160 k m f r o m the Brazilian coast at the water depth o f 500 m , decreasing to 180 m at 140 k m f r o m the coast and then progressively up to the beach. Three different scenarios f o r the subsea production systems are proposed. Semi-submersible (scenario 1) distant 160 k m f r o m the coast at water depth o f 500 m and the subsea arrangement constituted o f eight satellite wells. Jacket p l a t f o r m (scenario 2) distant 140 k m from the coast at water depth o f 180 m . Scenario 3 is a Subsea to Beach system (without p l a t f o r m ) . Initially, general arrangements f o r the subsea p r o d u c t i o n systems are implemented to establish the respective equipment locations. Flow assurance has been considered i n order to avoid hydrate f o r m a t i o n which could block the lines and stop production. Risk assessment for the proposed subsea production systems are performed using fault tree analyses. The selected top event is either total or partial production loss. Finally a cost analysis is performed f o r the system life cycle, including b o t h capital (CAPEX) and operational (OPEX) expenditures. Based on these assessment analyses the best arrangement f o r the subsea p r o d u c t i o n system is recommended.
Keywords
Subsea production system; subsea to beach; flow assurance
1 Introduction
The study reported i n this paper aims at contributing to evaluate i n a systematic way scenarios f o r a subsea production system, considering technical feasibility, operational reliability and financial return for the investment. Offshore gas field is adopted for the case study as well as three associated subsea production scenarios i n order to p e r f o r m the analyses to evaluate the respective arrangements and to recommend the best o p t i o n .
Scenario Evaluation for Subsea Production System Tiago P. E s t e f e n , D a n i e l S . W e r n e c k , Diogo do A m a r a l , J o a o Paulo C . J o r g e , Leandro C . Trovoado. J i a n S u . Edson L a b a n c a a n d S e g e n F. E s t e f e n
Subsea production systems for gas field offshore Brazil are proposed for the case study. The field is located at a distance o f 160 k m f r o m the Brazilian coast at a water depth o f 500 m . Water depths decrease reaching 180 m at 140 k m f r o m the coast and then progressively up t o the beach. Reservoir data indicated pressure o f 530 bar and average temperature o f 140°C. Production w i l l be based o n eight subsea wells w i t h an initial flow rate o f 20 m i l l i o n m ' per day o f gas and 2,000 m ' per day o f condensate.
Three different scenarios f o r the subsea production systems are proposed:
• Scenario 1: Semi-submersible distant 160 k m f r o m the coast at water depth o f 500 m ;
• Scenario 2: Jacket p l a t f o r m distant 140 k m f r o m the coast at water depth o f 180 m ;
• Scenario 3: Subsea to Beach system (no p l a t f o r m ) .
Initially, general arrangements f o r the subsea p r o d u c t i o n systems are implemented to obtain the respective positions o f the equipment, i.e. Christmas trees (X-Trees), m a n i f o l d s , jumpers, flowlines, production and export risers, gas process plant, control umbilicals and long distance pipelines. The general arrangements aim at operational flexibility and system redundancy. Possibilities o f flow maneuver and maintenance procedures i n emergency situations are also analyzed for each scenario.
Considering that gas wells are being developed flow assurance is taken into account i n order to avoid hydrate f o r m a t i o n which could block the Unes and stop production. Two solutions are analyzed, thermal insulation and continuous injection o f m o n o ethylene glycol ( M E G ) . A series o f analyses are performed using commercial software and analytical solution is employed to describe the thermodynamic state (pressure and temperature) i n the phase e q u i l i b r i u m diagram o f gas hydrate. Based on these results i t is possible to assure that the gas flow is out o f the hydrate envelope.
Risk assessment is performed based on fault tree analyses f o r the three scenarios. The selected top event is defined as the total and partial p r o d u c t i o n loss. Due to the lack o f a reliable data base to p e r f o r m quantitative risk analyses to evaluate the respective failure probabilities, qualitative risk assessment is then carried out. The three scenarios are studied i n terms of operational reliability i n order to recommend the best o p t i o n a n d p o s s i b l e i m p r o v e m e n t s f o r the o v e r a l l performance.
Costs play an important role i n the d e f i n i t i o n o f the most attractive option f o r the proposed subsea arrangements. Cost analysis is based on b o t h capital and operational expenditures, production rate, gas price and loan interest rates. Net present value approach is used to estimate the respective scenario profit. Uncertainties associated w i t h the prices raised f r o m the market are accounted for.
2 S y s t e m Design
I n order to exploit the gas field, three scenarios associated to Semi-submersible p l a t f o r m (SS), Jacket platform (J) and a new innovative system, Subsea to Beach (SB), were considered.
The SS arrangement was considered due to the wells water depth o f 500 meters, and also because it has been successfully used offshore BrazU for decades. Also, it has showed to be adequate to the m o t i o n constraints f o r production i n typical Brazilian environmental conditions.
Jacket platform became an option when water depths decreased f r o m 500 to 180 meters only 20 k m away f r o m the wells i n t o shore direction. As a fixed system i t presents advantages i n relation to SS motions induced by waves and currents, allowing the use o f rigid static risers.
The t h i r d scenario, Subsea to Beach, was proposed as an alternative w i t h o u t a processing plant on the p l a t f o r m deck. Therefore, it is practically unmanned offshore, reducing costs related to sea crew and supply vessels. Safety aspects related to the risk to human activities are also substantially reduced. However, i t should be emphasized that the process plant and workers are based onshore w i t h associated risks.
Wells layout for gas field is shown i n Figure 1.
/
"
495 m/ 500 m / \V.| G 1^ y / \V-2 ® SHORE \ y DIREcnOM yC / « - 'o / O SCAlJ-airtiT) G X 0 0 JO) lOCOFig. I Wells layout for the gas field
Preliminary studies have been performed to define respective l a y o u t s f o r the t h r e e scenarios. E q u i p m e n t a n d t h e i r distribution on the seabed as well as flowlines and risers have been considered. The subsea system design for each scenario is presented below.
2.1 Semi-submersible Platform
The subsea p r o d u c t i o n system comprises eight satellite wells connected to the floating p l a t f o r m b y flowlines and flexible risers w i t h 8" diameter, t h e r m a l l y insulated. The gas is dehydrated on the process plant, compressed and then exported t o g e t h e r w i t h c o n d e n s e d gas t h r o u g h a h y b r i d r i s e r configuration. Water f r o m the separation process is treated and then disposed into the sea. The hybrid riser comprises three flexible risers, 8" diameter, w h i c h connect the p l a t f o r m to the vertical r i g i d riser w i t h 22" diameter. Direct hydraulicScenario Evaluation for Subsea Production System
Tiago P. E s t e f e n , D a n i e l S. W e r n e c k , Diogo do A m a r a l , J o a o Paulo C . J o r g e , Leandro C . Trovoado, J i a n S u . Edson L a b a n c a and S e g e n E E s t e f e n
control system was adopted due to the number o f wells and their short distances f r o m the SS.
The h y b r i d riser is connected to a pipeline to export the gas directly to shore. Eight pairs of p r o d u c t i o n and export risers as well as the umbilical cables have been equally distributed along the deck rectangular edge to avoid concentration loads at a f e w points. Deck house is located far f r o m the riser connections to m i n i m i z e the risk o f accidents affecting the workers. The Semi-submersible p l a t f o r m arrangement is shown i n Figure 2.
Fig. 2 Semi-submersible platform arrangement
2.2 Jacket Platform
The f i x e d p l a t f o r m subsea p r o d u c t i o n system presents t w o parallel m a n i f o l d s , each one connected to f o u r X-Trees t h r o u g h flexible flowlines w i t h 8" diameter. Each m a n i f o l d has t w o p r o d u c t i o n headers (10") interconnected to a PLEM (Pipe Line End M a n i f o l d ) i n order to allow gas f l o w t h r o u g h two r i g i d pipes w i t h 18" diameter each, up to the p l a t f o r m . Two PLETs (Pipe Line E n d T e r m i n a t i o n ) are used f o r r i g i d pipe connection to the p l a t f o r m . The connections among m a n i f o l d s , P L E M s and PLETs are made by using r i g i d jumpers.
One o f the manifolds receives an umbilical while the other receives a service flexible pipe (8") and another umbilical. The service and umbilical lines are directly interconnected to the manifolds t h r o u g h flowlines. The second umbilical passes through the P L E M , considering that there is a valve used t o maneuver the PIG by hydrauhc activation.
For this scenario, i t was decided to use thermal insulation f o r the production pipes. Due to the need o f a M E G injection i n case o f shut d o w n , one o f the umbilicals has an internal hose for chemical injection.
The m u l t i p l e x e l e c t r o - h y d r a u l i c c o n t r o l system was used due to the distance between the p l a t f o r m and the wells, 20 k m , enabling faster valve activation i n c o m p a r i s o n to a h y d r a u l i c direct system. A n o t h e r advantage o f this system is the r e d u c e d n u m b e r o f u m b i l i c a l s a t t a c h e d t o t h e p l a t f o r m .
I n the process p l a n t , water associated to the n a t u r a l gas is r e m o v e d b e f o r e the gas is c o m p r e s s e d a n d e x p o r t e d together w i t h the condensed gas t h r o u g h a r i g i d riser (22"). Figure 3 shows the Jacket p l a t f o r m arrangement.
Fig. 3 Jacket platform arrangement
2.3 Subsea to Beach
Bernt and Smedsrud (2007) describe the concept and the technical solutions developed and applied to the Ormen Lange subsea to beach production system, second-largest Norwegian gas field. The paper presents the extensive design, fabrication and testing processes undertaken i n order t o verify correct functionaUty and confidence i n the applied solutions. Subsea to Beach arrangement presents the same equipment configuration, X-Trees, manifolds and PLET connections as in scenario 2 (Jacket), b u t w i t h o u t using the p l a t f o r m . The exportation to the onshore terminal w i l l be accomplished throughout t w o rigid pipes w i t h 22" diameter each.
I n this scenario, i t was also decided to use thermal insulation for the p r o d u c t i o n pipes. Due to the need o f MEG injection in case o f shut down, once again one o f the umbilicals has an internal hose f o r chemical injection. Due to the distance firom the wells to shore, about 160km, the m u l t i p l e x hydraulic control system was chosen.
As reservoir pressure falls b o t h as time goes by and also w i t h the increase o f accumulated production, i t may be necessary to install subsea separator and gas compressor to guarantee
Scenario Evaluation for Subsea Production System Tiago P. E s t e f e n , Daniel S . W e r n e c k , Diogo do A m a r a l , J o S o Paulo C . J o r g e , Leandro C . Trovoado, J i a n S u , Edson L a b a n c a a n d S e g e n E E s t e f e n
the field production during the project life. Figure 4 shows the proposed arrangement f o r Subsea to Beach scenario.
Fig. 4 Subsea to Beach arrangement
3 S u b s e a Processing
Technical challenges and solutions related to flow assurance for gas p r o d u c t i o n i n accordance to the e n v i r o n m e n t a l conditions are analyzed. One major problem f o r a gas field design is to avoid the hydrate f o r m a t i o n . Two solutions are considered, thermal insulation and continuous injection o f mono ethylene glycol ( M E G ) .
I n order to obtain thermal insulation that compUes w i t h project specifications, temperature profiles i n steady-state production conditions f o r the three different scenarios were i n i t i a l l y calculated based o n a theoretical approach (Jian Su et al., 2005). The pressure profile, i n steady-state, was determined using the computer program PIPESIM (2000). Analyses o f the transient regime were carried out employing the specialized software OLGA® (2000). Shut d o w n p r o d u c t i o n and line depressurization were also s i m u l a t e d . A f t e r w a r d s , the continuous injection o f thermodynamic inhibitor, MEG, and the volume needed to avoid the hydrate f o r m a t i o n has been analyzed.
3.1 Hydrates
Hydrates are ice-like solid crystalline normally f o r m e d at high pressure and low temperatures i n the presence o f water.
Once defined the gas composition, flow assurance study is summarized i n three fundamental analyses: thermodynamic.
fluid dynamic and heat transfer. The thermodynamic analysis defines state properties such as specific heat f o r constant pressure and constant volume (Cp and Cv) and specific mass (p). These w i l l be used to determine pressure and temperature profile along the line. Therefore, w i t h temperature and pressure data along the Une, i t is possible to determine hydrate formation points. I n case there is hydrate f o r m a t i o n , prevention and dissociation methods should be proposed.
The most adopted methods to avoid hydrate f o r m a t i o n are: • Water removal;
• Line heating; • Line depressurization; • Line thermal insulation; • Use o f thermodynamic inhibitors.
3.2 Thermal Insulation
The thermal insulation proposed, polypropylene f o a m , f o r rigid pipes consists of a multi-layer anti-rusty protection applied to the pipe surface. The surface has to be previously cleaned and prepared according to pre-set standards. This system is a p p r o p r i a t e t o o f f s h o r e i n s t a l l a t i o n s , due to i t s g o o d mechanical and thermal resistance features, and i t is generally used f o r water depths up to 600 meters. After a previous visual inspection of pipes and pre-heating / jetting on the pipe external surface, the system is applied i n f o u r different layers: primer ( 1 " layer), adhesive (2°'' layer), polypropylene f o a m (3"* layer) and polypropylene solid (4* layer).
For flexible pipe configuration synthetic f o a m tapes w i t h glass micro spheres are used. The U value, determined by design requirements, is provided to the manufacturer, so that the insulating tape layers can be determined and incorporated to the p i p e b e f o r e the o u t e r layer is a p p l i e d i n the f i n a l manufacture stage.
3.3 Gas State Properties
The fu-st step to verify whether the flow complies w i t h project specifications is to obtain thermodynamic properties and phase d i a g r a m . To do that the software P V T S I M (2002) was employed. P V T S I M is a versatile PVT simulation program which allows reservoir engineers, flow assurance specialists and process engineers to combine reliable fluid characterization procedures TOth robust and efficient regression algorithms to m a t c h fluid properties and experimental data. The fluid parameters may be exported to produce high quality i n p u t data f o r reservoir, pipeline and process simulators. Based on a gas typical composition the f o l l o w i n g phase diagram was
Scenario Evaluation for Subsea Production System
Tiago P. E s t e f e n , Daniel S. W e m e c k , Diogo do A m a r a l , J o S o Paulo C . J o r g e , Leandro C . Trovoado, J i a n S u . Edson L a b a n c a a n d S e g e n E E s t e f e n
obtained, as illustrated i n Figure 5. Hydrate formation occurs on the left side o f the curve.
0 I I , , , , , 0 5 10 15 20 25 30
Temperature ( ' C )
Fig. 5 Phase diagram showing the conditions under which hydrates will form
3.4 Temperature and Pressure Profile
Determination
Temperature a n d pressure p r o f i l e s i n steady-state f l o w c o n d i t i o n s were o b t a i n e d f o r the three scenarios. T h e theoretical analysis to obtain the temperature profile was based on Jian Su et al. (2005). The analyses to obtain the pressure profile were carried out using the soft^vare PIPESIM (2000). PIPESIM is a steady-state, multiphase flow simulator used f o r the design and diagnostic analysis o f o ü and gas production systems. PIPESIM soft^vare tools model multiphase flow f r o m the reservoir to the wellhead and also analyzes flowUne and surface f a c i l i t y performance to generate comprehensive production system analysis. Fluid modeling was obtained b y applying the state equations i n multi-component systems. The study was performed considering the flow rate o f 10 m i l l i o n mVday (by the end o f the design life, i.e. the worst case f o r the heat transfer).
To obtain the curve out o f the hydrate envelope f o r the three scenarios. Figure 6, i t has been estimated the f o l l o w i n g U (global heat transfer coefficient) values:
• Scenario 1, Semi-submersible (flexible risers), U = 17.79 w/m2 °C;
• Scenario 2, Jacket - P o l y p r o p y l e n e f o a m p r o p o s e d as thermal insulator, w i t h polypropylene soUd outer layer o f 0.25" and polypropylene f o a m inner layer o f 0.25", U = 3.78 w / m ^ "C;
• Scenario 3, Subsea to Beach - Polypropylene foam proposed as thermal insulator, w i t h polypropylene solid outer layer o f 0.25" and polypropylene f o a m inner layer o f 1", U = 1.05 w / m ^ "C.
0 26 60 76 100 125
Temperature ("C)
—HydrateOiivft —Scenario 1 —Scenario 2 —Scenarios
Fig. 6 Thermodynamic state (pressure, temperature) i n the phase equilibrium diagram of gas hydrate, scenario 1 , 2
and 3
3.5 Transient Regime
I n order to analyze the transient regime, the operational shut down was simulated using the program OLGA® (2000) w i t h i n p u t data from PVTSIM (2002) results. OLGA® models the flow of production using complex simulations which predict the behavior o f the fluid flow. The advantage o f OLGA lies i n the ability to model the dynamic qualities o f production f o r all multiphase scenarios. O n l y the worst case scenario f o r hydrate f o r m a t i o n , Subsea to Beach, was considered. Results are shown i n Figure 7.
bar "C
0 10 20 30 40 60 60 Time [hi
— pressure at Uie manifold pressure al the lemiinal fluid lemperalure at ttie manifold fluid temperature at the terminal
Fig. 7 O L G A ® ( 2 0 0 0 ) results for transient analysis at production shut down
The simulation considers the situation where the manifold's and the terminal's production valves are closed. Green and black curves refer to fluid temperature and pressure at the m a n i f o l d , respectively. Blue and red curves refer to fluid temperature and pressure at the terminal, respectively.
Figure 7 is used to estimate the shut d o w n p e r i o d w h i c h insulation provides w i t h o u t hydrate f o r m a t i o n . Analyzing the hydrate curve previously obtained. Figure 5, rath the coldest
Scenario Evaluation for Subsea Production System Tiago P. E s t e f e n . D a n i e l S. W e m e c k , Diogo do A m a r a l , J o S o Paulo C . J o r g e , Leandro C . Trovoado, J i a n S u , Edson L a b a n c a a n d S e g e n E E s t e f e n
temperature togetfier w i t h the higher pressure, i t is possible to conclude that there w i l l be no hydrate f o r m a t i o n f o r at least 60 hours.
I n case the hydrate block is f o r m e d , i t can be dissociated by depressurizing the line. Using again the computer program OLGA® (2000) it is possible to estimate tune needed to decrease properly the pressure. Figure 8 indicates that i t is necessary about 8 hours for the pressure to drop down to 25 bar (pressure at the onshore terminal). The analysis considered the distance between m a n i f o l d and onshore terminal.
110
2 0 H 1 1 1 1 1 '
0 10 20 30 40 50 60
Tïne (h]
= export pipeline pressure onshore terminal pressure
Fig. 8 Time required for pressure drop, scenario 3
3.6 Mono Ethylene Glycol
Another alternative to prevent hydrate f o r m a t i o n is the use o f chemical inhibitors. M o n o ethylene glycol (MEG) is the state of the art hydrate control method. Besides preventing hydrates, MEG reduces the corrosion rate i n carbon steel pipelines and it is well suited as carrier f o r corrosion inhibitors and p H -stabilizers.
The main benefits o f a M E G solution are: • Reliable solution;
• Closed loop; • Corrosion protective;
• N o gas plant or refinery contamination;
• Environmentally friendly, n o n toxic, n o n flammable; • Qualified technology.
3.6.1. MEG Calculation
A high-concentration ( 5 % to 50%) o f these chemical i n the water phase is required to avoid hydrate f o r m a t i o n . The methodology used to calculate the necessary amount o f MEG in the system is based on the hydrate curves. U s i n g the properties o f the gas, different concentrations o f MEG i n the
system are determined and then new hydrate curves are generated, which was made w i t h the program PVTSIM (2002). Results are shown i n Figure 9.
-12 -7 -2 3 8 13 18 23 28
Temperature ( ' C )
—0% —10% —30% —40% —50%
Fig. 9 MEG concentration
Taking the 9^0 sea temperature into the graphic, the working pressures are obtained f o r each one o f the different M E G percentage curves. By doing that, it is possible to conclude that a 30% MEG concentration is acceptable shice the pressiu-e given is approximately 150 bar, and the actual working pressure is aroimd 110 bar. The 40 bar difference represents the safety factor.
MEG delivery requirements f o r each well are individually determined based on predictions of water production f r o m each well, given by the multiphase meastu-e device installed on each X-Tree as part o f the control system. For mono ethylene glycol (MEG) net, h is assumed that for 100 kg of produced fluid, 1 kg is of water. Calculations have indicated that for the production of 20 milUon mVday, the necessary amount o f MEG is 0.52 kg/s.
4 S u b s e a Equipment
I n this chapter a more detailed description o f the subsea equipment and its selection are accomplished for the proposed gas field exploitation. The rehability of the subsea system design is strongly dependent on the specific equipment design. I n case o f complex equipment, like X-Tree and m a n i f o l d , special studies are necessary to optimize the equipment design and to take advantage of its flexibility i n benefit o f the subsea system design (Labanca, 2005).
4.1 Wet Christmas Tree (X-Tree)
X-Tree can be classified according to the control valve layout (Albernaz, 2005) as:• Horizontal Wet Christmas Tree;
• Conventional Wet Christmas Tree (vertical).
Horizontal X-Tree can be described as a production adapted
Scenario Evaluation for Subsea Production System
Tiago P. E s t e f e n , Daniel S . W e m e c k , Diogo do A m a r a l , J o a o Paulo C . J o r g e , Leandro C . Trovoado, J i a n S u , E d s o n L a b a n c a a n d S e g e n E E s t e f e n
base with valves mounted on the lateral sides, allowing well intervention and production column replacement w i t h o u t its removal. This characteristic does not present an advantage f o r the gas fields, considering that rare interventions are needed. Vertical X-Tree provides increased mstallation and operational flexibility over the horizontal tree. The vertical tree comprises separate modules that can be installed independently. The vertical X-Tree set comprises production adapted base (PAB), tubing hanger, flowline connectors, valves and tree cap.
Vertical X-Tree uses a PAB which enables the installation o f the lines independently. This feature was taken i n t o account for choosing the vertical X-Tree to be included i n the proposed subsea arrangements f o r the three scenarios. Considering 500 m water depth, all methods o f installation using divers were discarded.
The latest concept f o r guidelineless X-Tree uses the vertical connection module ( V C M ) . The possibility o f independent installations o f X-Tree and flowlines contributes to optimize the installation costs. Another i m p o r t a n t p o i n t is the use o f only one vessel f o r the X-Tree installation.
For the three scenarios considered the same X-Tree are adopted because i t depends only o n the reservoir characteristics. For the considered gas field, 500 m water depth and 7691 psi reservoir pressure, the selected X-Tree is the guidelineless, w i t h V C M and w o r k pressure o f 10,000 psi.
4.2 Manifold
to 300 m . I n the proposed scenarios D L m a n i f o l d s are employed.
The m a n i f o l d comprises the f o l l o w i n g parts: • Sub-base structure;
• Pipes and valves; • Recoverable valve modules;
• Recoverable control modules (subsea part o f the control system);
• Pipe connecting modules.
4.2.2 Manifold Arrangement and Operation
For scenarios 2 and 3 two manifolds i n parallel are employed. Figure 10 presents the m a n i f o l d w i t h capacity f o r f o u r wells. For clarity the symbols only appear i n one group of valves, b u t i n fact they are i n each o f the f o u r groups.
LEGEMD
Production Line 1>5] Manual Valve
Service Line »J Automatic Hydraulic Valve (ctose) - MEG 0 ^ Automatic Hydraulic Valve (open)
Umbilical Automatic Hydraulic Ctioke @ Temperature Transducer {§) Pressure Transducer @ Row Meter
Manifolds can be classified according to their f u n c t i o n and way o f installation. Regarding its fimction, i n general, they can be classified as:
• Collecting manifold - I t collects the flow from several pipes into a single pipe;
• D i s t r i b u t i o n m a n i f o l d - I t distributes the flow f r o m a single pipe to several pipes;
• Mixed manifold - It has both characteristics above mentioned. The main advantages i n its application are:
• Reducing the number of risers i n the p l a t f o r m m i n i m i z i n g both the space and the load applied on stationary production unit, thus reducing the pipes costs;
• Installing i n advance, i.e. subsea system awaiting p l a t f o r m arrival;
• Optimizing subsea arrangement (clearing the ground next to the p l a t f o r m and its anchor system).
4.2.1 Manifold Installation
Regarding the way o f i n s t a l l a t i o n and i n t e r v e n t i o n , the manifolds are of two types: DA (diver assisted) or D L (diverless).
The DA manifolds can only be installed i n water depths o f up Fig. 10 Submarine manifold for 4 wells
Scenario Evaluation for Subsea Production System Tiago P. E s t e f e n , Daniel S . W e r n e c k , Diogo d o A m a r a l , J o a o Paulo C . J o r g e , Leandro C . Trovoado, J i a n S u , Edson L a b a n c a and S e g e n E E s t e f e n
For JvtEG distribution, f o u r choices are used i n the m a n i f o l d for each X-Tree f o r separate f l o w control, considering that product injection needs may differ f o r each production line.
Production pipe linked to each X-Tree can be lined up for the three headers. Figure 1 1 . One, through the T1 valve, that goes to service pipe i n order to test well production. The other two, P I and P 2 , go to their respective p r o d u c t i o n headers. This c o n f i g u r a t i o n assures operational flexibility, because i t is possible t h r o u g h a maneuver o f valves t o select the well production for the desked export pipehne. The two production headers coming f r o m the m a n i f o l d arrive at a PLEM and then the production is exported through two pipelines.
ÖWchoke
Fig. 11 Manifold recoverable module
I t was installed i n each m a n i f o l d one electric hydraulic d i s t r i b u t i o n m o d u l e ( E H D M ) f o r the u m b i l i c a l vertical connection. A n d also two subsea c o n t r o l module (SCM) responsible each one for the control o f two X-Trees. Thus, i n case o f one SCM failure only two p r o d u c t i o n wells are lost.
It has been decided the use o f six recoverable modules, four for production and two f o r the SCM. Components which need maintenance were installed i n the production, such as hydraulic valves, flow meters, pressure and temperature transducers. Size and weight o f the manifold are increased by using recoverable modules. However, they a l l o w the repair o f i m p o r t a n t components without being necessary to recover the manifold.
4.3 Control Systems
4.3.1 Hydraulic Direct
Hydraulic direct is the simplest, cheapest and most reliable system, therefore the favorite f o r satellite well control. It was adopted f o r scenario 1 due to the number o f wells and the small distance betiveen them and the SS. Each X-Tree receives one umbilical from p l a t f o r m containing the necessary electric cables to acquire data and hydraulic hoses to activate valves.
4.3.2 Multiplex Electro Hydraulic
The multiplex control is usually employed i n systems w i t h a m a n i f o l d w i t h a great number o f hydraulic functions. This system m u l t i p l e x the h y d r a u l i c f u n c t i o n s and the data acquisition f r o m m a n i f o l d and wells through a central station installed on the platform / onshore terminal and, also, from subsea c o n t r o l modules installed i n the m a n i f o l d . The interconnection o f the subsystems is done through only f o u r hydraulic hoses and f o u r pairs o f electric cables mounted o n the umbilical. The cables have double-function, they transfer power f r o m the processing unit to sensors installed on the m a n i f o l d and X-Tree, and they b r i n g to the operational and supervision central station the signals f r o m these sensors. The main actions executed by this system are:
• Operation o f hydraulic valves o f the m a n i f o l d , X-Tree, PLEM and o f those installed i n the wells downhole; • Operation of hydraulic chokes;
• Pressure and temperature m o n i t o r i n g o f the i m p o r t and export fluids and position o f the chokes;
• Pressure and temperature m o n i t o r i n g at X-Tree; • Pressure and temperature m o n i t o r i n g at the well. The m a i n components o f this system are:
• Electro-hydraulic distribution module ( E H D M ) - installed in the m a n i f o l d ;
• Subsea control modules (SCM) - installed i n the m a n i f o l d ; • Electronic surface unit (ESU) - installed i n the production
terminal unit.
This system was employed i n scenarios 2 and 3 due to both m a n i f o l d use and the long distance between production u n i t and wells.
4.4 Equipment General Arrangement
I n m a n i f o l d 2 arrives, f r o m the p l a t f o r m or onshore terminal, one u m b i l i c a l w i t h a M E G i n j e c t i o n hose included, while i n the m a n i f o l d 1 arrives an umbilical and a flexible service pipe. Two umbilical cables were used i n order to provide more reliability to the system due to operational redundancy i n case o f failure. Since there is no need f o r service and M E G lines to pass t h r o u g h the PLEM, they are connected to the other m a n i f o l d b y rigid jumpers. One o f the umbilicals is also connect i n that same way, while the other one goes t h r o u g h the P L E M i n other to actuate the V P valve o n that eqiupment. Figure 1 2 illustrates the general arrangement o f the subsea equipment. For clarity the symbols o n l y appear i n one group o f the recoverable module, but i n fact they are i n each o f the eight groups.Scenario Evaluation for Subsea Production System
Tiago P. E s t e f e n , D a n i e l S . W e m e c k , Diogo do A m a r a l , J o S o Paulo C . Jorge, Leandro C . Trovoado, J i a n S u , E d s o n L a b a n c a and S e g e n E E s t e f e n
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4.5 Subsea Compression and
Separation
Reservoir pressure drops throughout the field p r o d u c t i o n lifetime. This w i l l impact production rate and profitability, especially f o r the Subsea to Beach case due to the 160 k m o f production pipelines. Because o f that, the use o f a subsea compressor was considered.
Before compression can be made, i t is necessary to separate the water associated w i t h the gas and the condensate. For that, it is essential to install a subsea separator. This system is focused on the following processes (Fantoft and f f e n d r i k s , 2004): • Separation o f water, gas and condensate;
• Re-injection o f the separated water into the reservoir; • Compression o f the dehydrated gas;
• M i x t u r e the compressed gas w i t h the condensate; • Export the gas and condensate mixture.
The installation o f this t^vo equipment, subsea separator and subsea compressor, w o u l d solve the pressure drop problem, conferrmg profitability and a series of advantages to the Subsea to Beach scenario, such as:
• D r a w out o f the field p r o d u c t i o n ;
• Better field management. The separation o f water w o u l d help on hydrate prevention;
• Reduced environment impact. The separated water can be re-injected into the reservoir.
4.5.1 Subsea Separation
The economic potential of subsea separation has been k n o w n for some time. Yet, while there are a substantial number o f subsea p u m p systems i n operation, there are only two subsea separation stations installed. One is the Troll Pilot f o r water separation and reinjection, operated by Norsk H y d r o u i the N o r t h Sea. The second installation is the VASP system for gas-hquid separation and boosting operated by Petrobras i n Brazil. There are interrelated reasons why the development of subsea separation applications has lagged. First, some components o f such a system w o u l d have to be newly designed and qualified. Second, a system incorporating new technology carries a higher potential risk. I n addition to undemonstrated performance, both durability and ease o f maintenance w o u l d need to be addressed to reduce the u n k n o w n aspects o f the r i s k . A c c o r d i n g l y , p l a n s f o r any new d e s i g n m u s t i n c l u d e qualification to m i n i m i z e the risk o f a new technology.
4.5.2 Subsea Compression
The subsea compression equipment is one o f the biggest challenges f o r the proposed implementation o f the Subsea to Beach concept. Bjerkreim et al. (2007) describes the subsea compression technical solution to be implemented i n the Ormen Lange field.
Scenario Evaluation for Subsea Production System Tiago R E s t e f e n , Daniel S . W e r n e c k . Diogo do A m a r a l , J o a o Paulo C . J o r g e , Leandro C . Trovoado. J i a n S u , E d s o n L a b a n c a a n d S e g e n E E s t e f e n
4.5.3 Process Description
All production is directed to the subsea separator, which \vill be responsible f o r separating the water f r o m the condensate and the gas. The gas is then compressed and put together w i t h the condensate. A t this point the mixture is exported through production pipelines to the terminal. The separated water is then re-injected i n the field.
For system optimization, i t is better to position the equipment as near to the field as possible. For scenario 3 the appropriated location is near the PLEM.
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5 Risk A s s e s s m e n t
I n order to estimate the reliability of the three proposed subsea arrangements for gas exploitation, fault tree analyses (Rausand, 1999; Kuo, 1998; ABS Guide, 2003) are performed assuming as the top event o f b o t h total and partial production losses. The fault tree does n o t consider the processing plant.
The subsea equipment taken i n t o account have a l i m i t e d n u m b e r o f components to make i t possible the overall reliability analyses i n the present stage, when the concepts should be better understood and the risks identified.
Although the respective fault trees for the considered scenarios could be employed i n a latter stage to generate quantitative estimates f o r the f a i l u r e p r o b a b i l i t y , i n this paper o n l y qualitative reliability analyses are performed. It is important to emphasize that the access t o reliable data base is necessary for a consequent quantitative risk analysis. Otherwise the results f o r the quantitative analysis c o u l d lead to w r o n g conclusions and mistaken decisions.
5.1 Scenario 1: Semi-submersible
The subsea arrangement based on satellite wells implies that each independent well system (X-Tree/ flowline/ riser) is responsible f o r 1/8 o f the total production. Each well system is independent and i n case o f one main component / process failure the respective production is interrupted.It can be observed that the satellite arrangement prevents the total p r o d u c t i o n i n t e r r u p t i o n because o f the direct l i n k between well head and processing unit. Total production loss is only possible if:
a) all eight independent i m p o r t systems (X-Tree/ flowUne/ riser) present simultaneously failure, or
b) the export riser system presents failure either i n the SLOR or export pipeline.
The fault tree associated \vith partial production loss f o r the Semi-submersible scenario is presented i n the Figure 13.
Fig. 13 Fault tree for the Semi-submersible scenario - partial production loss
5.2 Scenario 2: Jacket
Subsea arrangement for this scenario presents some tolerances to failure, i.e. failure in the flowline linking manifold to process plant does n o t cause partial production loss.
I n relation to total production interruption, i t can be observed that this scenario seems to be less reliable than the previous one. I n the present scenario there is more equipment prone to cause complete production shut down i n case o f failure, such as:
• 22" export riser/flowline;
• 2 X 18" flowUne/riser f r o m P L E M to Jacket - equipment instaUed i n parallel, the t o t a l p r o d u c t i o n i n t e r r u p t i o n depends o n failure o f both parallel lines;
Scenario Evaluation for Subsea Production System
Tiago P. E s t e f e n , Daniel S. W e r n e c k , Diogo do A m a r a l , J o a o Paulo C . J o r g e , Leandro C . Trovoado, J i a n S u . E d s o n L a b a n c a a n d S e g e n E E s t e f e n
• U m b i l i c a l s f r o m Jacket to m a n i f o l d - also installed i n p a r a l l e l w i t h the same r e d u n d a n c y as the lines above mentioned;
• Subsea c o n t r o l m o d u l e ( S C M ) r e s p o n s i b l e f o r t w o X-Trees each - o n l y the simultaneous failure o f the f o u r SCM could f u l l y stop p r o d u c t i o n .
A particular well shut d o w n seems to have a smaller failure probability f o r this scenario than f o r the previous one. I t is mainly due to the more reliable l i n k X-Tree / manifold / Jacket than X-Tree / riser / Semi-submersible, due to the riser dynamic behavior and associated uncertainties.
The fault tree associated w i t h partial production loss f o r the Jacket scenario is presented i n Figure 14.
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-Fig. 1 4 Fault tree for Jacket scenario - partial production loss
5.3 Scenario 3: Subsea to Beach
Subsea arrangement for this scenario is very similar to that f o r Jacket scenario. Therefore the fault trees are also similar. The main advantage o f this arrangement i n relation to the Jacket scenario is the possibility o f not using risers, although dynamic considerations for Jacket risers can be neglected. All the lines m the Subsea to Beach scenario are subjected to design static loads. Exception could be considered for eventual pipeline free span but it could occur also i n the other t w o scenarios w i t h similar probabilities.SOJ 1 FAlUt MltS I-l
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A n additional advantage is associated w i t h the use o f t w o export 22" pipelines instead o f one employed i n the Jacket subsea a r r a n g e m e n t . The d u a l p i p e system i n t r o d u c e s operational redundancy to the arrangement. I n the case o f a pipe interruption, flow assurance could be maintained w i t h o u t affecting the production. The main disadvantage is associated w i t h the gas transportation w i t h o u t water separation, w h i c h represents a considerable higher p r o b a b i l i t y o f h y d r a t e f o r m a t i o n and consequent pipeline block as compared w i t h dehydrated gas obtained f r o m the offshore process plant available i n b o t h scenarios 1 and 2.
5.4 Conclusions from the Qualitative
Risk Assessment
Based on the above fault trees two different situations in relation to p r o d u c t i o n loss are analyzed: total p r o d u c t i o n loss and partial production loss.
5.4.1 Total Production Loss
The conceptual probability o f failure f o r the total p r o d u c t i o n loss indicates that scenario 1 presents the best result. The satellite wells c o n t r i b u t e to decrease the p r o b a b i l i t y o f a
Scenario Evaluation for Subsea Production System Tiago P. E s t e f e n . Daniel S. W e m e c k . Diogo do A m a r a l , J o a o Paulo C . J o r g e , Leandro C . Trovoado. J i a n S u , Edson L a b a n c a a n d S e g e n E E s t e f e n
complete shut d o w n . The possibility o f a shut d o w n depends on export pipe system failure. For scenarios 2 and 3, there are a d d i t i o n a l possibilities o f f a i l u r e associated w i t h subsea multiplexed control and manifold.
Scenario 3 presents advantage i n relation to the scenario 2. An advantage f o r scenario 3 is the redundant export pipelines adding operational flexibility to the subsea arrangement, since the failure o f one pipeline does not i m p l y i n production loss. However, due to the transportation o f the gas/water mixture, scenario 3 presents higher probability o f hydrate f o r m a t i o n than scenarios 1 and 2, which have separation process to dehydrate the gas.
I n relation to the total production loss i t can be concluded that the most reliable subsea arrangement system is that represented by scenario 1, followed by scenarios 3 and 2.
5.4.2 Partial Production Loss
The p a r t i a l p r o d u c t i o n loss considers o n l y one w e l l i n t e r r u p t i o n . A n a l y z i n g the subsea arrangements and respective fault trees it can be observed that scenarios 2 and 3 are more reliable than scenario 1. As already mentioned the advantage o f o n - b o t t o m i m p o r t system using manifolds and electro-hydraulic multiplex control reflects on smaller failure probability i f compared ^vith the i m p o r t and export dynamic risers i n scenario 1. I n general, i t can be concluded that scenarios 2 and 3 are more reliable than scenario 1 f o r partial production loss. I n this case it is difficult to distinguish scenarios 2 and 3. A l t h o u g h scenario 3 has t w o redundant export pipelines, the transport o f water/gas m i x t u r e increases the probability of hydrate formation i f compared w i t h scenario 2, although i n this scenario there is no pipeline redundancy.
5.4.3 The Best Scenario
Considering that the total p r o d u c t i o n loss is associated %vith a failure probability substantially smaller than f o r the partial p r o d u c t i o n loss, the indication o f the most reliable scenario s h o u l d take i n t o consideration small p r o d u c t i o n losses d u r i n g the project l i f e cycle. The satellite wells associated w i t h dynamic risers again p u t the scenario 1 as the less attractive alternative.
A l t h o u g h equivalent i n terms o f partial p r o d u c t i o n loss, scenario 3 is more reUable than scenario 2 for total production loss (two export pipes). Therefore, based o n the qualitative risk assessment f o r p r o d u c t i o n loss, the scenario 3 can be i n d i c a t e d as the best o p t i o n f o r the o f f s h o r e gas f i e l d considered i n this study. However, the possibility o f gas/water subsea separation and subsea gas compression, before export to onshore terminal, could mean an outstanding advantage for Subsea to Beach scenario i n r e l a t i o n to b o t h Semi-submersible and Jacket scenarios. I n addition, the possibility o f only one export pipeline could be considered for the Subsea to Beach scenario f o r dehydrated gas.
It should be emphasized that a quantitative risk analysis based on rehable data could eventually result in a different conclusion.
6 C o s t s
The total cost when developing a subsea exploitation field is a f u n c t i o n o f several income and expense factors such as capital expenditures (CAPEX), operational expenditures (OPEX), p r o d u c t i o n rate, product price, frequency o f component failures and intervention vessels (Gustavsson et al., 2004). The value o f a project is based on its capability to generate future cash flow, therefore the investment alternatives can only be compared i f measured at the same time. To do that, the approach based on the Net Present Value (NPV) is adopted.
6.1 MEG/lnsulation Analysis
I n order to prevent hydrate f o r m a t i o n , two possibilities were considered, the continuous injection of MEG and the thermal insulation o f the production pipelines. These two methods have different impacts on cost. Insulation requires more initial expenditure, increasing the CAPEX. O n the other hand the continuous injection o f MEG requires m u c h less CAPEX but its maintenance adds to the OPEX.
For scenario 1 the insulation concept was readily adopted because o f the short distance f r o m the wells to the Semi-submersible. The analyses were performed only for scenarios 2 and 3 due to the long distances f r o m the wells to the Jacket p l a t f o r m or to the onshore terminal, respectively. I f using continuous M E G injection, a flexible 6" flowline is required for MEG transportation. Even though the flexible Une is more expensive then the rigid one, the fact that it is possible to install this line together \vith the umbilicals makes the overall installation expenditure more attractive. I f it were a rigid pipe, another vessel w o u l d have to be contracted. W h e n using i n s u l a t i o n , the cost o f the pipes increase because o f the insulation layer itself, but installation costs are the same. Table 1 shows the results obtained for scenarios 2 and 3 f o r the sum of CAPEX and OPEX.
Table 1: Comparative costs between of MEG and insulation for scenarios 2 and 3
Solution *
Insulation MEG
Jacket 90 147.5
Subsea to Beach 811 891
• Values in million US$
6.2 Cost Analysis for the Three
Scenarios
Cost analysis was made considering the use o f loans based o n Price method, w h i c h determines constant payments. I t was assumed 80% loan f o r 20 years pay period w i t h 6% year interest rate. D o i n g that, the initial investments are greatly reduced since only 20% o f CAPEX is paid at the end o f each semester. The loan debt increases t i l l operations begin and payments start. Table 2 summarizes the main loan data.
Scenario Evaluation for Subsea Production System
Tiago P. E s t e f e n , D a n i e l S . W e r n e c k , Diogo do A m a r a l , J o a o Paulo C . J o r g e , Leandro C . Trovoado, J i a n S u , E d s o n L a b a n c a and S e g e n E E s t e f e n
Table 2: M a i n loan data
year Financial Interest 6 % Own expenditure 2 0 % Financed expenditure 8 0 % Project Life 20
(a) Semi-submersible scenario
0.14
Based on the subsea design, industry prices were raised to specify each system component and installation costs. I n order to estimate income, the 20 m i l l i o n m ' / day were converted to equivalent n u m b e r o f o i l barrels. Two N P V values were calculated f o r each scenario f o r two oU equivalent prices. The higher N P V obtained was f o r Subsea to Beach, Table 3.
Table 3: Cost analysis f o r two income considerations
N P V *
US$ 25.00 US$ 45.00 Semi-submersible 147.96 618.75 Jacket 125. 20 596.00 Subsea to Beach 172.41 643.21
*NPV In million US$ for 20 years service
A f t e r calculating the capital r e t u r n f o r each scenario, the most obvious aspect is the p r o x i m i t y o f the obtained results. Even though the Subsea to Beach has the best NPV, US$ 172.41 miUion f o r the barrel o i l price o f US$ 25.00 and US$ 643.21 m i l l i o n f o r US$ 45.00, these are 37.7% a n d 8% greater than the lowest ones o f US$ 125.20 m i l l i o n and US$ 596.00 m i l l i o n f o r Jacket p l a t f o r m scenario. Because o f that and the fact that there are uncertainties f o r the component costs, i t is n o t possible to guarantee the Subsea to Beach scenario as the most profitable investment.
Finally, to better understand the N P V return value behavior, a risk estimative f o r the cost analysis is performed. This was particularly necessary due to the fact that the prices obtained for each component can fluctuate. To r u n the analysis, i t is necessary to k n o w w h i c h components have a higher impact on the NPV. This sensibility study consists of varying the value o f one parameter, the p l a t f o r m or the OPEX for example, to analyze the impact o n the calculated NPV. The outcome o f the study is that the most i m p o r t a n t parameters are the platforms, the OPEX and semester income value, and all pipeline costs f o r buying and installing them.
The next step was to r u n the risk cost analysis. This was p e r f o r m e d u s i n g the s o f t w a r e @Risk ( 2 0 0 4 ) . Basically, triangular functions were determined f o r each o f the selected parameters of the three scenarios, and their prices were defined w i t h a m i n i m u m value (10% less), the mean value and the m a x i m u m value (10% more). Then 10,000 iterations were assumed i n the analysis, where the program randomizes the parameter values w t h costs w i t h i n established limits. Figure 15 shows the probability graphics obtained f o r the scenarios 1,2 and 3. The analysis considered the o i l price per barrel as US$ 25.00. 1? ^o* ^4= ^t? <?• .jP' N P V (US$ million) (b) Jacket scenario ! f
<'
# ^sj" o'= ..h"' <o* .^«^^ N P V (US$ minion)(c1 Subsea to Beach scenario
0.12
N P V ( U S $ million) Fig. 15 Probabihty analyses f o r N P V
Scenario Evaluation for Subsea Production System Tiago P. E s t e f e n , Daniel S. W e m e c k , Diogo do A m a r a l , J o a o Paulo C . J o r g e , L e a n d r o C . Trovoado, J i a n S u , E d s o n L a b a n c a a n d S e g e n E E s t e f e n
I t is c o n f i r m e d tliat the Subsea to Beach scenario has the highest NPV values, ranging f r o m 107 m i l l i o n to 233 m i l l i o n , w i t h the highest (11%) chance o f returning 177 m i l h o n . The Jacket plataform has lower values for the returning range, but it shows the highest probability o f 12%, the biggest one over the three scenarios. The Jacket p l a t f o r m shows values w i t h a range between 56 and 192 m i l h o n .
7 Conclusions
Three subsea production systems have been proposed for a gas field offshore Brazil. The considered scenarios were Semi-submersible p l a t f o r m (SS), Jacket p l a t f o r m (J) and Subsea to Beach (SB). Aspects related to subsea processing, risk assessment and costs have been considered to provide the necessary support for the development o f the subsea production systems. For the three scenarios a series o f analyses have been carried out to determine the thermodynamic state (pressure and temperature) i n the phase equilibrium diagram o f gas hydrate to assure that the flow is out of the hydrate envelope. Based on these results i t is realized that the gas m i x t u r e can be maintained out o f the hydrate envelope by using appropriate pipe insulation. Analyzing Subsea to Beach for the worst case, the longest pipe w i t h flow rate o f 10 m ü l i o n m ' per day by the end o f the life cycle, U value equal to 1.05 w / m ' °C was obtained f o r the two 22" pipelines. Flow assurance is feasible for all scenarios. The most critical scenario is the SB because it needs either pipeline insulation or MEG continuous injection.
Risk assessment has been conducted for production loss. Fault trees constructed for each scenario have been analyzed i n terms of qualitative risk approach. The conceptual probability o f failure f o r the total production loss indicates that scenario I presents the best result. The satellite wells c o n t r i b u t e to decrease the probabihty o f a shut down. The possibility o f a shut down depends on export pipe system failure. For scenarios 2 and 3, there are additional possibilities o f faUure associated w i t h subsea multiplexed control and m a n i f o l d . I n relation to the total production loss it was concluded that the most rehable subsea arrangement system is that represented by scenario 1, followed by scenarios 3 and 2.
The p a r t i a l p r o d u c t i o n loss c o n s i d e r s o n l y one w e l l i n t e r r u p t i o n . A n a l y z i n g the subsea arrangements and respective fault trees i t can be observed that scenarios 2 and 3 are more rehable than scenario 1. The advantage of on-bottom import system using manifolds and electro-hydraulic multiplex control reflects on smaller failure p r o b a b ü i t y i f compared w i t h the i m p o r t and export dynamic risers i n scenario 1. I n general, it can be concluded that scenarios 2 and 3 are more reliable than scenario 1 f o r partial p r o d u c t i o n loss. I n this case i t is d i f f i c u l t to distinguish scenarios 2 and 3. Although scenario 3 has two redundant export pipelines, the transport o f water/ gas mixture increases the probability o f hydrate f o r m a t i o n i f compared w i t h scenario 2, although i n this scenario there is no pipeline redundancy.
Considering that the total production loss is associated w i t h a failure probability substantially smaller than f o r the partial production loss, the indication o f the most rehable scenario should take into consideration small production losses during the life cycle. Satelhte wells associated w i t h dynamic risers p u t the scenario 1 as the less attractive alternative. A l t h o u g h equivalent i n terms o f partial production loss, scenario 3 is m o r e reliable than scenario 2 f o r t o t a l p r o d u c t i o n loss. T h e r e f o r e , based o n the quaUtative risk assessment f o r production loss, the scenario 3 can be indicated as the best option f o r the considered offshore gas field. The possibility o f gas/water subsea separation and subsea gas compression, before export to onshore t e r m i n a l , could mean an outstanding advantage f o r Subsea to Beach scenario i n relation to b o t h Semi-submersible and Jacket scenarios.
Cost analysis indicates close capital returns f o r the three scenarios. Subsea to Beach has the best NPV, US$ 172.41 m i l l i o n for the oil barrel o f US$ 25.00 and US$ 643.21 m i l h o n for US$ 45.00. These results are 37.7% and 8% greater than tiie lowest ones of US$ 125.20 m i l l i o n and US$ 596.00 m i l l i o n for Jacket p l a t f o r m scenario.
As general conclusion the Subsea to Beach scenario is the best o p t i o n according to the obtained results. However, additional technological developments associated w i t h subsea gas/water separation and subsea gas compression are strongly recommended i n order to have this o p t i o n commercially available i n the near f u t u r e . Aspects related to subsea e q u i p m e n t r e l i a b i l i t y and r e m o t e c o n t r o l are also o f paramount importance f o r the unmanned Subsea to Beach concept.
8 Acknowledgements
The authors w o u l d like to express their appreciation t o PETROBRAS f o r the outstanding support during the research w o r k o n Subsea P r o d u c t i o n Systems. The report "Subsea Production System f o r Gas Field Offshore Brazil" also based o n the m e n t i o n e d research was the 2005 w i n n e r o f the I n t e r n a t i o n a l S t u d e n t O f f s h o r e D e s i g n C o m p e t i t i o n p r o m o t e d by A S M E / O O A E , S N A M E and other prestigious international societies. Two o f the authors, Segen F. Estefen and Jian Su, are research fellows o f the Brazilian Research C o u n c i l ( C N P q ) .
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Scenario Evaluation for Subsea Production System
Tiago P. E s t e f e n . Daniel S . W e m e c k , Diogo d o A m a r a l , J o a o Paulo C . J o r g e , l e a n d r a C . Trovoado, J i a n S u , E d s o n L a b a n c a and S e g e n E E s t e f e n
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