Módulo 3 - Apostila

CURSO WEB

OGM

MÓDULO 3

Sumário

1 Substructures ................................................................................................ 4

1.1 Jacket ..................................................................................................... 6

1.2 Gravity Based Substructures ..................................................................... 7

1.3 Jack-Up ................................................................................................... 8

1.4 Floating, Production, Storage and Offloading (FPSO) .................................. 8

1.5 Semi-Submersibles ................................................................................... 9

1.6 Tension Leg Platforms (TLP) ................................................................... 11

1.7 Compliant Tower .................................................................................... 12

1.8 Spar ...................................................................................................... 13

1.9 Floating, Production, Drilling, Storage, Offloading (FPDSO) ....................... 17

1.9.1 Storage ........................................................................................... 17

1.9.2 Off-loading ...................................................................................... 17

1.9.3 Mooring ........................................................................................... 17

1.9.4 Multi-Platform Complex .................................................................... 17

2 Individual Facility Platform Configuration ....................................................... 18

2.1 Bridge Connections ................................................................................ 20

2.2 Bridge Reports ....................................................................................... 21

3 Subsea Facilities .......................................................................................... 21

4 Riser Tower ................................................................................................. 22

5 Terminus Facilities ....................................................................................... 23

5.1 FSO ....................................................................................................... 23

5.2 CALM .................................................................................................... 23

5.3 Terminal ................................................................................................ 23

5.4 Tankage System .................................................................................... 24

6 Offshore Processing Facilities........................................................................ 24

6.1 Reservoir Fluids ..................................................................................... 25

6.1.1 Setting the Reservoir Fluids .............................................................. 25

6.2 Kill System ............................................................................................. 27

6.3 Drilling System ....................................................................................... 27

6.3.1 Drilling Setting ................................................................................. 29

6.4 Wellheads and Manifolds ........................................................................ 30

6.5 Wellhead Platforms ................................................................................ 33

6.6 Oil and Gas Production ........................................................................... 34

6.7 Separation ............................................................................................. 35

6.8 Crude Metering and Export ..................................................................... 43

7 Tutorial 2 .................................................................................................... 45

8 References .................................................................................................. 66

Chemtech Serviços de Engenharia e Software Ltda. 4 AS INFORMAÇÕES CONTIDAS NESSE MATERIAL PERTENCEM À CHEMTECH E NÃO PODEM SER REPRODUZIDAS SEM AUTORIZAÇÃO.

1 Substructures

The objective of this section is to review the different types of substructures available in OGM and the basics of the design inputs associated to each type.

Substructures are fixed or floating structures that support the topsides facilities. The substructure selection also has a strong influence on the total project cost and ultimately the economic feasibility of the project. OGM offers the following substructure types that are applicable for specific water depth ranges and services:

• Jacket;

• Gravity Based Substructure (GBS);

• Jack-Up;

• FPSO;

• Semi-Submersible;

• Tension Leg Platform (TLP);

• Compliant Tower;

• Spar;

• FPDSO.

Input design specifications are in general unique to each substructure type. Input specifications are made from the Topsides Flowsheet under the Substructure button.

Two reports dedicated to substructures are available from the Offshore Report Menu in the OGM Output Reports Tool:

Substructure Technical Summary

The Substructure Technical Summary provides a summary of substructure design specifications along with size and weight of all substructure components. For some substructures GBS and semi-submersible substructures, convergence pass/fail conditions are also reported.

Substructure Cost Summary

The Substructure Cost Summary provides a cost for all equipment items, transportation and installation of the substructure, and all indirect costs (engineering, project management. etc.).

To assist the user, a series of tables have been prepared to provide reasonable limits to some of the technology applications. OGM Deepwater’s technical definition flexibility is not limited to current industry experiential limits, but rather allows the user to create a design and estimate for what is perceived to be the projected technology limit at the time the project will be executed in the future. Projected limits are based on either reasonable applications of existing technology or likely foreseeable technology advances in the next five years. Unlikely or unforeseeable advances have not been included. Table 1.1 shows the general water depth limits of experience and projected limits for substructures, pipelines and risers. Table 1.2 shows the general payload limits of experience and projected limits for substructure types.


Table 1.1: Water Depth Limits


Table 1.2: Payload Limits for Platforms

A technology report can be generated by the user to evaluate the facility design basis for an offshore development project against current limits of technology.

A database output report called “Technology Report” under the “Field and Total Facility Reports” section allows the user to compare the facility design basis for a field development against the set limits of offshore technology.

Technical threshold limits of several design criteria for each type of offshore production facility can be set based on the type of environment (mild/ moderate/harsh). These design criteria include maximum and minimum water depth, maximum topside weight, maximum riser count and maximum well count for various types of offshore production facilities.

The region of the installation determines the type of environment. For example, the Gulf of Mexico is considered as a moderate environment. Default values for the threshold limits are based on the current typical design of installed facilities; outliers and unique facilities are ignored. Guidance is not provided for facilities located in arctic environment due to limited data. The user is advised to evaluate the facility design basis carefully if the design lies outside the threshold limits.

1.1 Jacket

A jacket is a piled steel structure valid from 20 ft up to 1200 ft in water depth that may contain anywhere from 4 legs up to 12 legs piled into the seafloor. OGM sizes the substructures based on data sets that are dependent on the water depth, 100 year


significant wave height and topside size and weight. In OGM, jacket is represented by the following icon:

Database options include:

• G.O.S.P: The GOSP database represents over 150 data points collected from GOSP JIP participants and is recommended for most cases. Platforms with 4, 8 and 12 legs are allowed with the Historical and Modern databases, while platforms with 4, 6, 8 and 12 legs are allowed with the GOSP database. Jackets have the option of multilevel modular topsides or a multi-level, integrated, or stab-in, deck.

• Modern: The modern database represents the lighter substructures primarily in milder environmental conditions and is limited to water depths less than 600 ft.

• Historical: The historical data base is a curve-fit of historical information over a wide variety of environmental conditions and includes designs of up to 1,100 feet water depth. It best reflects older type jacket designs.

1.2 Gravity Based Substructures

A Gravity Base Structure (GBS) resists the various environmental forces by utilizing the weight of the structure on the sea-bed rather than, for example, using piles or mooring lines. The structure is designed specifically for the user’s requirements of oil storage volume, water depth, dimensions of the deck and other factors. The GBS module was designed to consider multi-legged structures and caisson type structures. Examples of some of the different structure geometry that can be generated and evaluated using the GBS module are shown in the User's Manual.

The environmental forces acting on the GBS are seismic forces, wave forces and ice forces. The module, in the most automated mode, calculates the On-bottom stability of a large number of geometrical variations (1,000 to 10,000) of the structure against the environmental forces along with the floating stability of the structures during the set-down procedure. The module also calculates the construction cost, the major cost items being the cost of the steel and/or the cost of the concrete along with the cost of any solid ballast required. Of those structures satisfying the various stability constraints, the lowest cost structure found is selected. If a structure geometry that satisfies all of the stability constraints cannot be found by the program, an approximate solution is presented. There are 3 different user selectable calculation modes that are described below in the Calculation Modes section. The module also considers foundation options such as subcuts and berms in evaluating the design of the structure. The GBS Module is intended to be used for the Conceptual or the Preliminary Engineering Phase of a project. Default environmental force parameters are provided for the offshore Sakhalin region. Calculations for other geographical regions are performed when the user provides appropriate values for the seismic, wave and ice force parameters.


1.3 Jack-Up

The jack-up substructure is a converted jack-up drilling rig using a single, open deck design for the topsides facilities applicable in water depths ranging from 50 to 300 ft.

In OGM, jack-up is represented by the following icon:

1.4 Floating, Production, Storage and Offloading (FPSO)

Floating Production, Storage and Offloading (FPSO) facilities are ship-shaped vessels designed to support fluid processing on the deck, storage in the cargo tanks and crude off-loading. A major advantage of FPSOs is that they can provide oil storage, which avoids a long and expensive pipeline to shore. This is especially attractive in remote areas. Offloading generally occurs every few days when an oil tanker arrives at the production site. The oil is then transferred from the FPSO to the tanker and taken by the tanker to a refinery.

Figure bellow shows the mainly system presented in FPSO facilities.

Figure 1.1: FPSO

In OGM, FPSO is represented by the following icon:

Bellow are listed the functionalities of a FPSO facility.


• Floating: When selecting the optimum type of floating system, field location, environmental conditions, water depth and production rate are major factors. FPSOs are a very versatile offshore installation. At the end of a life for an oil field, these vessels are designed to enable them to move to another location and start work on pumping another oilfield dry over a period of years;

• Production: Reservoir fluids are processed on the FPSO to enable stabilized crude oil to be exported by tanker. Gas is generally used as fuel on the FPSO. The production is carried out on topsides equipment that process and separate the oil, gas and water produced from the wells. Topsides structures also include the turret assembly, the flare tower, the power generation module, the offloading reel and the platform cranes;

• Storage: Once oil moves from the reservoirs into the FPSO and is processed, the oil will be stored within the vessel storage tanks. FPSOs are now globally required to be double hulled thus providing double containment. FPSOs are usually rated by storage capacity. Most FPSOs can store at least 500,000 bbls and some have been designed to store up to 2 million bbls;

• Offloading: Oil is moved from the FPSO into shuttle tankers via the vessel's offloading system - designed for wave 'significant' heights based on the region of operation. There are number of methods of transferring oil to shuttle tankers. A simple method involves pumping oil through a hose into another tanker via a Single Point Mooring buoy located close-by;

• Mooring: An FPSO is mooring in place using one of three methods: external turret, internal turret or spread mooring. The type of technology to be used is based weather conditions and operational conditions;

• Region: Areas with the highest concentration of FPSOs are the North Sea, South East Asia and West Africa. Other regions include South China Sea, Australia and the Mediterranean Sea. The Gulf of Mexico had been restricted by MMS (Minerals Management Service) regulations until recently in using FPSOs in the region but is now being evaluated by the MMS on a project by project basis. Each region has a cost structure that makes certain operations less expensive and feasible than others do.

FPSO’s are valid in water depths from 100 ft up to 10,000 ft and the default water depth is region dependent.

1.5 Semi-Submersibles

Semi-submersible platforms have been used, among other applications, for offshore drilling and/or production in relatively shallow to deep waters for decades. Semis offer a unique combination of the ability to carry large payloads, limited sensitivity to water depth, and a design offering the ability to move after abandonment. OGM only offers the option to simulate a newly built semi-submersible.

The new-build semi-submersible configuration in OGM is based on a four-column design (see figure bellow) as used primarily in the Gulf of Mexico and the North Sea.


Figure 1.2: Semisub

In simplest terms, a good semi configuration is one that has the lowest capital expense while meeting, among other things, the following key requirements:

• Adequate column span to support the specified deck size and payload;

• Sufficient freeboard to avoid significant under-deck slamming in storm conditions;

• Adequate stability for the expected operational, survival as well as transit conditions ;

• Good motion characteristics.

Figures bellow shows this type of facility.

Figure 1.3: Typical Semi-Submersible

In OGM, semi-submersible is represented by the following icon:

Other design considerations include constructability, access and ballasting capacity to maintain stability and draft and even keel.


Calculation routines are provided in OGM to ensure that an optimal configuration is developed that meets these requirements. In developing the hull configuration, OGM uses a simplex algorithm to search for the optimum solution in terms of the total capital expense subject to various constraints imposed by the above requirements. A rational set of constraints is provided, but the knowledgeable user may wish to vary some of the constraints. Because of the nonlinear nature of the problem in developing such a configuration subject to those constraints, the linear programming algorithm may converge to a locally optimal solution.

Under some conditions, it may be difficult for OGM to produce a design that meets all sizing constraints. When this happens, the user may need to look carefully at the rationality and stringentness of the constraints as well as the "quality" of the starting point beside other input data. For those less experienced users, it is highly recommended that the user allow OGM to internally determine the initial size guesses as well as the sizing constraints. Be aware that extra caution should be taken when modifying the constraints.

TIP: Problems with semi-submersible substructure convergence can typically be resolved with one or all of the following design changes:

• Reduction in number of decks lowering the center of gravity;

• Increasing the deck size;

• Increasing the semi submersible draft.

To increase the draft, the semi submersible sizing option will need to be changed to allow specification of initial dimensions and then the Max Operating Draft sizing constraint will need to be increased.

1.6 Tension Leg Platforms (TLP)

Tension Leg Platforms (TLPs) are allowed in water depths from 500 to 6,000 feet. OGM models steel TLPs comprised of four equidistant columns connected by either round or rectangular pontoons. OGM will calculate the hulls weight, as well as other substructure information such as conductor weight and riser weight, as a function of the dimensions of the TLP, topsides weight and water depth. It will then use this information, as well as the specified pretension on the tendons, to predict a ballast weight to achieve a specific draft, which may be specified by the user or internally estimated. OGM also provides options to model 3-column and single column configurations as well. OGM does not attempt to determine the stability or hydrodynamic response of the design. Several systems are considered integral to the TLP hull and are not separately modeled. These systems are: the ballast tanks, pumps and associated piping; the tendon tensioning systems, and all caissons. TLPs have the option of single level modular topsides or multilevel integrated deck. Skidded equipment is allowed on the weather deck.


Figure 1.4: Typical Tension Leg Platform

In OGM, TLP is represented by the following icon:

1.7 Compliant Tower

Compliant towers have proven to be technically and economically competitive in water depths ranging from 1,000 ft to as deep as 2,000 feet where building a traditional steel jacket is not practical. A compliant tower is tall, slim steel tower that sways slightly, or complies with wind and wave forces. The two most common tower designs are available in OGM, the Piled Tower and the Base Plate Tower. Figure bellow shows a compliant tower.


Figure 1.5: Compliant Tower

Certain Compliant Towers are free standing and are designed to avoid dynamic amplification of wave loads applied to the tower (this is problematic in conventional deep water platforms). Compliancy is achieved by making the tower more flexible, thus yielding a long sway period (between 20-40 seconds) and making them bottom founded. Compliant towers offer continuous support to risers and conductors and are configured with axial tubes (two at each of the four legs of the tower section) and an articulation point that governs the dynamic characteristics of the structure. Being 'compliant', the tower is designed to be more flexible than conventional platforms and has a sway-response cycle, if subjected to a storm wave.

OGM estimates of compliant tower weights are based on weight correlations to previous tower installations and designs. Compliant towers are valid for mild, moderate and harsh environments, but due to the inherent nature of their design are usually more applicable to mild or moderate environments.

Tower direct costs are estimated by material cost per weight and labor man-hours per weight. Indirect costs are estimated based on percentages. Offshore installation costs can be found in the global installation screens.

In OGM, Compliant Tower is represented by the following icon:

1.8 Spar

One of the principal advantages of the Spar concept over other floating platforms lies in its reduced heave and pitch motions which allows the use of dry trees and SCRs (Steel Catenary


Risers). The dry trees offer direct vertical access to the wells from the surface. This allows the Spar to be configured for full drilling, workover, production processing or any combination of these. The Spar is unconditionally stable since its center of gravity is always below its center of buoyancy.

The Spar derives no stability from its mooring system, so it will not list or capsize even if completely disconnected from its mooring. The two most prominent hull configurations of a Spar are the Classic Spar and Truss Spar.

Figure 1.6: Spar Platform

In OGM, Spar is represented by the following icon:

The Spar hull consists of three main sections: the hard tank, the midsection and the soft tank. The hard tank, designed to resist hydrostatic pressure, provides the required buoyancy and contains the variable ballast required to maintain a constant draft with the varying topside payload. The pressure balanced soft tank contains fixed ballast to meet global performance requirements. The midsection connects the hard tank to the soft tank. In a Classic Spar configuration, the midsection is a cylinder with the same external diameter as the hard tank and soft. A Truss Spar utilizes a midsection with a containing heave plates that provide added mass and damping to ensure good motion.


Figure 1.7: Spar structure

Mooring lines are designed to keep the Spar on station during all normal and storm operating conditions. Mooring lines are generally semi-taut catenary systems. A single mooring line consists of a platform chain, mooring strand, and anchor chain. The platform chain is the part of the mooring line connected to the Spar. The middle portion of the mooring line is known as the mooring strand. The final portion of the mooring line is the anchor chain, which connects to the anchor at the seafloor.

Figure 1.8: Mooring lines

The hard tank and soft tank both contain a centerwell, which provides a passage for the vertical Top Tension Risers (TTRs), SCRs, and other piping systems. The size of the centerwell is governed by factors such as the number of wells, number of SCRs, water depth, top tensioning system, type of riser, pressure rating and other piping systems.

The risers play a major role in determining the size of the centerwell, which in turn determines the size and cost of the hull. Therefore, the type of riser system selected could have a major cost impact on the hull.

The risers are generally configured as a single casing riser or a dual casing riser. The selection of the type of riser system may be based on many factors, which may include operational requirements, previous experience, and perceived risks and rewards. In the single casing configuration, the riser is designed for high pressure. In the dual casing configuration, the inner riser is designed for high pressure while (generally) the outer riser is designed to a lower pressure rating to assist pollution containment. Due to fixed costs related to manufacturing set-up for top tension risers, the cost per riser may vary from scenario to scenario. This is due to the fixed start-up costs being distributed over the total number of risers.


Figure 1.9: Casing riser

The Spar hull sizing program calculates and determines the appropriate hull and mooring systems required to meet the requirements defined by the input parameters. The centerwell size is first estimated based on the well count, riser type, pressure rating, water depth, and top tensioning system. The smallest feasible diameter for the estimated centerwell is then selected. Look up tables are utilized to provide the hull component weights for the given geometry. The number and size of the mooring lines are calculated based on the hull diameter and the water depth. The outfitting load, fixed ballast, and variable ballast are then determined to perform the buoyancy and stability checks. If the checks pass, then the configuration and weights are used to calculate the cost. If the checks fail, then the hull diameter is increased and the process is repeated. The stability and buoyancy calculations are based on the following assumptions and loads (See the SPAR’s Sizing Methodology flow chart in the OGM manual):

• Global performance is defined by a static angle with the wind loads specific to the environment of the selected location;

• Wind loads are derived from correlation to existing projects;

• Component loads are taken from output of detailed Spar design tools;

• Hull steel component loads are defined by tables of detailed design results;

• Outfitting loads are defined by weights, hull geometries, and the number of mooring lines as derived from existing projects.


1.9 Floating, Production, Drilling, Storage, Offloading (FPDSO)

Floating Production, Drilling, Storage and offloading (FPDSO) facilities combine all functions into one large unit. These units can be ship-shaped, barge-shaped or based on other proprietary designs. A major advantage of FPDSOs is that they can provide both drilling and oil storage. This can be an attractive combination, especially in remote areas.

1.9.1 Storage

Once oil moves from the reservoirs into the FPDSO and has been processed, the oil will be stored within the vessel storage tanks. FPDSOs are globally required to be double hulled thus providing double containment. FPDSOs are usually rated by storage capacity. Most FPDSOs can store at least 1 million bbls, and some have been designed to store up to 2 million bbls.

1.9.2 Off-loading

Oil is moved from the FPDSO into shuttle tankers via the vessel's off-loading system - designed for wave 'significant' heights based on the region of operation. There are number of methods of transferring oil to shuttle tankers. A simple method involves pumping oil through a hose into another tanker via a Single Point Mooring buoy located close-by.

1.9.3 Mooring

An FPDSO is mooring in place using spread mooring, thereby limiting its application to mild environments.

1.9.4 Multi-Platform Complex

In OGM, the facilities configurations are represented as shown in figure below, as well as the representation in the software.


2 Individual Facility Platform Configuration

Figures below show the platform configuration in OGM.

Figure 2.1: Platform configuration


Below are listed some decision rules about this configuration:

Rule No. 1

Platform 'J' is not an optional platform. If only one platform is to be simulated, it will automatically be platform 'J'. It may have functions assigned to it, or may be a 'node' platform, with no equipment (supporting bridges and interconnecting piping only). Platform 'J' may be connected to a maximum of four other platforms (excluding well platforms).

Rule No. 2

Platform 'F' may only be a dedicated flare platform. It may be connected by bridge or subsea pipeline to any of platforms 'A' through 'E' or 'G' through 'J'.

Rule No. 3

The platform connections shown in the figure are fixed; i.e. platform 'H' may not be connected to platform 'J', platform 'A' may not be connected to platform 'D', etc.

Rule No. 4

The connect point of the well platforms is internally determined. If a dedicated manifold platform is specified, the well platforms will attach to it. Otherwise, the well platforms will attach to whichever platform is assigned the manifold function.

Rule No. 5

Bridges are named as shown by the lower case letters in the figure. This naming convention is also fixed; i.e. bridges 'a', 'b', 'c', 'd', are the only ones which may be attached to platform 'J' (unless the flare platform is attached), bridge 'e' may only attach to platform 'E' and 'A', etc. The bridges from the well platforms and flare platform are the only ones with variable attach points.

Rule No. 6

Functions (i.e. living quarters, oil production, water injection, etc.) may be assigned to the platforms in any combination. The related utilities and structural steel systems will be automatically allocated for each platform. Functions may not be assigned to one of the other platforms unless all intermediate platforms have assigned functions; i.e. functions may not be assigned to platform 'E' unless platform 'A' has been assigned a function.


Figure 2.2: Typical Two-Platform Facility

The following systems are allocated by platform, according to the functions assigned to each bridge connected platform:

Figure 2.3: Systems in a facility

2.1 Bridge Connections

Bridge names and locations are defined by the conventions given in the Platform Function Assignment Rules and illustrated by the figure. Only the flare platform and wellhead platforms (assigned elsewhere) have variable attach points.


The length of each bridge may be specified. The maximum unsupported bridge span may also be specified, up to a maximum of 400 ft. The bridge weights, including all piping necessary to connect platforms, are calculated internally. A 'heavy' bridge is used when a great deal of interconnecting piping must be supported. A 'lighter' weight bridge, primarily for personnel access, is used where applicable.

The operating weight of each bridge will contribute to the topside loading of the connected platforms. The bridge weight load will be divided between the connecting platforms or intermediate support platforms, if they are necessary.

Generally, shorter bridges have lower capital and operating costs, but longer bridges can better isolate non-hazardous function platforms from hazardous function platforms. If a hazardous function is not involved, a bridge length of 50 ft is suggested. Otherwise, bridge length of 150 ft is recommended.

2.2 Bridge Reports

• Bridge Installed Cost Summary Report (Offshore menu only): This report provides the direct, indirect and offshore costs for each selected bridge.

• Detailed Bridge Summary Report (Offshore menu only): This report provides a detailed description of each bridge, including the length, intermediate support structure characteristics, structural weight, piping weight and cable weights. Material and fabrication labor costs for each bridge element are also provided.

3 Subsea Facilities

Subsea tiebacks to fixed (or floating) platforms are considered:

• Whenever the reservoir is not commercially attractive when required to include a drilling / processing platform specifically for the reservoir, or

• Whenever the reservoir is too shallow to use horizontal wells, thereby requiring all vertical wells that then can’t be reached with a single platform drilling location, or

• Whenever the distance from the well target to the platform is beyond the reach limit of horizontal drilling.

When relatively dry, high-pressure gas is the subsea well product, the subsea transport distance can be great, sometimes exceeding 50 miles (80 km). When the reservoir product is a multiphase mixture of oil, water, gas and sand with low natural drive pressure, the tieback distance is reduced significantly, due to flow assurance concerns.

Subsea facilities including subsea trees, manifolds, control systems, umbilicals and flowlines allow for the economic development of marginal fields near in-place infrastructure or for fields with a large area extent.

The following issues should be considered when evaluating subsea development options:

• Recoverable reserves and projected oil/gas price;

• Number and location of wells;

• Drilling and servicing of wells;

• Required field life;

• Fabrication, transportation, and installation scenarios;

• Production and drilling facility requirements;


• Effects of well fluid properties;

• Means for export of oil and gas;

• Effect of development schedule on economics;

• Environmental conditions and water depth.

Satellite subsea wells are often produced separately by providing each well with means for crude flow, annulus flow, pigging, well control and chemical injection.

Manifolding well fluids together at the seabed reduces the number of lines back to the platform. The fluids from many wells can be manifolded together; but as the number increases, so does the size, weight and complexity of the manifold system. This increases engineering and fabrication time, thus delaying first oil production. Small manifolds can be installed with less expensive installation vessels, whereas large manifolds require the use of larger, more expensive installation vessels.

Notice that in OGM in the case of FPSO (and also Semi-submersibles facility) on the Screening Study Definition screen for any offshore topside facility, the flow rate inputs (Crude Production Rate, Gas Export Rate) define the flow rate for Reservoir Fluid number 1 and is not the throughput rate for the facility. Throughput for the facility is determined by the OGM simulator based on the combination of reservoir fluid rates for the different reservoir fluids at the facility (up to three are allowed) plus any imported well fluids from other facilities. For an FPSO and Semi-submersible, no local reservoir fluids can be specified as these types of facilities are considered "wet tree" facilities where all well fluids come from another facility (i.e. no wells trees controlling the well flow exist on the facility topsides). Thus, the flow rates on the Screening Study Definition screen are invalid because no local reservoir fluids exist.

In OGM, sub-sea facility is represented by the following icon:

4 Riser Tower

Riser towers allow multiple risers to be routed together in an insulated bundle that is supported in a vertical position near the surface facility. In addition, Riser towers transmit very little load to the host structure. To-date, most riser towers have been associated with FPSOs, but they can also be applied with other floating structure concepts, such as semi-submersibles or spars.

The primary motivations for using riser towers are:

• Less sensitive to environmental conditions (water depth and extreme wind, wave and current) than other riser types;

• Less load to the host structure;

• Efficient means of insulation;

• Concerns about riser towers include cost, easiness of installation and the lack of a long-term operability track record.


5 Terminus Facilities

5.1 FSO

Floating, storage & offloading (FSO) vessels can be used for oil storage and subsequent offloading. FSOs are normally used in remote areas where the main processing structure does not have large oil storage capability, such as jackets, towers, TLPs, Semis and Spars.

FSOs can be new built, but due to commercial reasons, they are often converted tankers. To facilitate tandem offloading, FSOs are usually turret moored. FSO turrets are usually simpler than turrets found on FPSOs, because the flow paths needed are much fewer.

5.2 CALM

CALM buoys are used in areas where tandem offloading is difficult or too risky. Shuttle tankers can hook-up to a CALM while offloading from an FPSO several miles away from the FPSO, which dramatically reduces the risk of a collision.

Figure 5.1: CALM buoy

5.3 Terminal

Terminal facilities in OGM are designed for export. No fluids are returned to processing sites from the terminal. Processing required for the export pumps is the limit to the processing capabilities at the terminal.

The liquids entering the terminal, which may be crude, condensate, propane, butane and/or products from gas-to-products are specified by an expected inlet flow rate. If a flow rate is not specified, the export rate from the central processing facility will be used. The liquids may be sent to storage tanks if desired. The total number of storage tanks will be calculated from a specified days of storage capacity and volume per tank. A tankage manifold may also be specified as a lump sum cost. Pumps, metering, jetties, offshore loading, rail loading, road loading are all possible options for exported fluids, with the last four items being optional cost only items. The specified export rate will be used to size export pumping and metering facilities.

Optional utility facilities available at the Terminal include a flare, fire protection equipment and buildings. Electricity necessary to run equipment may be generated locally or imported. If power is generated at the terminal, the power generation equipment options will depend on the fuel available. If only oil lines enter the terminal, no gas engine generators and no turbine alternators will be available for power generators. Electrical, instrumentation and PVF bulks will be allocated as necessary depending on the facilities present.

Terminal costs include any facilities at the terminal plus any of the following:

• Jetties;


• Roads;

• Power Lines;

• Water well/line;

• Dredging;

• Buildings;

• Terminal tankage - (Oil and LNG) based on number of days of storage or a specified value of Tankage;

• Single Point Mooring including pipelines from the terminal;

• Road and/or Rail Loading;

• Security.

5.4 Tankage System

Storage tanks may be allocated for crude, diesel fuel, produced water, slop oil, and chemicals. Each tank is atmospheric, designed as cone roof or floating roof and allocated with fire protection. Multiple tanks may be allocated for crude and produced water based on the number of storage days required, while only one tank will be allocated for each of the other fluids.

6 Offshore Processing Facilities

The starting point for definition of topside facilities is the Screening Study Definition screen discussed in Module 2. This screen provides the key input values to do a quick, early phase estimate of a facility. For greater accuracy, more detail is required regarding well fluid definition, process conditions, equipment design, and facility design. To do this, click on the Flowsheet button on the Screening Study Definition screen to display the Topsides Flowsheet window (see Figure below).

Figure 6.1: Topsides Flowsheet


From the Topsides Flowsheet, the user can step through the process flow and specify details about step of the process along with details for all utility and structure aspects.

6.1 Reservoir Fluids

There are five main types of reservoir fluids.

• The Black Oil is characterized to make up of non-volatile hydrocarbons. Its initial gas-oil ratios is 2000 scf/stb or less, increasing this value during production with the pressure decrease;

• Volatile Oil has more ethane through hexane than black oils and initial gas-oil ratios in the 2000 to 3300 scf/stb;

• Condensate Gas have some similarity with latest kind of oil reservoir, but because of its temperature, greater than critical temperature of the fluid, under a condition at the same pressure and temperature, Volatile Oil is a liquid and Condensate Gas is a gas;

• Wet Gas has a natural gas that contains significant propane, butane and other liquid hydrocarbons. Unlike Condensate Gas, no liquid is formed inside the reservoir. Attention: Do not confuse the condensate, formed through separation phase and Condensate Gas;

• Dry Gas is the hydrocarbon mixture solely at the gas phase and does not form condensate, either in the reservoir or at surface.

The difference between Wet Gas and Dry Gas is presented in the figure below. Note that on the right side of the figure, the reservoir pressure path line (1-2) does not intercept the dew point line and the point ‘Separator’ falls outside of the liquid region, hence no condensate is formed either in the reservoir or at surface.

Figure 6.2: Pressure path in reservoir

6.1.1 Setting the Reservoir Fluids

Reservoir fluids are assumed to be those fluids produced within the facility being simulated and their compositions are given in molar percents. The actual flow rate of each stream will be adjusted to meet the specified reservoir simulation basis.

The composition should be specified separately for each reservoir fluid. If not specified, the default composition will be calculated (as described in section 4.1.4.2 of the OGM manual).


Temperatures, pressures and other properties, as well as the entry point into the separation system can be specified independently for each fluid (Figure 6.3).

Figure 6.3: Specifications for Reservoir Fluid screen

The stream composition can also be specified by clicking on the Specify button on the Reservoir Fluids screen (Figure 6.3) and then selecting the Specify Composition option on the Specifications for Reservoir Fluid screen. For heptane and heavier, two pseudocomponents can be specified where the fluid properties are determined either based on the pseudocomponent API gravity and Average Molecular Weight or by critical properties.

The specified gas oil ratio (GOR) is only used to estimate the reservoir fluid composition. The gas oil ratio for separators calculated by the process simulator is influenced by the process configuration and operating specifications, and may not be the same as the one used to estimate the reservoir fluid composition.

TIP: To see what composition OGM assumes for a specific GOR, first set the GOR and then select the Specify Composition option and click on the Fill Composition button. This feature is handy when only the GOR is known but high CO2 or H2S is known to exist in the well fluid.

The design production rates for each stream are not independent. All production rates must be specified in the same units and the rates will be summed to determine the overall simulation basis. For example, if two reservoir fluids are specified and the daily crude production rate is chosen for the simulation basis (Figure 6.4), then we may specify the daily crude production rate for reservoir fluid 1 as 75,000 and for reservoir fluid 2 as 100,000 bpd.

Figure 6.4: Reservoir fluid screen


The simulation will then be run to achieve a total of 175,000 bpd. Due to differences in composition of the two reservoir fluids, the ratio of the production rates may not be maintained.

Imported streams are assumed to have a fixed, known flow rate. The model calculates the stream compositions and flow rates when the source satellite is simulated (Figure 6.5). Imported stream flow rates are not adjusted in the process calculation iterations to meet the design simulation basis.

Figure 6.5: Crude production rate

The temperature and pressure of each imported stream should be specified. For thermodynamic calculations these are assumed to be the temperature and pressure at the point where the stream enters the separation system.

6.2 Kill System

A kill system is used to secure a production well should a downhole communication develop between tubing and casing. The kill system may include one or two diesel-driven kill pumps, a kill system manifold, piping to the manifold and perhaps weighted drilling mud storage. A kill system is normally provided only as a backup to normal inhibiting programs when downhole corrosion problems are anticipated. A kill system on a platform is not normally designed to overcome a blowout, but to fill the well with weighted fluid or sea water in adequate measure to overcome flowing conditions. A workover rig may be needed to remove kill fluid, fix the downhole problem and restore the production well to a flowing condition.

A production well may have two or three well kill connections for the tubing and casing. If remote operation of the kill valves attached to the wellhead is desired, a kill sequencing panel is needed to override the normal shutdown sequence. The kill valve sequencing panel for the wellhead valves is normally placed at the kill pump location, away from control room personnel.

6.3 Drilling System

Drilling equipment on a platform (Figure 6.6) has highly variable operational loading because of consumables: barites, cement, liquid fuel and drilling tubulars. Weight tabulations for a


drilling package will vary with the type of well completion, weight of drilling fluid, depth of well, environment and amount of personnel support.

Figure 6.6: Drilling equipment

Three types of drilling rigs may be simulated with the careful specification of this category of management decisions:

• Integrated, self-contained drilling rig;

• Workover rig only;

• Barge-assisted drilling rig.

The American Petroleum Institute (API) tabulates several specifications of drilling rig packaging on self-contained platforms. Configurations are outlined and drilling guidelines for modules are tabulated. These guidelines are applicable for relatively shallow water and a nominal number of conductors.

The self-contained drilling rig is only one of many configurations. If a multi-function platform is being planned, liquid fuel storage and power generation (in some cases) may be shared with the production operation.

The cost of purchasing or leasing drilling rigs is a user defined lump sum cost. The cost of drilling production, gas injection, water injection and water wells is calculated based on user defined number of wells, average depth of each well and cost per well depth.

Drilling facilities can often have a significant impact on the weight and cost of the structure and the entire facility. When Drilling is specified, an integrated drilling system is defaulted.

The associated drilling cost results appear in a several reports, two of these are:

• Deck area allocation by level (Offshore menu only): For facilities where multiple decks are an option, area allocation for each deck level is reported. Area allocation will be listed production/utility equipment, living quarters, drilling equipment and laydown


area, and the wellbay area. In addition, any unallocated area or unusable area is reported. Deck dimensions for each level are also reported.

• System Weight & Area Summary Report: This report provides, for each selected facility, a system by system breakdown of the equipment area, allocated area, equipment dry & operating weights and bulks dry & operating weights. The total dry/operating weights on this report are the total weights for the topsides including drilling, if applicable.

6.3.1 Drilling Setting

There are several drilling configurations available that allocate weight and area to a facility dedicated for the drilling rig, related equipment and laydown area. Drilling configurations include integrated drilling rigs, workover rigs, coiled tubing units and a barge-assisted rig. Estimates can be generated using a first level estimate, just marking the Drilling Option for default, where the overall drilling area and weight is determine, or using a second level estimate where specifications for individual components are defined (Figure 6.7). The last one can be access and modified through the Topsides Flowsheet showed in the previous section.


Figure 6.7: Drilling screen

6.4 Wellheads and Manifolds

The subsea wellhead and its protection are showed in the Figure 6.8 (left side). As its name means, the wellhead is a group of valve installed on the subsea surface (head of the well) and together with the christmas trees are the main equipment for oil production, controlling wellhead pressure, adjusting well flow rate and transporting oil to pipeline.

The manifold (showed on the right side of the Figure 6.8) is a metal structure supported on the subsea surface that contains valves and tools connecting christmas trees, production systems, piping and risers. This example of a manifold was developed by Aker Solutions to be installed on Espirito Santo Basin and is called Plem (Pipeline End Manifold). It is a huge


structure used to connect many gas wells, composed by a main structure, with coupled production modules, which weights 293 ton.

Figure 6.8: Wellheads and Manifolds

The wellheads and manifolds section provides for the specification of the number of wells and equipment associated with the wellheads and manifolds, including lift pumps, wellhead heaters and chemical storage.

Several configurations of the wellhead(s) and manifold(s) may be simulated. The wellhead function may be assigned to an integrated platform or to one or more dedicated wellhead platforms. The manifold function may be assigned to a dedicated manifold platform or to an integrated platform. If wellhead platforms are specified, they will be attached to the platform that has been assigned the manifold function. Wellhead platforms may not attach to each other. If more than one wellhead platform is specified, the manifold function must also be assigned to a platform that will tie in all the wellhead platforms. The specification of manifold function location refers only to the manifold that feeds directly to the main process separators.

The wellheads and manifolds encompass specifications for the well counts and manifold configurations for the following fluids:

• Production fluids;

• Injection water;

• Injection gas;

• Acid gas for injection;

• Source water used for water injection.

Additionally, options for submersible pumps, wellhead heaters, corrosion inhibitor injection pumps, pigging pumps and through flow line tool access can be specified. Figure 6.9 shows the Manifold screen for a Jacket Substructure and Figure 6.10 shows the subsequent Manifold screen.


Figure 6.9: Wellheads and Manifolds screen

1. Center-to-center between conductors, its default values are 14 ft for TLP and 7 ft for others in Brazil;

2. In this case (Jacket), it means the number of wellhead platforms and is used to determine the number of trees;

3. Exceeding conductors, its default value is 25% of well numbers;

4. The pressure used to design equipments and valves;

5. Corrosion inhibitor injection like MEG in the PMXL-1 platform (Do you read something about this during the Module 2 exercise?);

6. Injection rate of corrosion inhibitor (gpm/prod well) used to size the pumps;

7. Static pressure at or near the bottom of the wellbore used to size the pump power;

8. Turn on the area and weight allocation for the flowline loops and control panels is included in the manifold system;

9. The flowline from the wellhead to the manifold.


Figure 6.10: Manifolds screen

1. Number of parallel manifold. Default value: one log per 10 local wells;

2. If selected manifold logs will be stacked two high, reducing the amount of deck area taken by the manifold system;

3. Used to determine the weight and cost of the manifold valving;

4. Default: 110% of flowing wellhead pressure and/or > First stage separator design pressure + 50 psi;

5. This specification will be used to determine the pressure rating of the production manifolds. Range: Manifold Design Pressure, psig > (First Stage Separator Design Pressure +

50 psi)

Default: 110% of Flowing Wellhead Pressure.

6.5 Wellhead Platforms

Separate wellhead platforms have very light operational loading unless they are designed to support a workover rig, which is not included in this simulation. The equipment on a wellhead platform is limited because of the high risks. Each wellhead platform may have production wells, gas reinjection wells, water injection wells or any combination of the three. If the wellhead is to be part of an integrated platform, the number of wellhead platforms should be specified as zero.

The design parameters for wellhead platforms must be specified separately from the main production specifications. These management decisions are used only to size equipment and piping on the wellhead platforms and bridges. For instance, the combined design production flow rate for all wellhead platforms does not necessarily equal the main production design flow rate specified. This allows production rate, gas/oil ratio and wellhead conditions to be


independently specified for each wellhead platform, subject only to the constraints of production type (oil or gas).

A production manifold is optional on wellhead platforms. If multiple production wellhead platforms are simulated, a manifold will be necessary on a main complex platform. If a single production wellhead platform with manifold is simulated, a production manifold is not necessary on a main complex platform.

Four topside systems are assigned to wellhead platforms: manifold, finishing steel, stab-in support deck and wellhead platform system. The wellhead platform system includes an optional test separator and reduced amounts of utility and material handling equipment. Use of the individual utility systems would have resulted in an unnecessarily large topsides load. The minimum platform dimensions are 25 feet by 25 feet. Wellhead platforms are not recommended in water depths greater than 400 feet, due to the current limitations of jack-up type workover rigs.

6.6 Oil and Gas Production

The separation system consists of gas-oil-water separators and process exchangers (if required). Program flexibility allows up to three trains of gas-oil-water separation, up to five stages of separation with produced water removal at any stage and combinations of vertical and/or horizontal production separators, powered centrifuges and dewatering hydrocyclones. Additionally, up to three reservoir fluids may be simulated on each facility, satellite or host, and the host may further process hydrocarbons imported from satellite facilities.

For onshore facilities, each gathering station may have up to five stages of separation with up to twenty trains. An emulsion treater may be specified as the last or next to last stage. A test separator is also available. All of the sizing methods available at the CPF are available at the gathering stations.

A low pressure production manifold may be added to accommodate streams entering between the first and second separation stages. A dedicated receiver separator may be allocated for each fluid.

The number of separation stages should be evaluated against the amount of liquid recovery per stage and may be minimized if condensate from gas compression is recovered and recycled to the crude being exported. A balance of the number of separation stages with the minimizing of gas compression horsepower may be carefully evaluated. Generally, minimizing the number of separation stages is more important than minor reductions of compressor horsepower.

The first stage separation pressure is determined by evaluations outside the scope of this program since it is related to available reservoir pressure, reservoir pressure decline predictions and wellbore flow. The design pressure of the first stage separator and gas treatment facilities prior to compression may be specified in order to design for maximum operating pressure and maximum production rates, which may not be coincident.

When oil production facilities are specified, crude emulsion treatment/desalting equipment may be allocated in the gas-oil separation system as the last or next to the last stage of separation. Interstage booster pumps are allocated if the process calls for crude emulsion treatment at higher pressure than the previous stage of separation. Crude booster pumps may be allocated before the crude metering/export facilities.

Additional information and variables regarding specification of emulsion treaters/desalters can be found in the "Crude Emulsion Treatment" section of this manual.


When gas production facilities are specified, associated condensate from the last stage separator is combined with condensate from the gas compression/treatment facilities. This combined stream is coalesced and spiked in the gas pipeline or shipped by a dedicated pipeline. Crude metering/export facilities are not allocated for gas production facilities, but meters and pumps may be allocated in the condensate disposal system.

OGM can simulate up to three reservoir fluids with facilities able to import additional hydrocarbon streams. Each stream can enter into the separation system prior to the first or second separation stage or into a dedicated receiver separator. One low pressure manifold may be allocated between the first and second separation stages.

6.7 Separation

The separation system provides options necessary to appropriate separate crude, gas and produced water, break emulsions and stabilize crude for transport. OGM allows up to five stages of separation plus a crude stabilizer. Separation configurations are managed using the graphical Separation System input screen as displayed in Figure 6.11.

Figure 6.11: Separation System graphical input screen


The separation system consists of the main gas-oil-water separators and the required process exchangers. Crude cross exchangers are available prior to each separation stage. Program flexibility allows for up to twenty (20) separators per stage of separation as well as sizing based on different flow percentage for each stage. Up to five stages of separation are available including options for produced water removal at any stage and any combination of vertical and/or horizontal production separators. A crude stabilization column may be specified to follow the last separator when less than five stages are specified.

The number and configuration of separation stages may be evaluated against the amount of liquid recovery per stage. The number of separation stages may be minimized if condensate from gas compression is recovered and recycled to the crude being exported. A balance of the number of separation stages with the minimization of gas compression horsepower may be determined. As previously explained, generally, minimizing the number of separation stages is more important than minor reductions of compressor horsepower.

Figure 6.12 illustrates the major equipment allocated in the separation system.

Figure 6.12: Separation Facilities Multistage Separation System

All incoming local reservoir fluid streams and streams imported from other facilities are show to the left of the screen. Dedicated receiver separators for an incoming stream can be allocated by right-clicking on the stream and selecting the option from the pop-up menu as shown in Figure 6.13. Once selected, a receiver separator will be displayed on the graphical screen. Left-clicking on the receiver separator will open a screen that provides design specifications for that specific receiver separator (similar to the main production separator design inputs displayed in the figure). Left clicking twice on a Local Production line will open the Specifications for Reservoir Fluid screen already discussed.


Figure 6.13: Separation Stream Options

Right clicking on the graphical screen background will bring up a menu shown in Figure 6.14 that allows the user to:

• Turn on or off the option for separation;

• Add or remove separators;

• Add or remove a test separator;

• Add or remove a crude stabilizer.

The graphical drawing will represent any changes to the separation system configuration made on the menu. A link to the Reservoir Fluid screen is also available from the menu.


Figure 6.14: Separation Options Menu

Clicking on the Further Define option on the menu brings up a Production screen (see Figure 6.15) with additional separation system specifications. Below are a few key points about the inputs on this screen:

• The Option to Recombine Process Fluids applies to a separation system with a single stage of separation and is used to remove produced water from the well stream and then recombine the crude and gas for export from the facility.

• The Viscosity of Export Crude is used for calculation of separator sizing for several of the separator sizing methods (viscosity controlling, BS&W, slug flow), pump efficiency calculations and export crude pipeline hydraulic calculations.

• The Reid Vapor Pressure (RVP) of Exported Crude when specified will change the temperature and pressure of the last stage of separation (not including the crude stabilizer or emulsion treater) to meet the desired RVP. Care should be taken in using this specification as separator conditions may change significantly depending on fluid composition and upstream separator conditions. Last stage separator conditions can be altered manually to meet the desired RVP. The crude export stream summary in the text output report will report the True Vapor Pressure for the stream for reference.

• Maximum separator dimensions can be set to put an upper limit on separator design. If the separator exceeds the set dimensions, an additional train will be added until the separators no longer exceed the dimension limits.

• The sand removal configuration applies to all separator stages that have the sand removal option checked. Typically, sand removal will be specified in the first stage of separation.


Figure 6.15: Additional Separation System Specifications

Separator pressures can be reset from the main separation graphical input screen simply by clicking on the separator pressure and changing the value. Right-clicking on an individual separator on the main separation graphical input screen will display a menu that allows the user to specify whether water is separator and the destination of the vapor from the separator (see Figure 6.16).


Figure 6.16: Separator Stream Specifications

Left-clicking twice on an individual separator on the main separation graphical input screen brings up a detailed separator input screen where key process and separator design input specifications can be edited (see Figure 6.17). Below are a few key points regarding inputs on this screen:

• The Adiabatic option if checked flashes the inlet stream to the separator at inlet temperature and the separator operating pressure to achieve liquid/vapor separation. Turning off the option allows specification of a flash temperature for the separator and adds a heat exchanger to meet the specified temperature.

• The Separator Type provides options for horizontal separators, vertical separators, powered centrifuges and dewatering hydrocyclones. The powered centrifuge options are only available for stages three and lower.

• The Sizing Method selection determines how a separator will be sized based on required liquid volume. For each of the sizing methods, gas velocity is also checked and the larger of the diameters determined between the liquid and gas velocity sizing methods is used (see Figure 6.18).

• When the Water Separation option is specified, the percentage of free water that is carried over to the next separator can be specified using the Water Separation input. Note that in the separator process balance in the text output, all free water will be listed in the Water stream including the entrained water. The entrained water is then added to the feed stream for the next separator stage.

• A cross exchanger can be specified for a separator to exchange with a separated crude stream from another separator to provide supplemental heating of a feed stream to a separator. This takes advantages of heating being done downstream and reduces heating medium requirements. If a specific separator temperature is set for


the separator utilizing the cross exchanger and the heat available is not enough to meet the required duty, a second exchanger using heating medium will be allocated.

Figure 6.17: Separator Specifications

Figure 6.18: Separator Sizing Options Slug Flow Methods

When the Sizing Method is specified to “Emulsion Treater/Desalter”, the Emulsion Treater button becomes valid and can be clicked on to bring up detailed Emulsion Treater specifications as shown in Figure 6.19. Emulsion Treater options include single and two stage desalters, heater treaters and electrostatic treaters. Additionally, a pre-flash separator can be specified and allocated on top of the liquid full emulsion treater to minimize equipment footprint.


Figure 6.19: Emulsion Treater Specifications

Crude emulsion treatment is a part of the separation system. Three types of crude emulsion treatment vessels may be specified:

• Electrostatic Treater with or without heating of the crude: Electrostatic treatment of crude oil, along with heating, is another option for removing water from crude. Crude is heated to 130°F, or even 180°F, and subjected to a high voltage electrical field to aid in water droplet coagulation. An electrostatic emulsion treater will operate at about 15 to 30 psig. Figure 6.20 illustrates a typical electrostatic treater.


Figure 6.20: Flow Through Electrostatic Coalescer

• Heater Treater (no electrostatic elements) with firetube or external heat exchanger: An oil/water emulsion is heated to aid in breaking the emulsion. Sufficient settling time must be allowed for the phases to settle. Heater treaters are most commonly direct-fired units, but heat may be added indirectly through a heat exchanger or an internal tube bundle using heating medium for offshore installations. Heating to an appropriate temperature with oil-water emulsion breaking chemicals and allowing adequate settling time is a reliable method of removing water from oil.

• Desalter (one or two stage): Desalting is a third option for treating crude emulsions. Desalters use a longer residence time than treaters and can be designed with one or two stages. Without heat or electrostatic treatment, residence time is the only separating method used in a desalter.

When oil production facilities are specified, crude emulsion treatment/desalting equipment may be allocated as the last or next to the last stage of separation. Liquid produced from the separation may be routed to either crude export or condensate treatment. In the crude export system, crude booster pumps may be allocated before the crude metering and export facilities.

6.8 Crude Metering and Export

The Crude or condensate liquid metering is normally done before the liquid leaves the platform. The Crude Metering and Export system includes a crude cooler, crude surge tank, export pumps and meters. Below are a few key points regarding inputs on the Crude Metering and Export input screen shown in Figure 6.21:

• The crude cooler is allocated only if the inlet temperature exceeds the user-specified Maximum Export Temperature;

• Booster pump sizing and cost is allocated to the separation system if selected on this screen. OGM assumes that one operating pump plus a spare is allocated per last stage separator train;

• The Crude Export Rate defaults to the sum of the local reservoir fluid rates in kbpd divided by 24 hours except for an FPSO, where OGM assumes that the rate is an offloading rate rather than a production rate;

• The Pump Maximum Horsepower is used to place an upper limit on the pump horsepower and will automatically increase the number of pumps if the pump horsepower exceeds the Pump Maximum Horsepower;


Figure 6.21: Crude Metering and Export


7 Tutorial 2

STEP 1 - Bridge-Connected Jacket Complex Tutorial Description:

• Based on Tutorial 1. • Add bridge connected living quarters platform. • Add bridge connected gas compression platform. • Add bridge connected flare platform.

Configuring the simulation:

1. To connect platforms with bridges start by selecting the Flowsheet button on bottom right side of the Screening Study Definition [JACKET] window. The following windows appears:


2. Then select the Platform Functions button. It is in the 2nd column, top row. The Platform Function Assignment [JACKET01] window appears:


3. The primary platform is the “J” platform. It is the center square in the platform configuration on the left side of the screen. To indicate that the living quarters are on a separate platform, and thereby connected by a bridge, select either square A, B, C or D for the living quarters. Note: these are adjacent platforms to the J platform. “Living Quarters:” is the top item in the list of facilities/equipment. Use your cursor to move the dot from the J platform to either A, B, C or D. For this example, A has been selected.

4. To move the gas compression equipment to its own platform, select B, C or D for that equipment. E could also be selected but it would not be desirable to have the living quarters sandwiched between the gas compression and all the other processing equipment. “Gas Compression:” is the eighth item in the list of facilities/equipment. For this example, B has been selected.

5. The flare could potentially be located on C, D, E, G or F. For choices C, D, E and G, the Flare Platform Connection’s only choice is “BY BRIDGE”. For choice F, the flare could be connected BY SUBSEA PIPELINE. For this example, C was selected for the flare. See figure below.

6. Tutorial 2 is ready to be run, Ctrl-F5. The OGM Run Status Panel window should indicate that the simulation is completed.

7. As an example, it was compared a JACKET with (Tutorial 1) and without (Tutorial 2) the additions of bridges.

It was followed the steps taught at Tutorial 1 to generate a Report. At this item it

was selected the sequence Offshore Report Menus � Field and Total Facility Reports � Field Capital Cost Summary.


First, it was created the JACKET without Bridges (Tutorial 1):

In the sequence, the JACKET with Bridges (STEP 1 from Tutorial 2):


The differences between the both windows are marked in the Report. The JACKET from Tutorial 1 has only the indication of one facility (Platform J), while the JACKET of Step 1 from Tutorial 2 has three bridges allocated at the platform, increasing the number of facilities, as shown at the second report. These changes not only raise the quantity facilities, but also the subtotal cost of the case. Therefore, it is important to notice that every change made at the facility implicates in adjustments at the report. STEP 2 - Satellite Wellhead Platforms Tutorial Description:

• This tutorial demonstrates how OGM can be used to model satellite wellhead platforms and pipeline connections between platforms.

• Add two satellite platforms with jacket substructures. • Set the crude production rate to 20 kbpd. • Set the water depth to 200 ft. • Set the number of production wells to 10. • Remove separation, living quarters and drilling from the Satellite Wellhead

platforms.

• Add electrical cable connection from the central process platform to each satellite platform.

• Add a water injection connection to each satellite for 10 kbpd. • Remove water injection at the satellite wellhead platforms.

Configuring the simulation:

1. Starting with Tutorial 2 – step 1, select a JACKET from the tool bar (release the button on your mouse) then move your curser onto the “field”.


A small sketch of a jacket will appear. Once the cursor is in the desired position, left click to place the jacket in the field. Do this twice, once for each satellite platform. Hit the ESC button or right click to stop placing JACKETs on your field.

2. A Name of the facility window will appear.


For this example, the default names were used (JACKET02 and JACKET03).

3. Pull up the Screening Study Definition [JACKET02] windows to set the crude production rate (20 kbpd), water depth (200 ft) and number of production wells (10). The window will appear by double clicking on the jacket.


Above is the Screening Study Definition window for JACKET02 with the parameters entered. Complete this for Satellite Wellhead Platforms, JACKET02 and JACKET03.

4. The satellite wellhead platforms do not have gas/water separation equipment. To remove this, the Separation box must be unchecked. Complete this for both Satellite Wellhead Platforms.


There is often more than one way to accomplish a task in OGM. Steps 5 through 6 provide one method for removing the living quarters and drilling equipment.

5. To remove the living quarters, select the Flowsheet button from the Screening

Study Definition [JACKET03] window. That pulls up the Topsides Flowsheet [JACKET03] window. Select the Living Quarters button to view the Living Quarter [JACKET03] window. To remove the living quarters, uncheck the box marked Allocate Living Quarters. Refer to the screen shots below:


6. To remove the drilling facilities, select the Drilling Facility button from the

Topsides Flowsheet [JACKET03] window. This pulls up the Drilling [JACKET03] window.


To remove the drilling equipment from these satellite wellhead platforms, uncheck the Drilling Options box. Refer to the screen shots above.

7. Another method of removing the Living quarters and drilling equipment is to uncheck the Allocate Living Quarters: box and uncheck the Drilling Option box in the Screening Study Definition [JACKET03] window.

Resuming the first changes made at this Step, it is possible to conclude that the two jackets added are wellhead platforms that simply bring the reservoir fluid to the surface and send the fluid onto the central processing platform for separation, treatment, and export boosting. The wellheads thus will only include the wellheads & manifolds and any utilities required to support the functions on the platform. Thus gas compression is not required (done on the central processing facility), flare should exist, living quarters was assumed not to be allocated (i.e. wellhead platforms were assumed to be unmanned).


9. To add an electrical cable connection, select the Create a Pipeline button from

the tool bar. Move the cursor over the initial jacket (JACKET01), click, then move your cursor over one of the satellite platforms and click a second time. The window Pipeline Connection is now displayed.

Select Electric Power and push the Add >> button to move it from the Available window to the Current window. Another method of moving an item from the Available window to the Current window is to double click on the item. Close the Pipeline Connection window.


If at any time you want to change the pipeline connections, the Pipeline Connection window can be display by two methods. Double left click on the line or right click and then left click on the Modify . . . window.

10. To add water injection connection to each satellite, double left click on the black Electric Power line. The Pipeline Connection window will appear. Select the Water Injection item (Water Injection item must be selected in the Screening Study Definition [JACKET01] window) and push the Add >> button to move it from the Available window to the Current window. Once it is in the Current window, select it again and click on the Edit . . . button. Enlightening the item 10, water injection pumps are allocated at the central processing facility and pump the water via pipeline to the wellhead platforms for injection.

11. The Water Injection Pipeline Specifications [JACKET01-… window will appear.

Another method of pulling up Water Injection Pipeline Specifications [JACKET01-… window is to double click on an item in the current window. This action will cause that specific editing screen to appear for that item.


For the Simulation Option: select SIMULATED W/O PV CALC. (Note: PV stands for present value.) For the Export Quantity: enter 10 kbpd. Close the Water Injection Pipeline Specifications [JACKET01-… window then close the Pipeline Connection window. Complete these steps for both Satellite Wellhead Platforms. These steps will automatically remove the check from the Water Inj.: box in the Screening Study Definition [JACKET03] window.


12. These Satellite Wellhead Platforms must deliver well fluids to the central processing unit, JACKET01. To accomplish this, a crude pipeline must be added from JACKET02 to JACKET01 and from JACKET03 to JACKET01. This is done by using the Create a Pipeline button from the tool bar. Before we started at JACKET01 and moved to the other jackets. This time, start at the satellite platforms and move the cursor over the initial jacket (JACKET01). The window Pipeline Connection is now displayed. Double click on the Crude item in the Available window to move it to the Current window. This should be completed for each Satellite Platform.


13. Tutorial 2 – step 2 is now ready to be run. Since there is more than one jacket, the best method of running the entire field to select Run from the top menu bar or Ctrl F5. Again, because there are multiple jackets, a window appears allowing you to select the order that the simulation will be run.

14. For now, leave the facilities in the default order. Hit the Ok button. When the

simulation is run and converged, the OGM Run Status Panel window looks like:


15. Reports

Following the steps to generate reports showed at Tutorial 1, below it will be presented some examples concerning Tutorial 2.

The following screen is brought in Microsoft Access.

Opening the Offshore Report Menu window and selecting the Substructure Reports, two options can be chosen: Substructure Cost Summary and Substructure Technical Summary.


As an example, the Substructure Cost Summary will be selected as shown at the figure above. This time the “Output to” option will be “Screen (Preview)”, where the report is shown at the same MS Access window.

Analyzing each substructure available at Step 2 from Tutorial 2, the changes made during the sequence of the Tutorial can be observed at the windows below.


The most remarkable difference between the three Jackets at this report is in the section Import/Export Risers. The tutorial provided information asking the user to add Water Injection at the pipeline from JACKET01 to JACKET02 and JACKET03. For this reason, these changes are shown at the report as a riser which will import water to JACKET02 and JACKET03 and export from JACKET01. Another change also asked by the Tutorial refers to the crude oil import to JACKET01 from JACKET02 and JACKET03. The report shows it as a crude import riser in the section Import/Export Risers of JACKET01. Beside these changes, the total cost of the substructures is also an option of analysis. As it can be seen, the prices increase proportionally with risers quantities.


8 References

1. OGM Training Manual General Training

2. OGM Version 1.7.3 Release Notes

3. OGM Users Manual

4. OGM Quick Reference Guide

Módulo 3 - Apostila

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Transcript of Módulo 3 - Apostila