Christmas trees are used on both surface and subsea wells. It is common to identify the type of tree as either “subsea tree” or “surface tree”. Each of these classifications has a number of variations. Examples of subsea include conventional, dual bore, mono bore, TFL (through flow line), horizontal mud line, mud line vertical, side valve, and TBT (through-bore tree) trees. The primary function of a tree is to control the flow, usually oil or gas, out of the well.
Horizontal vertical christmas tree pptAmar Gaikwad
Brief Information about Christmas tree that is Sub-sea horizontal vs vertical x-mas tree. in this presentation include information that is types of x-mas tree,tree selection & last is which tree is most preferable for surface and subsurface applications.
The document discusses the steps involved in well completion, including:
- Cleaning out the wellbore by running a bit and scraper to remove cement and cuttings.
- Circulating the well from bottom to top with completion fluid to displace drilling mud.
- Measuring the clarity of the returning fluid using an NTU measurement to ensure it is below 25.
- The goal is to clean the wellbore before running the completion string.
The document provides information on various wellbore equipment manufactured by Parveen including:
- Measuring line stuffing boxes that seal around wirelines and incorporate a blow out plug for safety.
- Line wipers used to wipe wirelines when removed from wells.
- Grease injection control heads that inject grease to create a seal around braided lines.
- Lubricator risers that allow wirelines to be raised above wellhead valves.
- Blowout preventers available in manual or hydraulic models in various configurations to provide protection during wireline operations.
Subsea Field Development for an ideal Green field.Emeka Ngwobia
• The Daiyeriton Field is a green field development project. The subsea field layout with its drill centers has been illustrated in slide 2. New flowlines and pipelines will tie-in to the existing Daiyeriton floating production, storage, and offloading (FPSO) vessel. The new system will enable the transportation of production and injection fluids to and from the Daiyeriton field facilities from five new drill centers: DC-SW, DC-NW, DC-SE, DC-NE and DC-E. DC-SE, DC-SW, DC-NE and DC-E are dedicated production drill centers while DC-NW is a dedicated WI drill center. Gas lift will be provided at the riser base of a new 12-inch production flowline.
•The water depth at the proposed development sites range from 800 m to 1000 m.
The document discusses wellheads and their components. It describes how wellheads are made up of multiple pieces including the casing head, casing hangers, spools, tubing hangers, master valves, and flow trees. It provides pictures and descriptions of these individual components and how they assemble to form the full wellhead. It also discusses design considerations, installation procedures, sealing methods, and testing of wellhead equipment.
The document discusses mudline suspension systems used for offshore drilling. It describes how the system allows the weight of the well to be transferred to the seabed and provides a disconnect capability. Key components include butt-weld subs, shoulder hangers, split-ring hangers, mudline hangers, and temporary abandonment caps. The system also allows the well to be temporarily abandoned when drilling is finished and reconnected later for completion.
This document provides an overview of offshore oil and gas facilities, including wellhead platforms. It describes the typical components and functions of wellhead platforms, such as slots for drilling wells, wellhead control equipment, production manifolds, test separators, and utilities. The document outlines the process systems of a typical wellhead platform and summarizes the purpose and design of components like pig launchers, vents, flares, utility gas systems, drain systems, and chemical injection. Diagrams illustrate the installation and components of wellhead platforms such as the jacket, decks, cranes, pipelines, and safety equipment.
Wellhead function, rating and selectionElsayed Amer
The document discusses various components of wellhead and Christmas tree equipment used in oil and gas wells. It describes the purpose and components of the wellhead assembly including the casing head, casing hangers, tubing head, and tubing hanger. It also discusses the tubing head adapter and its role in connecting the tubing head to the Christmas tree. Seals, valves, and other surface equipment used to control flow from the well are also covered.
Horizontal vertical christmas tree pptAmar Gaikwad
Brief Information about Christmas tree that is Sub-sea horizontal vs vertical x-mas tree. in this presentation include information that is types of x-mas tree,tree selection & last is which tree is most preferable for surface and subsurface applications.
The document discusses the steps involved in well completion, including:
- Cleaning out the wellbore by running a bit and scraper to remove cement and cuttings.
- Circulating the well from bottom to top with completion fluid to displace drilling mud.
- Measuring the clarity of the returning fluid using an NTU measurement to ensure it is below 25.
- The goal is to clean the wellbore before running the completion string.
The document provides information on various wellbore equipment manufactured by Parveen including:
- Measuring line stuffing boxes that seal around wirelines and incorporate a blow out plug for safety.
- Line wipers used to wipe wirelines when removed from wells.
- Grease injection control heads that inject grease to create a seal around braided lines.
- Lubricator risers that allow wirelines to be raised above wellhead valves.
- Blowout preventers available in manual or hydraulic models in various configurations to provide protection during wireline operations.
Subsea Field Development for an ideal Green field.Emeka Ngwobia
• The Daiyeriton Field is a green field development project. The subsea field layout with its drill centers has been illustrated in slide 2. New flowlines and pipelines will tie-in to the existing Daiyeriton floating production, storage, and offloading (FPSO) vessel. The new system will enable the transportation of production and injection fluids to and from the Daiyeriton field facilities from five new drill centers: DC-SW, DC-NW, DC-SE, DC-NE and DC-E. DC-SE, DC-SW, DC-NE and DC-E are dedicated production drill centers while DC-NW is a dedicated WI drill center. Gas lift will be provided at the riser base of a new 12-inch production flowline.
•The water depth at the proposed development sites range from 800 m to 1000 m.
The document discusses wellheads and their components. It describes how wellheads are made up of multiple pieces including the casing head, casing hangers, spools, tubing hangers, master valves, and flow trees. It provides pictures and descriptions of these individual components and how they assemble to form the full wellhead. It also discusses design considerations, installation procedures, sealing methods, and testing of wellhead equipment.
The document discusses mudline suspension systems used for offshore drilling. It describes how the system allows the weight of the well to be transferred to the seabed and provides a disconnect capability. Key components include butt-weld subs, shoulder hangers, split-ring hangers, mudline hangers, and temporary abandonment caps. The system also allows the well to be temporarily abandoned when drilling is finished and reconnected later for completion.
This document provides an overview of offshore oil and gas facilities, including wellhead platforms. It describes the typical components and functions of wellhead platforms, such as slots for drilling wells, wellhead control equipment, production manifolds, test separators, and utilities. The document outlines the process systems of a typical wellhead platform and summarizes the purpose and design of components like pig launchers, vents, flares, utility gas systems, drain systems, and chemical injection. Diagrams illustrate the installation and components of wellhead platforms such as the jacket, decks, cranes, pipelines, and safety equipment.
Wellhead function, rating and selectionElsayed Amer
The document discusses various components of wellhead and Christmas tree equipment used in oil and gas wells. It describes the purpose and components of the wellhead assembly including the casing head, casing hangers, tubing head, and tubing hanger. It also discusses the tubing head adapter and its role in connecting the tubing head to the Christmas tree. Seals, valves, and other surface equipment used to control flow from the well are also covered.
This document provides a running procedure for installing a Transformer R7 wellhead system. It includes 11 stages of the installation process with detailed steps for each stage. The stages include site preparation, installing the casing head, installing additional components like the drilling adapter, testing the BOP stack, running casing, installing the packoff and casing head cap, and installing the tubing spool. Dimensional drawings and a bill of materials are provided.
This document contains slides from a presentation on well completions fundamentals. It discusses various aspects of well completions such as bottom hole completion techniques including perforated, open hole and liner completions. It also discusses perforations, the production string including tubing, packers and Christmas trees. The upper hole completion involves installing the production tubing, packers and the Christmas tree. Multiple completion configurations allow accessing multiple pay zones including single string and parallel string options. Horizontal and multilateral well completions also require specialized techniques and equipment.
This document provides information about well completion processes and equipment. It discusses steps like well clean up, mud displacement, perforating, and installing downhole equipment like packers, landing nipples, and side pocket mandrels. The document also outlines considerations for completion design based on factors like the wellbore, reservoir properties, and production method. Well completion aims to enable production from the reservoir to the surface.
This document was produced as part of my final year project of training to obtain a petroleum engineering diploma.
The aim of this project is to make a comparative study between continuous and intermittent gas lift systems based on real data from an oil well in Algeria, and to choose the system best suited to increase the production of the well.
This study was carried out by a manual design using the method of “fixed pressure drop” for the continuous gas lift system and “fallback gradient” method for intermittent gas lift system.
We were able to determine at the end of this study that the system best suited to the current conditions of our well would be the intermittent gas lift system and we also proposed that it should be combine with the "plunger lift " system in order to increase the efficiency of the intermittent gas lift system by eliminating problems linked to the phenomenon of" fallback " thus increase the production of our wells.
This document provides details on the components of an oil drilling rig, including mud tanks, shale shakers, and other equipment. It describes the purpose and function of each component. The mud tank stores drilling fluid and other solids control equipment are mounted on top, including shale shakers. Shale shakers are the first stage in removing cuttings from the drilling fluid and consist of parts like the hopper, feeder, screen basket, and vibrator. The document also discusses screen selection and causes of premature screen failure.
Well completion equipment 2. landing nipplesElsayed Amer
A landing nipple is a short length of pipe with a cut profile on the inside used to allow a lock mandrel to locate and lock into for various purposes like plugging the tubing. There are selective and no-go types, with no-go containing a restriction preventing passage. Landing nipples are used for removing surface equipment, pressure testing, setting packers, installing downhole tools, and landing pressure recorders. They consist of a lock mandrel, equalizing sub, and flow control device. Major manufacturers include Baker, CAMCO, Halliburton, and Weatherford.
This document discusses packers, which are used in oil and gas well completions to isolate sections of the wellbore. It describes the main components and functioning of packers, including cones that force slips into the casing and compressed sealing elements. The document outlines different types of packers classified by function, installation method, and duration. Removal techniques for permanent and retrievable packers are also summarized. Safety joints are explained as a means to release packers in emergency situations by shearing pins and allowing retrieval of completion equipment above. In conclusion, the document emphasizes that packers are critical for well integrity and outlines key aspects of their design and application.
A drill stem test (DST) is used to test characteristics of a newly drilled well while the drilling rig is still on site. It can provide estimates of permeability, reservoir pressure, fluid types, wellbore damage, barriers and fluid contacts. There are three main methods to analyze DST data: Horner's plot method, type curve matching method, and computer matching. Type curve matching involves matching pressure change over time data from the DST to standard type curves to determine properties like permeability and skin factor. Gringarten type curves are commonly used and account for variations in pressure over time based on reservoir-well configurations.
This document provides information about well completion processes and equipment. It discusses steps like well clean up, mud displacement, perforating, and describes completion equipment such as packers, landing nipples, perforated joints, and side pocket mandrels. The document is a reference for engineers, providing technical details on well completion design, operations, and component functions.
This document discusses well completion testing and work over. It defines well completion as preparing a well for production by installing necessary equipment to allow safe and controlled hydrocarbon flow to the surface. The document describes open hole and cased hole well completions, including their advantages and disadvantages. It also discusses different types of well completions like liner completions, perforated liner completions, and production casing completions. Finally, it briefly covers different flow configurations like casing flow, tubing and annulus flow, and tubing flow.
This document contains information about Eng. El Sayed Amer, a petroleum engineer who has worked for Weatherford Drilling International and as a process and production engineer for SUCO and RWE DEA. It discusses production packers, which are subsurface tools used to provide a seal between the tubing and casing. Production packers can protect the casing from corrosion, provide better well control, isolate pay zones, and prevent fluid movement between zones. They are classified as either permanent or retrievable based on whether they can be removed from the well without destruction. The document focuses on the characteristics and advantages and disadvantages of permanent and retrievable production packers.
Scsssv surface control subsurface safety valveElsayed Amer
The document discusses subsurface safety valves (SSSVs), which are installed downhole to allow emergency shutdown and prevent uncontrolled hydrocarbon release from a well. SSSVs were not in place during the Piper Alpha platform disaster, exacerbating the accident. SSSVs come in two types: wireline-retrievable, which can be easily installed/removed via wireline but restrict flow; and tubing-retrievable, which are integral to the tubing and avoid flow restrictions but require pulling tubing for repair. Recommended minimum setting depths are 50m below the deepest pile for offshore and 100m below ground level for onshore. [/SUMMARY]
This document discusses side sliding doors and side pocket mandrels. Side sliding doors, also known as sliding sleeves, are used to provide controlled communication between the tubing and casing annulus. They can enable well killing by fluid circulation. Side pocket mandrels are used to install gas lift valves, dummies, or chemicals at intervals along the tubing string. Gas is injected into the tubing/casing annulus and acts on the gas lift valves to lift liquid up the tubing.
This document provides an introduction to hydraulic workover and snubbing solutions. It discusses the history of hydraulic workover which has been used since the 1920s. It defines snubbing as running and pulling tubulars with surface pressure present. Engineering calculations are required for hydraulic workover applications to determine the required snubbing force and hydraulic pressure based on factors like well pressure, tubular size, and length. Proper procedures must be followed when running tubulars between blowout preventer rams.
This document provides information about gas lift optimization. It discusses the need for gas lift when wells are not producing through natural flow. Gas lift involves injecting natural gas into the well to lift fluids to the surface. The document outlines the basic principles of gas lift and gas lift systems. It describes how gas lift valves work and the process of unloading a well using multiple unloading valves. The goal of optimization is to find the optimal injection point and amount of gas injected to maximize oil production rates. Charts are provided showing well performance curves with injection rate versus oil rate.
The document discusses several challenges related to plugging and abandoning oil wells in a more efficient and cost-effective manner. It proposes questions around developing new tools and methods for removing casing strings more quickly when they are stuck, finding alternative materials to cement for creating annular barriers, and investigating options for permanently sealing wells without removing tubing and casing.
After drilling is completed, wells undergo completion procedures to prepare them for production. This involves setting production casing and cementing it through the target zone. Tubing is run inside the casing with a packer to isolate the production zone. A Christmas tree is installed to control flow. Completion types include open hole, liners, and perforated casing. Perforating creates holes through casing into the formation. Some formations require stimulation like acidizing to improve permeability or fracturing to create conductive fractures held open by proppant. This increases flow into the wellbore.
Valves operation and functions complete guideElsayed Amer
Eng. El Sayed Amer is a senior process and production engineer at Suez Oil Co. He has worked as a drilling and completion engineer for Weatherford drilling international. He is also an instructor for oil and gas courses. He is a member of several professional engineering organizations and certified in process modeling and reservoir simulation software. He has expertise in valves technology and operations in the process industry.
The document discusses oil and gas production and surface facilities. It begins with an introduction to the upstream, midstream, and downstream sectors of the oil and gas industry. It then covers well types at the production phase, including oil, gas, and water injection wells. It describes key wellhead components like the casing head, tubing head, Christmas tree, and safety control subsurface safety valve. It provides details on various artificial lift methods and their relative advantages and disadvantages. It concludes with descriptions of hook-up and flow line components used to transport oil and gas from wells.
This document provides a running procedure for installing a Transformer R7 wellhead system. It includes 11 stages of the installation process with detailed steps for each stage. The stages include site preparation, installing the casing head, installing additional components like the drilling adapter, testing the BOP stack, running casing, installing the packoff and casing head cap, and installing the tubing spool. Dimensional drawings and a bill of materials are provided.
This document contains slides from a presentation on well completions fundamentals. It discusses various aspects of well completions such as bottom hole completion techniques including perforated, open hole and liner completions. It also discusses perforations, the production string including tubing, packers and Christmas trees. The upper hole completion involves installing the production tubing, packers and the Christmas tree. Multiple completion configurations allow accessing multiple pay zones including single string and parallel string options. Horizontal and multilateral well completions also require specialized techniques and equipment.
This document provides information about well completion processes and equipment. It discusses steps like well clean up, mud displacement, perforating, and installing downhole equipment like packers, landing nipples, and side pocket mandrels. The document also outlines considerations for completion design based on factors like the wellbore, reservoir properties, and production method. Well completion aims to enable production from the reservoir to the surface.
This document was produced as part of my final year project of training to obtain a petroleum engineering diploma.
The aim of this project is to make a comparative study between continuous and intermittent gas lift systems based on real data from an oil well in Algeria, and to choose the system best suited to increase the production of the well.
This study was carried out by a manual design using the method of “fixed pressure drop” for the continuous gas lift system and “fallback gradient” method for intermittent gas lift system.
We were able to determine at the end of this study that the system best suited to the current conditions of our well would be the intermittent gas lift system and we also proposed that it should be combine with the "plunger lift " system in order to increase the efficiency of the intermittent gas lift system by eliminating problems linked to the phenomenon of" fallback " thus increase the production of our wells.
This document provides details on the components of an oil drilling rig, including mud tanks, shale shakers, and other equipment. It describes the purpose and function of each component. The mud tank stores drilling fluid and other solids control equipment are mounted on top, including shale shakers. Shale shakers are the first stage in removing cuttings from the drilling fluid and consist of parts like the hopper, feeder, screen basket, and vibrator. The document also discusses screen selection and causes of premature screen failure.
Well completion equipment 2. landing nipplesElsayed Amer
A landing nipple is a short length of pipe with a cut profile on the inside used to allow a lock mandrel to locate and lock into for various purposes like plugging the tubing. There are selective and no-go types, with no-go containing a restriction preventing passage. Landing nipples are used for removing surface equipment, pressure testing, setting packers, installing downhole tools, and landing pressure recorders. They consist of a lock mandrel, equalizing sub, and flow control device. Major manufacturers include Baker, CAMCO, Halliburton, and Weatherford.
This document discusses packers, which are used in oil and gas well completions to isolate sections of the wellbore. It describes the main components and functioning of packers, including cones that force slips into the casing and compressed sealing elements. The document outlines different types of packers classified by function, installation method, and duration. Removal techniques for permanent and retrievable packers are also summarized. Safety joints are explained as a means to release packers in emergency situations by shearing pins and allowing retrieval of completion equipment above. In conclusion, the document emphasizes that packers are critical for well integrity and outlines key aspects of their design and application.
A drill stem test (DST) is used to test characteristics of a newly drilled well while the drilling rig is still on site. It can provide estimates of permeability, reservoir pressure, fluid types, wellbore damage, barriers and fluid contacts. There are three main methods to analyze DST data: Horner's plot method, type curve matching method, and computer matching. Type curve matching involves matching pressure change over time data from the DST to standard type curves to determine properties like permeability and skin factor. Gringarten type curves are commonly used and account for variations in pressure over time based on reservoir-well configurations.
This document provides information about well completion processes and equipment. It discusses steps like well clean up, mud displacement, perforating, and describes completion equipment such as packers, landing nipples, perforated joints, and side pocket mandrels. The document is a reference for engineers, providing technical details on well completion design, operations, and component functions.
This document discusses well completion testing and work over. It defines well completion as preparing a well for production by installing necessary equipment to allow safe and controlled hydrocarbon flow to the surface. The document describes open hole and cased hole well completions, including their advantages and disadvantages. It also discusses different types of well completions like liner completions, perforated liner completions, and production casing completions. Finally, it briefly covers different flow configurations like casing flow, tubing and annulus flow, and tubing flow.
This document contains information about Eng. El Sayed Amer, a petroleum engineer who has worked for Weatherford Drilling International and as a process and production engineer for SUCO and RWE DEA. It discusses production packers, which are subsurface tools used to provide a seal between the tubing and casing. Production packers can protect the casing from corrosion, provide better well control, isolate pay zones, and prevent fluid movement between zones. They are classified as either permanent or retrievable based on whether they can be removed from the well without destruction. The document focuses on the characteristics and advantages and disadvantages of permanent and retrievable production packers.
Scsssv surface control subsurface safety valveElsayed Amer
The document discusses subsurface safety valves (SSSVs), which are installed downhole to allow emergency shutdown and prevent uncontrolled hydrocarbon release from a well. SSSVs were not in place during the Piper Alpha platform disaster, exacerbating the accident. SSSVs come in two types: wireline-retrievable, which can be easily installed/removed via wireline but restrict flow; and tubing-retrievable, which are integral to the tubing and avoid flow restrictions but require pulling tubing for repair. Recommended minimum setting depths are 50m below the deepest pile for offshore and 100m below ground level for onshore. [/SUMMARY]
This document discusses side sliding doors and side pocket mandrels. Side sliding doors, also known as sliding sleeves, are used to provide controlled communication between the tubing and casing annulus. They can enable well killing by fluid circulation. Side pocket mandrels are used to install gas lift valves, dummies, or chemicals at intervals along the tubing string. Gas is injected into the tubing/casing annulus and acts on the gas lift valves to lift liquid up the tubing.
This document provides an introduction to hydraulic workover and snubbing solutions. It discusses the history of hydraulic workover which has been used since the 1920s. It defines snubbing as running and pulling tubulars with surface pressure present. Engineering calculations are required for hydraulic workover applications to determine the required snubbing force and hydraulic pressure based on factors like well pressure, tubular size, and length. Proper procedures must be followed when running tubulars between blowout preventer rams.
This document provides information about gas lift optimization. It discusses the need for gas lift when wells are not producing through natural flow. Gas lift involves injecting natural gas into the well to lift fluids to the surface. The document outlines the basic principles of gas lift and gas lift systems. It describes how gas lift valves work and the process of unloading a well using multiple unloading valves. The goal of optimization is to find the optimal injection point and amount of gas injected to maximize oil production rates. Charts are provided showing well performance curves with injection rate versus oil rate.
The document discusses several challenges related to plugging and abandoning oil wells in a more efficient and cost-effective manner. It proposes questions around developing new tools and methods for removing casing strings more quickly when they are stuck, finding alternative materials to cement for creating annular barriers, and investigating options for permanently sealing wells without removing tubing and casing.
After drilling is completed, wells undergo completion procedures to prepare them for production. This involves setting production casing and cementing it through the target zone. Tubing is run inside the casing with a packer to isolate the production zone. A Christmas tree is installed to control flow. Completion types include open hole, liners, and perforated casing. Perforating creates holes through casing into the formation. Some formations require stimulation like acidizing to improve permeability or fracturing to create conductive fractures held open by proppant. This increases flow into the wellbore.
Valves operation and functions complete guideElsayed Amer
Eng. El Sayed Amer is a senior process and production engineer at Suez Oil Co. He has worked as a drilling and completion engineer for Weatherford drilling international. He is also an instructor for oil and gas courses. He is a member of several professional engineering organizations and certified in process modeling and reservoir simulation software. He has expertise in valves technology and operations in the process industry.
The document discusses oil and gas production and surface facilities. It begins with an introduction to the upstream, midstream, and downstream sectors of the oil and gas industry. It then covers well types at the production phase, including oil, gas, and water injection wells. It describes key wellhead components like the casing head, tubing head, Christmas tree, and safety control subsurface safety valve. It provides details on various artificial lift methods and their relative advantages and disadvantages. It concludes with descriptions of hook-up and flow line components used to transport oil and gas from wells.
1. Well completion is the process of preparing a well for production after drilling and installing permanent casing. This involves preparing the wellbore, running production tubing and downhole tools, and potentially perforating and stimulating the well.
2. Completion equipment includes components like the wellhead, Christmas tree, tubing hanger, production tubing, safety valves, and downhole pumps and gauges. These components allow for controlling flow from the reservoir, protecting the well, and enabling intervention operations.
3. Well completions are designed based on factors like the type of well, number of production zones, and choosing appropriate inflow and outflow systems like open hole completions, gravel packs, or tubingless complet
Valves are mechanical devices that control the flow of liquids and gases in piping systems. They direct, start, stop, mix or regulate flow, pressure, or temperature. Common valve types include gate, globe, check, butterfly, ball, plug, and diaphragm valves. Valves are classified according to their function (on-off, nonreturn, throttling), application (general service, special service, severe service), and motion (linear or rotary). Control valves are throttling valves that are part of a control loop and are used as the final control element to regulate processes.
Valves in Pipelines-December 20150Finalgobindkhiani
This document summarizes the basics of pipeline construction and operation. It discusses the three categories of pipelines (gathering, transportation, distribution), pipeline materials and construction process involving 29 key steps. It also describes how oil and gas are transported through pipelines using pump stations and compressors. Intelligent pigs are used to inspect pipelines for anomalies. Various valves like manual valves, automated valves and ESD valves are installed to control pipeline flow and isolate sections for maintenance. Block valves are also installed every few miles for ease of maintenance access.
The document summarizes Wilson Mohr's wellhead control panel capabilities. The panel provides hydraulic power to well shutdown valves and includes manual and automated valves and gauges for local and remote operation. It controls the normal sequencing of opening and closing valves. An emergency shutdown switch is included. The panel integrates a hydraulic power unit, accumulator rack, and programmable logic controller-based control system to monitor processes, valves, and pumps and ensure proper sequencing for normal operation and emergency shutdown conditions.
This document provides specifications, instructions, and parts information for the HCK5D gas-powered suction stop valve. The HCK5D is a heavy-duty, flanged valve designed to control refrigerant flow in large commercial and industrial refrigeration systems during defrost. It remains normally open via a spring and closes when high pressure gas is introduced through a single pilot solenoid valve. When power is lost, it will not fully open until pressure across the valve is equalized to prevent shocks. Replacement parts are made of durable materials like ductile iron and installation requires only a single pilot line for operation.
The document describes several key components of a Christmas tree used in oil and gas production:
- Master valves control all flow from the wellbore, with most trees having two for redundancy. The upper valve is used routinely and the lower provides backup.
- Pressure gauges monitor well pressure, now often using electronic gauges to transmit data for remote monitoring.
- Wing valves control or isolate production flow to surface facilities, with some trees having two - one main and one backup. Others use one for production and another as a kill valve.
- A swab valve at the top provides access for well intervention tools like wireline.
- Chokes control production rates by restricting flow through interchangeable or
This document discusses various appurtenances used in water supply systems. It describes valves such as sluice valves, check valves, air relief valves, drain valves, zero velocity valves, scour valves, ball valves, and fire hydrants. It also discusses other appurtenances like water meters, storage tanks, bib cocks, and stop cocks. The purpose of these appurtenances is to control water flow, prevent leakage, change flow direction, and regulate pressure. Proper selection and installation of appurtenances is important for efficient water distribution.
Hydraulic Ram Made from Standard Plumbing Parts - University of GeorgiaFatin62c
This document provides instructions for assembling a hydraulic ram pump from standard plumbing parts. The assembly uses a swing check valve, spring loaded check valve, ball valves, unions, gauges and PVC or metal pipes. An inner tube is used as an air bladder in the pressure tank. The ram can be adjusted by changing the angle of the swing check valve or length of the drive pipe. Proper installation and startup is required to displace trapped air in the system.
A Control Valve is the most commonly used
final control element used to regulate fluid flow in
a process. In a process, normally it is the only
controllable element residing in the loop.
Ø This is a device used to modulate flow of
process fluid in pipe lines by creating a variable
area in the flow path.
Ø The flow path is varied with respect to the
control signal received from the controller
towards the required flow modulation.
The document provides definitions and descriptions of key components and concepts related to control valves. It discusses:
- What a control valve is and its main components like the valve body, trim, actuator, and accessories.
- Definitions of terms like bonnet, seat, cage, port, packing, and their functions.
- The inherent flow characteristics of control valves like linear, equal percentage, and quick opening.
- Additional concepts covered include vena contracta, cavitation, flashing, and noise in control valves. Diagrams are provided to illustrate cage shapes, plug shapes, and characterized cages for globe-style valves.
This document discusses various appurtenances used in water supply systems. It describes valves such as sluice valves, check valves, air relief valves, drain valves, zero velocity valves, scour valves, ball valves, and fire hydrants. It also discusses other appurtenances like water meters, storage tanks, bib cocks, and stop cocks. The purpose of these appurtenances is to control water flow, prevent leakage, change flow direction, and regulate pressure. Proper selection and installation of appurtenances is important for efficient water distribution.
This document provides an overview of best practices for installing and maintaining water distribution systems, including water mains, service lines, valves, hydrants, and other components. Key points covered include recommended pipe materials and sizes, minimum burial depths, separation from sewers, procedures for wet and dry taps, and installation details for valves, hydrants, and service connections. Operational considerations are also discussed, such as flushing, valve operation, and hydrant usage. Reference materials including AWWA standards are listed for additional guidance.
This document discusses various water supply appurtenances including valves, meters, hydrants and pipes. It notes that valves are used to control water flow, regulate pressure, and prevent backflow. Common valve types include sluice valves, check valves, air relief valves, drain valves, and ball valves. Water meters measure water usage to determine billing. Other appurtenances include fire hydrants, storage tanks, bib cocks, and stop cocks which control water distribution and access. The document provides details on the purpose and function of several key water supply system components.
A solenoid valve is an electromechanically operated valve that is controlled by an electric current passing through a solenoid. When current is applied, the solenoid generates a magnetic field that either opens or closes the valve. Solenoid valves are commonly used to control fluid systems and have applications in plumbing, industrial machinery, pneumatic tools, and more due to their fast, reliable switching capabilities.
Want to know more about ensuring safety and long-lasting performance on industrial valves? Fevisa, a leading valve manufacturer had a complete guide on what you are searching for.
The document provides guidance on selecting solenoid valves, noting that it is important to identify parameters like capacity, pressure conditions, media conditions, and discusses choosing valves suitable for open systems with defined pressure or closed circuit systems with undefined pressure, and covers direct-operated and servo-operated valve options.
There are four basic types of flow control elements employed in valve design:
1. Move a disc, or plug into or against an orifice.
2. Slide a flat, cylindrical, or spherical surface across an orifice.
3. Rotate a disc or ellipse about a shaft extending across the diameter of an orifice.
4. Move a flexible material into the flow passage.
Gate valves use the second type of flow control by sliding a flat disk across an orifice to start and stop flow but not regulate it. Common valve parts include the body, bonnet, trim (disk, seat, stem), actuator, and packing. The type of valve chosen
Similar to Report on horizontal vertical christmas tree (20)
Strategies for Effective Upskilling is a presentation by Chinwendu Peace in a Your Skill Boost Masterclass organisation by the Excellence Foundation for South Sudan on 08th and 09th June 2024 from 1 PM to 3 PM on each day.
A workshop hosted by the South African Journal of Science aimed at postgraduate students and early career researchers with little or no experience in writing and publishing journal articles.
Macroeconomics- Movie Location
This will be used as part of your Personal Professional Portfolio once graded.
Objective:
Prepare a presentation or a paper using research, basic comparative analysis, data organization and application of economic information. You will make an informed assessment of an economic climate outside of the United States to accomplish an entertainment industry objective.
How to Fix the Import Error in the Odoo 17Celine George
An import error occurs when a program fails to import a module or library, disrupting its execution. In languages like Python, this issue arises when the specified module cannot be found or accessed, hindering the program's functionality. Resolving import errors is crucial for maintaining smooth software operation and uninterrupted development processes.
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How to Build a Module in Odoo 17 Using the Scaffold MethodCeline George
Odoo provides an option for creating a module by using a single line command. By using this command the user can make a whole structure of a module. It is very easy for a beginner to make a module. There is no need to make each file manually. This slide will show how to create a module using the scaffold method.
A review of the growth of the Israel Genealogy Research Association Database Collection for the last 12 months. Our collection is now passed the 3 million mark and still growing. See which archives have contributed the most. See the different types of records we have, and which years have had records added. You can also see what we have for the future.
This presentation was provided by Steph Pollock of The American Psychological Association’s Journals Program, and Damita Snow, of The American Society of Civil Engineers (ASCE), for the initial session of NISO's 2024 Training Series "DEIA in the Scholarly Landscape." Session One: 'Setting Expectations: a DEIA Primer,' was held June 6, 2024.
Pollock and Snow "DEIA in the Scholarly Landscape, Session One: Setting Expec...
Report on horizontal vertical christmas tree
1. T120026423 AMAR MADUKAR GAIKWAD Page 1
Abstract
Christmas tree in oil and gas sector is not the same with the real christmas tree we use every
end and beginning of a new year. The name was given due to its resemblance and structure in
the decorative nature of a real christmas tree. Thousands of subsea Christmas trees have been
installed since the first subsea Christmas was installed in the Gulf of Mexico in 1961. Since
then, the Christmas are an essential part of the subsea fields. Christmas trees are used on both
surface and subsea wells. It is common to identify the type of tree as either “subsea tree” or
“surface tree”. Each of these classifications has a number of variations. Examples of subsea
include conventional, dual bore, mono bore, TFL (through flow line), horizontal mud line, mud
line vertical, side valve, and TBT (through-bore tree) trees. The primary function of a tree is to
control the flow, usually oil or gas, out of the well. A tree may also be used to control the
injection of gas or water into a non-producing well in order to enhance production rates of oil
from other wells. Tree complexity and functionality has increased over the last few decades.
Subsea Christmas tree is the core equipment in offshore oil & gas production system.
Installed on subsea wellhead, the tree is used to connect and support tubing string, seal off
casing pipes and casing tubing annulus, isolate borehole fluids from external sea water, control
wellhead production pressure, and adjust borehole flow rates. When the well and facilities are
ready to produce and receive oil or gas, tree valves are opened and the formation fluids are
allowed to go through a flow line. Flow lines on subsea wells usually lead to a fixed or floating
production platform or to a storage ship , known as a floating storage offloading vessel (FSO),
or floating processing unit (FPU). A tree often provides numerous additional functions
including chemical injection points, well intervention means, pressure relief means, monitoring
points such as pressure, temperature, corrosion, erosion, sand detection, flow rate, flow
composition, valve and choke position feedback, and connection points for devices such as
down hole pressure and temperature transducers.
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CHAPTER 1
Introduction
In petroleum and natural gas extraction, a Christmas tree is an assembly of valves, spools, and
fittings used for an oil well, gas well, water injection well, water disposal well, gas injection
well, condensate well and other types of wells. It was named for its crude resemblance to a
decorated tree. The purpose of a production Christmas Tree is to control the flow of
hydrocarbons from its respective well via various control valves and choke, to receiving unit.
This can be a fixed or floating vessel or produced via pipeline to shore. The purpose of an
injection Christmas Tree is to control the flow of water or gas into its respective well via
various control valves and choke, from a process installation off- or on-shore.
Christmas tree are installed on both surface and subsea wells on the surface at the top of the
casing hanger to control the flow of fluid/gas out of the well. As the well production flows up
the tubing, its enters the Christmas tree. The equipment at the top of the producing wellhead is
called a ‘‘Christmas tree’’ and it is used to control flow. The ‘‘Christmas tree’’ is installed
above the tubing head. An ‘‘adaptor’’ is a piece of equipment used to join the two. The
‘‘Christmas tree’’ may have one flow outlet (a tee) or two flow outlets (a cross). The master
valve is installed below the tee or cross. To replace a master valve, the tubing must be plugged.
Subsea and surface trees have a large variety of valve configurations and combinations of
manual and pneumatic actuated valves. Subsea trees contain many additional valves and
accessories compared to Surface trees. Typically a subsea tree would have a choke (permits
control of flow), a flowline connection interface (hub, flange or other connection), subsea
control interface (direct hydraulic, electro hydraulic, or electric) and sensors for gathering data
such as pressure, temperature, sand flow, erosion, multi-Phase flow, single phase flow such as
water or gas.
A basic surface tree consists of two or three manual valves (usually gate valves because of their
flow characteristics) A typical sophisticated surface tree will have at least four or five valves,
normally arranged in a crucifix type pattern.
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CHAPTER 2
Christmas Tree System
2.1 Main Components:
Typical main components in an Christmas Tree assembly required to perform its functions
include:
• Tubing Hanger
• Tubing Head Spool
• Tree piping
• Flowline connector
• Wellhead connector
• Valves and fittings
• Choke
• Tree cap
• Tree frame
A typical Christmas tree composed of a master gate valve, a pressure gauge, a wing valve, a
swab valve and a choke is shown here. The Christmas tree may also have a number of check
valves. The functions of these devices are explained in the following paragraphs.
At the bottom we find the casing head and casing hangers. The casing will be screwed, bolted
or welded to the hanger. Several valves and plugs will normally be fitted to give access to the
casing. This will permit the casing to be opened, closed, bled down, and in some cases, allow
the flowing well to be produced through the casing as well as the tubing. The valve can be used
to determine leaks in casing, tubing or the packer, and will also be used for lift gas injection
into the casing.
Figure 2.1. Schematic of Wellhead & Christmas Tree
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The components are described following:
A) The Tubing Hanger: (also called a donut) is used to position the tubing correctly in the
well. The Tubing Hanger (TH) system is designed to suspend and seal the downhole tubing.
The Tubing hanger shall be possible to be installed through a BOP stack and locked into the
internal landing profile of either the casing hanger in the wellhead, the tree bore or in the THS.
The tubing hanger shall provide the means of communication between the Christmas Tree and
the downhole hydraulic and electric functionalities. Wet mate couplers/connectors are located
on the top and bottom of the hanger and engage with the Christmas Tree and the downhole
equipment.
Tubing Hanger Configurations:
The tubing hanger can be segmented into two types of configurations: monobore and dualbore
Tubing hanger. The monobore tubing hanger only have a production bore, with the annulus
routed around the bore. The dual bore tubing hanger is designed with a main production bore
and an annulus bore. The tubing hanger assembly consists of the hanger body, lockdown
sleeves, locking dogs, gallery seals, pump down seal, electrical penetrator receptacle, dry and
wet mate connector and pup joint. These components ensure that the tubing hanger is locked
down and communicate with the systems around.
Figure 2.2 Monobore And Dual Bore Tubing Hanger
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B) Wellhead Connectors: The wellhead connectors are the mechanism to lock and seal a
Christmas tree to the wellhead, Christmas tree to the THS and the THS to the Well head.
The connectors may be both mechanical and pressure connections. If remote operated, it may
be hydraulically actuated. Where possible, divers can actuate the screws in the mechanical
connections.
It exists two types of tree connectors:
• H4 connector
• Collet connector
The H4 connector is the most commonly used connector. It is a hydraulically actuated
connector applicable for H4 type of wellhead profiles. The connector is used to land and lock a
Christmas tree to a subsea wellhead. The tree connectors can be both mechanical and pressure
connections together with orientation between the Christmas tree assembly and the wellhead.
C) Valves: Tree valves are designed in the Christmas tree assembly to control and safely stop
the fluid flow. The various valves are used for servicing, testing and regulating oil, gas, water
or chemicals. The most common type of valves in a Christmas tree is a gate valve. Gate valves
are operated either hydraulically, mechanically and/or by Remotely Operated Vehicles
(ROVs). Christmas tree valves should be designed, fabricated and tested in accordance with
API 17D, API 6A and API 6D.
All main valves are power-operated fail-safe closed valves, which means that the valves will
automatically close if either the signal or the hydraulic control pressure is lost. Swab and
control valves are fail “as is” due to production regulations. All Christmas tree are configured
to provide ROV access to the principal main Christmas tree valves and isolation needle valves
from the ROV panel. ROV interfaces shall be configured per ISO 13628-8.
Typical valve sizes include:
Production and Injection valves (typ. 5-7” gate valves) for controlling the process medium
Annulus or Injection Valves (typ. 2” gate valves) for annulus access
Service valves (typ. 3/8” to 1”) for chemical injection
Isolation valves (typ. 3/8 “to 1”) for pressure test and downhole lines
Check valves (typ. ½-1”) for preventing back-flow of well fluid to service lines.
Master gate valve. The master gate valve is a high quality valve. It provides full opening, which
means that it opens to the same inside diameter as the tubing so that specialized tools may be run
through it. It must be capable of holding the full pressure of the well safely for all anticipated
purposes. This valve is usually left fully open and is not used to control flow.
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The pressure gauge. The minimum instrumentation is a pressure gauge placed above the master
gate valve before the wing valve. In addition other instruments such as a temperature gauge will
normally be fitted.
The wing valve. The wing valve can be a gate or ball valve. When shutting in the well, the wing
gate or valve is normally used so that the tubing pressure can be easily read.
The swab valve. The swab valve is used to gain access to the well for wireline operations,
intervention and other workover procedures. On top of it is a tree adapter and cap that will mate
with a range of equipment.
The variable flow choke valve. The variable flow choke valve is typically a large needle valve.
Its calibrated opening is adjustable in 1/64 inch increments (called beans). High-quality steel is
used in order to withstand the high-speed flow of abrasive materials that pass through the choke,
usually over many years, with little damage except to the dart or seat. If a variable choke is not
required, a less expensive positive choke is normally installed on smaller wells. This has a built-
in restriction that limits flow when the wing valve is fully open.
This is a vertical tree. Christmas trees can also be horizontal, where the master, wing and choke
are on a horizontal axis. This reduces the height and may allow easier intervention. Horizontal
trees are especially used on subsea wells.
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CHAPTER 3
Overview Of Subsea Christmas Tree Systems
3.1 Industry Requirements
When a manufacturer is involved in a new project, the first step is to define the requirements and
specifications relevant for that particular project. The requirements are specified in the laws and
regulations of the countries involved, the standards are stipulated in the customer requirements
and in internal standards and requirements within the organization involved. Subsea production
system poses a hazard. It is therefore vital to have standards that give guidance to maintain secure
operations and prevent major accidents.
Applicable standards for the Christmas tree requirements include:
API 6A: Specification for Wellhead and Christmas Tree Equipment.
API 17D: Design and Operation of Subsea Production Systems-Subsea Wellhead and Tree
Equipment;
ISO 13628-4: Petroleum and natural gas industries – Design and operation of subsea
production systems. Part 4: Subsea wellhead and tree equipment;
ISO 10423:2009: Petroleum and natural gas industries - Drilling and production
equipment - Wellhead and Christmas tree equipment.
3.2 Christmas Tree Installation And Service Conditions
3.2.1 Christmas Tree Installation:
An Christmas tree can be installed either by a drill-pipe or by a crane through a moon pool at a rig
or a vessel, depending on the size of the Christmas tree. The vessel may be a jack -up,
semisubmersible or a drillship. Both Vertical Christmas tree and Horizontal Christmas tree
systems use a landing string through the BOP stack to run the completion.
Typical procedures for installing the Vertical Christmas tree and the Horizontal Christmas tree
system are as follows (Bai & Bai, 2012):
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Vertical Christmas Tree:
Perform pre-installation tree tests.
Skid tree to moon pool.
Push guide wired into tree guide arms.
Install lower riser package and
emergency disconnect package (EDP) on
tree at moon pool area.
Connect the installation and workover
control system (IWOCS)
Lower the tree to the guide base with
tubing risers
Lock the tree onto the guide base. Test
the seal gasket.
Perform tree valve functions with the
Installation and Workover Control System
(IWOCS).
Retrieve the tree running tool.
Rune the tree cap on the drill pipe with
the utility running tool system.
Lower the tree cap to the subsea tree.
Land and lock the tree cap onto the tree
mandrel.
Lower the corrosion cap onto the tree
cap with a drill pipe (or lifting wires).
Some suppliers have developed ROV-
installed corrosion caps.
Horizontal Christmas Tree:
Complete drilling
Retrieve the drilling riser and BOP stack;
move the rig off
Retrieve drilling guide base
Run the Production Guide Base (PGB) and
latch onto the wellhead
Run the subsea Horizontal Christmas tree
Land tree, lock connector, test seal function
valves with an ROV, release tree running
tool.
Run the BOP stack onto the Horizontal
Christmas tree; lock the connector
Run the tubing hanger; perform subsea well
completion; unlatch the Tubing Hanger
Running Tool (THRT).
Run the internal tree cap by wireline
through the riser and BOP; retrieve THRT.
Retrieve BOP stack.
Install debris cap.
Prepare to start the well.
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3.2.2 Service Conditions:
The pressure ratings for Christmas tree are standardized to 5000 psi, 10000 psi and 15000 psi.
Recently there are also Christmas tree constructed to apply for 20000 psi (ISO 13628-4, 2010).
Equipment shall be designed according to the material classes and temperature ratings required.
These ratings are specified in API SPEC 6A and 17D. For further information, see these
standards.
3.3 Christmas Tree Design And Analysis:
Each Christmas tree design is driven by reservoir requirements, such as type of chemical
injection needed. As an example, a gas reservoir is in the need of a constant stream of Mono
Ethylene Glycol (MEG) to avoid formation of hydrates, while an oil reservoir require artificial
lift methods to be able to recover the full potential of the well as the pressure decrease along with
the extraction of hydrocarbons. For each reservoir, it is necessary to conduct analyses for
protection of the equipment.
The analyses shall include the means of:
• Chemical injection
• Cathodic protection
• Insulation and coating
• Structural loads
• Thermal analysis
The kind of chemical injection chosen for a well depend upon the reservoir type and the fluid
characteristics. The final objective is to be certain that the equipment produces economically
from the reservoir to the production facilities throughout the whole lifecycle of the field
development. With the Christmas tree assembly constantly being exposed to the ambient sea
conditions, it is crucial with sufficient anodes for cathodic protection.
Thermal insulation is needed to ensure sufficient cool down time in the event of a production
stoppage. The main objective of thermal insulation is to have sufficient time to solve a shutdown
problem and avoid the burden of the launching preservation sequence with associated production
losses and to avoid dramatic consequences of hydrate formation with associated production
losses. Included in the insulation is a layer of corrosion coating suitable for working pressure,
specified by project requirements. The structures have to be designed so that they withstand
internal and external structural loads imposed during installation and operation.
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According to the standard API RP 17D special Christmas tree load considerations should be
analyzed for:
• Dropped objects,
• Marine riser and BOP loads,
• Flow line connection loads,
• Lifting loads,
• Snagged tree frame, umbilical's or flow line,
• Pressure induced loads. (American Petroleum Institute (API), 2011)
3.4 Test Program For Christmas Trees
Factory Acceptance Test (FAT) shall be executed of all units pre-installation to ensure that the
components of a unit and the unit itself satisfy all specified requirements to strength and
functional performance (ISO 13628-4, 2010).
All assemblies are required to pass FAT before they are passed to stock, prepared for Extended
Factory Acceptance Test (EFAT) or delivered directly to site for installation. Whenever
equipment is moved from one site to another it will be subjected to a Site Receipt Test (SRT). The
aim is to verify equipment received at site is in the same as before transportation state, with no
deterioration occurred during transportation.
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CHAPTER 4
Functional Requirements & Types Of Christmas Tree
4.1 Christmas Tree Functional Requirements:
The subsea Christmas Tree is located on the top of the wellhead, providing an interface between
the completion string and the piping towards the process system. At its simplest, an Christmas tree
can be defined as an assembly of valves and fittings used for production or injection to control the
flow of product, chemicals, water or gas from a well. The injection system, production control
system, downhole control system and monitoring and flow control system are all systems
controlled through the Christmas tree assembly.
Typical functional requirements include:
• Control of flow by directing hydrocarbons from the well to the flowline (called production tree)
or by canalizing water or gas into the reservoir to maintain reservoir pressure (called injection
tree);
• Regulate the fluid flow through a choke;
• Monitor well parameters, such as temperature, annulus pressure, well pressure and flow
composition;
• Act as a barrier between the reservoir and the environment;
• Safely open and shut down the fluid flow through the assembly of valves;
• Inject protection fluids, such as inhibitors for corrosion and hydrate prevention, to protect the
subsea equipment and to assist the flow.
Each Christmas tree is designed for the individual reservoir conditions and for the possible facility
solutions available, which means that the configuration, size, weight and cost for a Christmas tree
will differ from one offshore field to another due to the specific design requirements. The
optimum Christmas tree will be driven by reservoir requirements and therefore never completely
standardized. However, there is a strong trend towards smaller, more compact Christmas tree in
the industry.
4.2 Types And Configurations Of Christmas Trees
Christmas tree may be segmented into two main types: Vertical Christmas Tree and Horizontal
Christmas Tree. The Subsea Engineering Handbook, written by Yong Bai and Qjang Bai in 2012,
is the main source for the background information about the trees in the following sections.
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4.2.1 Vertical Christmas Tree:
The conventional Christmas tree, which is the Vertical Christmas tree, is the earliest and most
extensively used Christmas tree. The Vertical Tree concept is defined as having a vertical flow
though the tubing hanger. The master and wing valves in the tree body are located vertically
above the tubing hanger. The tubing hanger is landed in the subsea high-pressure (HP) wellhead.
This concept allows retrieval of the tree body with pulling the tubing hanger. A Vertical
Christmas tree are installed either on a wellhead or on a tubing head, after the subsea tubing-
hanger has been installed through the drilling BOP stack and landed and locked into the wellhead
or in the tubing head. The production flow path is through the valves mounted in the vertical bore
and out of the top of the tree during workover and testing or during production (injection) via the
production outlet that branches off the vertical bore (ISO 13628-4, 2010). The Vertical Christmas
tree is identified by the location of the production and annulus bore, that is placed vertically
through the tree body with the primary valves placed in a vertical configuration. The tree can have
a concentric bore or multiple bores. Annulus access may be through the bore or a side outlet in the
tubing head, depending on the Christmas tree design. A typical tree of this type is illustrated in
figure 4.1 and 4.2.
Figure 4.1 Vertical Christmas Tree Configuration
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4.2.2 Horizontal Christmas Tree:
The other main type of Christmas tree is the Horizontal Christmas tree design, also commonly
known as the spool tree. The Horizontal Tree is defined as diverting flow horizontally at the
tubing hanger. The master and wing valves in the tree body are located in the horizontal plane to
the tubing hanger. The tubing hanger is landed in the horizontal tree. This concept allows retrieval
of the tubing hanger with pulling the tree body. The Horizontal Christmas tree are distinguished
from the conventional design by the production and annulus valves being routed around the tubing
hanger in a horizontal configuration. One of the key functional features is that the Horizontal
Christmas tree may be installed after drilling and installation of the complete wellhead system, but
prior to installation of the tubing completion and tubing hanger.
Since the Christmas tree is installed prior to the tubing completion, the Blow Out Preventer (BOP)
stack is landed on top of the Horizontal Christmas tree and the tubing hanger and tubing
completion is run through the BOP and landed off on a landing shoulder in the bore of the
Horizontal Christmas tree. The production flow path exits horizontally through a branch bore in
the tubing hanger between seals and connect to the aligned production outlet.
An alternative arrangement is that the tubing hanger and internal tree cap are combined into a
single extended tubing hanger system suspended in the Horizontal Christmas tree. This doubles up
on the number of isolation plugs and annular seals for barrier protection and features a debris cap
that can also serve as a back-up locking mechanism for the tubing hanger (ISO 13628-4, 2010). A
third configuration, the drill-thru configuration, allow installation of the tree immediately after the
wellhead housing is landed, meaning that drilling and installation of the casing strings is
performed through the tree, minimizing the number of times it is necessary to run and retrieve the
BOP stack.
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Figure 4.2 Horizontal Christmas tree Configuration
4.3 Comparison Of Horizontal And Vertical Christmas Trees:
An ongoing debate within the Christmas tree industry is comparing the relative merits of Vertical
Christmas tree and Horizontal Christmas tree systems. For the last 20 years the Horizontal
Christmas tree has been the preferred design for deepwater fields, while in recent years the focus
in the industry is returning to the conventional Vertical Christmas tree system. A key requirement
when designing a Christmas tree is that access to the annulus is enabled between the production
bore and the casing. This is an important feature for a number of reasons, such as pressure
monitoring and gas lift means. As an example, any pressure build-up in the annulus may be bled
into the production bore via a crossover loop.
The original design of the Vertical Christmas tree and the Tubing Hanger (TH) were a dual-bore
configuration. Prior to removal of the BOP it was then necessary to set plugs in both the
production bore and the annulus bore. Access to the bores is handled with a dual-bore riser or a
landing string. The handling and operation with dual-bore systems compared to mono-bore
systems are more complex and time-consuming, and then again more costly.
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In an Horizontal Christmas tree configuration access to the annulus is incorporated in the tree
design and controlled by valves rather than plugs. This enables operation with mono-bore
systems, which means less complex riser or landing string. Easier access to the annulus enables
operations that can deliver significant advantages, particularly in deepwater (White, 2013).
Regarding installation and intervention, both Horizontal Christmas tree and Horizontal Christmas
tree systems use a landing string to run the completion through the BOP. In the Horizontal
Christmas tree configuration, the tree is normally run on a subsea test tree within the marine riser
to carry out a number of critical functions. Once the hanger is landed inside the landing shoulders
in the tree, it is critical to ensure communication of electric and hydraulic downhole functions.
The TH is landed passively inside the tree without relying on external input using an orientation
sleeve.
Before production, after a well is completed, it is common practice to flow the well fluid to the
drilling rig to clean up the well or to carry out a well test. For the horizontal christmas tree
systems this is carried out through the subsea test tree and a marine riser. The primary function of
the test tree ensures that, if necessary to disconnect the rig from the BOP during testing or
cleanup, the test tree will close the valves and an emergency disconnect will be performed safely.
In the case of the Vertical Christmas tree system, the completion is run on a landing string
incorporating a tool that run, lock and orientate the TH. This orientation requires a tool to
interface with a pin installed inside the BOP. Once the TH is oriented and installed inside the
wellhead, with the understanding that when the tree is oriented and landed on the wellhead, the
communication of all electric and hydraulic down hole functions will function. Well cleanup and
testing is then carried out after a dedicated test package and an open-water riser replace the BOP.
This test package comprises a Lower Riser Package (LRP) and an Emergency Disconnect
Package (EDP), enabling the rig or vessel to disconnect safely in the case of an emergency in the
same way as a test tree.
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CHAPTER 5
Tree Selection - Horizontal Vs Vertical Tree
5.1 Subsea Tree Selection:
The decision to select the subsea tree concept usually occurs early in the project due to long
delivery times. It is typical for this phase of the project to occur 18 to 24 months prior to the start
of drilling operations. Also, the contract commitment for the trees can be one of the first large
CAPEX expenditures for a new project. Therefore, it is imperative that the subsea tree concept
has been fully integrated into the overall conceptual well plan and that potential well control
risks identified with each option have been considered. The subsea tree selection process is
typically led by the Subsea Group of the Development Company, but critical input and
endorsement from Drilling is required.
Decisions made during this development phase have significant implications on almost every
aspect of the well plan and completion installation (specifically the completion riser type). Early
integration of drilling, completion and subsea expertise during the concept selection phase of the
project enhance the planning and execution phases of deepwater subsea developments.
There are two fundamental subsea tree concepts available to industry – Vertical Trees (VT) and
Horizontal Trees (HT). Essentially all of the subsequent completion discussions are predicated
on the type of tree selected.
5.2 Vertical Trees:
The nomenclature for these two tree concepts evolved from the tubing hanger design, depending
on the direction of the production flow stream relative to the tubing hanger (e.g., either vertical
or horizontal). With either subsea tree concept, the vertical production flow from the wellbore is
eventually diverted horizontally to enter the subsea flow line system. For the vertical tree
concept, the flow stream is diverted horizontally above the tubing. The production tubing is run
through the drilling BOP and landed in the 18-3/4 in. subsea wellhead or in the tubing hanger
spool. The drilling BOP must be pulled before the VT can be run. A special completion riser is
used to run the tubing/TH and the VT (Figure).The vertical tree concept can be further defined as
“Eccentric” or “Concentric” based on whether the production flow is routed eccentrically
(resulting in a dual bore configuration) or concentrically (a single bore configuration) through
the tubing hanger. These differences will be further discussed in this section.
17. T120026423 AMAR MADUKAR GAIKWAD Page 17
5.2.1 Eccentric Dual Bore Vertical Tree:
This tree concept, also known as a dual bore Vertical tree, has two vertical bores through the tree
body and tubing hanger as illustrated in Figure 5.2. In the Eccentric Vertical Tree concept, the
dual bore tubing hanger is eccentric and lands in the subsea wellhead body. The eccentric design
requires accurate orientation of the tubing hanger (TH) and the tree. The annulus bore provides
access to the production casing annulus and facilitates fluid circulation and well control during
tubing running or pulling operations when there are no downhole mechanical barriers. The
tubing hanger lands and seals in the subsea wellhead body. This makes the tubing hanger
independent from the VT itself. The Eccentric Vertical Tree concept has a minimum of two
subsea tree valves (e.g. master and swab valves) located vertically above each bore (e.g., the
production tubing bore and production casing annulus bore). It is also common for the tubing
hanger spool to have a crossover connection between the production and annulus bore, separated
by an X-over valve (XOV). This design provides vertical access through the vertical tree body to
run or pull wireline plugs that land into dedicated profiles in the dual bore tubing hanger. These
wire line plugs provide mechanical isolation to the tubing and production casing annulus for well
control. This becomes important during BOP removal/tree installation and during workover
operations. The Eccentric Vertical Tree concept has the production wing valve outlet in the tree
body at 90 degree to the production bore above the master valve. This diverts the production
flow stream horizontally, through the choke and mated connector to the subsea flowline system.
18. T120026423 AMAR MADUKAR GAIKWAD Page 18
Figure 5.1 Dual Bore Vertical Tree
Figure 5.2 Eccentric Dual Bore
5.2.2 Summary Of Eccentric Vertical Tree:
1. Two eccentric vertical bores through tubing hanger.
19. T120026423 AMAR MADUKAR GAIKWAD Page 19
2. Tubing hanger lands in subsea wellhead (active alignment).
3. Flow diverted horizontally after master valve.
4. Tree installed with dual bore completion riser (open water).
5. Through tubing workovers – no plugs to pull.
The typical steps to run the tubing and Eccentric Vertical Tree are as follows:
1. Production tubing hanger is run via a dual bore completion riser and landed in the subsea
wellhead. This system will be run through the drilling riser/BOP.
2. Flow barriers (wire line plugs) are run and set in the tubing hanger. The completion riser and
drilling riser/BOP are pulled.
3. The VT is run via a dual bore completion riser/BOP.
4. The flow barriers are removed, and either the well is allowed to flow back to surface via the
completion riser, or the tree cap is run and the well flows through the subsea manifold/pipeline.
The Eccentric Vertical Tree concept was used for the following projects:
1 .Zinc (ExxonMobil – GOM)
2. Girossol (Total Fina Elf - Block 17 Offshore Angola)
3. Balder (ExxonMobil – North Sea Norway)
4 .Blackback (ExxonMobil – Austraila)
5.2.3 Concentric Mono Bore Vertical Tree:
The Concentric Vertical Tree concept uses a mono bore tubing hanger that is concentric and sets
in a tubing hanger spool landed above the subsea wellhead. The concentric design does not limit
the production bore through the tubing hanger, therefore a larger tubing string can be used. For
this tree concept, the flowpath for the production casing annulus is around the concentric tubing
hanger through side outlets machined in the tubing hanger spool below and above the hanger as
shown in Figure. The tubing hanger lands and seals in the subsea wellhead body. This makes the
tubing hanger independent from the VT itself. The Concentric Vertical Tree concept has a
minimum of two subsea tree valves (e.g. master and swab valves) for both the production tubing
and casing. This design provides vertical access through the vertical tree body to run or pull
wireline plugs that land into dedicated profiles in the mono bore tubing hanger. These wireline
plugs provide mechanical isolation to the production tubing only. The production casing is
isolated with a valve in the tubing spool body. This becomes important during BOP removal/tree
installation and during workover operations.
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Figure 5.3 Concentric Vertical Tree Concept & Tubing Hanger
5.2.4 Summary Of Concentric Vertical Tree:
1. Single concentric bore through tubing hanger.
2. Tubing hanger lands in tubing hanger spool (passive alignment).
3. Flowbase design allows tree retrieval without pulling jumper.
4. Tree installed with mono bore completion riser (open water).
5. Additional permanent leak path (tree/tubing hanger spool).
The typical steps to run the tubing and Concentric Vertical Tree are as follows:
1. Flow barriers (wire line plugs) are run and set in the production casing.
2. The drilling riser/BOP is pulled.
3. The tubing hanger spool is run with DP.
4. Once the spool is landed the DP is pulled.
5. The drilling riser/BOP is run and the flow barriers are removed.
6. Production tubing/TH is run via a mono bore completion riser and landed in the tubing spool.
This system will be run through the drilling riser/BOP.
7. Flow barriers (wire line plugs) are run and set in the tubing hanger.
8. The completion riser and drilling riser/BOP are pulled.
9. The VT is run via the mono bore completion riser/BOP with a hose or small string
of tubing to maintain access to the production annuals.
10. The flow barriers are removed and either the well is allowed to flow back to surface via the
completion riser or the tree cap is ran and the well flows through the subsea manifold/pipeline.
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The Concentric Vertical Tree concept was used for the following projects:
1. Bongo (Shell – Nigeria)
2. Mensa (BP – GOM)
3. Crazy Horse (BP – GOM)
4. Macaroni (Shell – GOM)
5.2.5 Vertical Tree Summary
The main differences between the Eccentric and Concentric Vertical Tree concepts are:
1.The Concentric Vertical Tree body lands on a tubing hanger spool while the Eccentric Vertical
Tree body land on the 18-3/4 in. subsea wellhead.
2. The Concentric VT uses a mono bore tubing hanger. Therefore, the production annulus access
is around the tubing hanger (i.e. through the tubing hanger spool). Although the Concentric VT
system is designed to capture many of the advantages of both Eccentric VT and Horizontal Tree
concepts, this concept has some significant limitations to be considered during subsea tree
concept screening.
The key limitations include:
3. A separate trip in critical path (with a single derrick MODU) is required to install the tubing
hanger spool located between the subsea wellhead and vertical tree body which results in
additional installation costs and another potential leak path.
4. More potential leak paths due to additional connections.
5.3 Horizontal Trees:
As previously noted, the Horizontal Tree (HT) concept diverts the production flow stream out a
side outlet in the tubing hanger through production flow valves located 90 degrees from the
vertical run of the tree. The tubing hanger lands in the body of the HT. The HT uses a
hydraulically actuated connection to connect to the high pressure wellhead. The HT also has a
profile on top of the tree that allows the drilling BOP stack to connect to the tree.
The tubing hanger for this HT concept has an intersecting outlet at 90 degrees to the production
bore. This diverts the production flow stream through the production master and wing valves.
These valves may be either integral to the HT body or bolted on the side of the HT body. Access
to the production casing annulus is provided by a valved side outlet configuration that exits
below and re-enters above the tubing hanger as shown in Figures 5.5. and 5.6.
To secure the well for production operations, a permanent wireline plug must be installed in the
vertical bore of the tubing hanger above the flow outlet. Then, an internal tree cap is run and
landed in the tree above the tubing. A second permanent wireline plug is then run and landed in
the internal tree cap to fully isolate the vertical flow path. This plug allows future vertical access
without pulling the internal tree cap.
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Since the tubing hanger lands in the HT body and not the subsea wellhead, as with a dual bore
vertical tree, the interface between the subsea wellhead and subsea tree is less critical than with a
Vertical Tree concept. This allows the drill team greater flexibility to more easily use different
vendor designs for the subsea wellhead or utilize an existing exploration well that is temporarily
suspended. The HT concept can be further defined as “Partial Drilling” or “Full Drilling” as
shown in Figures 5.5 and 5.6. Both horizontal tree concepts utilize a concentric, mono bore
tubing hanger. Tubing hanger orientation is still required, due to mating of all control line
connectors.
5.3.1 Partial Drilling Horizontal Tree:
This concept (concentric vertical bore through the hanger and the production flow) is diverted
into an intersecting horizontal bore against a permanent wire line plug in the tubing hanger. A
fixed helix in the tree body provides passive tubing hanger alignment. Access to the tubing by
production casing annulus is around the tubing hanger through the tree body shown in Figure
5.5. This tree is typically run and landed using drill pipe. Once the HT is installed, it is not
possible to land casing hangers in the 18-3/4 in. subsea wellhead. However, since the HT is run
after setting a full string of 9-5/8 in. production casing, it is possible to run a drilling bore
protector and drill or sidetrack in an 8-1/2 in. hole through the HT. One of the key advantages of
this concept is that production tubing may be used as the completion riser. This eliminates the
need to have a costly dedicated completion riser.
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Figure 5.4 A) – Mica Partial Drilling Horizontal Tree
Figure5.4 B )– Mica Partial Drilling Horizontal Tree
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Figure 5.5 Partial Drilling Horizontal Tree
5.3.2 Summary Of Partial Drilling Horizontal Tree
1. Concentric vertical and intersecting horizontal bore in hanger.
2. Tubing hanger lands in HT body (passive alignment).
3. Tree installed on drill pipe.
4. Drill 8-1/2 in. hole with HT installed using a bore protector.
5. Production tubing used as completion riser.
The typical steps to running the Partial Drilling HT are as follows:
1. Run and cement the production casing.
2. Test the casing and install storm packer for well bore isolation.
3. The drilling riser/BOP is pulled.
4. The HT is run with a drill pipe landing string.
5. The HT coupled to the connection on top of the wellhead.
6. The drilling riser/BOP is run and coupled to the connection on top of the HT.
7. The storm packer is removed.
8. The production tubing/TH is run with a subsurface test tree (SSTT) and a mono bore
completion riser or landing string. This system will be run through the drilling riser/BOP.
9. The well is flowed back to surface via the completion riser (landing string), or the internal tree
cap is run and the well flows through the subsea manifold/pipeline.
10. Pull the subsurface test tree (SSTT) and a mono bore completion riser or landing string.
11. Pull the drilling riser/BOP.
12. Run the external tree cap on drill pipe.
The Partial Drilling HT concept was used for the following projects:
1. Diana, Marshall, Madison (ExxonMobil GOM)
2. Mica (ExxonMobil GOM) (Figure 5.4)
3. Kizomba (ExxonMobil Angola)
5.3.3 Full Drilling Horizontal Tree:
This Full Drilling HT concept is based on combining the existing 16-3/4 in. subsea wellhead and
18-3/4 in. HT tree designs. The concept is to manufacture a 16-3/4 in. subsea wellhead system
with an 18-3/4 in. hub. This would permit an 18-3/4 in. HT system to be run on drill pipe
immediately after running and cementing the subsea wellhead on 20 in. conductor casing. Or in
the case of the slim hole design, 13-3/8 in. with a crossover to 20 in. casing and an 18-3/4 in. hub
is run. The 18-3/4 in. BOP stack would then be run and landed on top of the 18-3/4 in. HT. A
25. T120026423 AMAR MADUKAR GAIKWAD Page 25
drilling wear bushing would be run to protect the HT bore. Then drilling and casing running
operations would be conducted through the 18-3/4 in. HT body (see Figure5.6).
The Full Drilling HT concept eliminates the need to pull the 18-3/4 in. BOP stack by allowing
the 9-5/8 in. casing string to be run through the HT body. Even though this concept can save a
BOP trip on a single well basis, much of its incentive is lost if batch installation of trees is done.
One key advantage of this concept is the use of a flow base which allows the tree body to be
pulled without disconnecting the jumper between the flow base and the manifold. The tubing
hanger spool is typically run & landed using drill pipe, while the tree body is usually installed
with a mono bore completion riser in open water. However, a separate trip is required to install
the tubing hanger spool, and another permanent leak path is introduced.
Figure 14.6 - Full Drilling Horizontal Tree
5.3.4 Summary Of Full Drilling Ht Concentric Vertical And Intersecting Horizontal Bore In
Hanger
1. Tubing hanger lands in HT body (passive alignment).
2. Tree installed on drill pipe.
3. Drill 12-1/4 in. and 8-1/2 in. hole with HT installed using a bore protector (slim hole design).
Production tubing used as completion riser.
The typical steps to running the Full Drilling HT are as follows:
1. Run and cement the surface casing. Test the casing and install storm packer for well bore
isolation.
26. T120026423 AMAR MADUKAR GAIKWAD Page 26
The drilling riser/bop is pulled.
2. The tubing spool is run on mono bore completion riser.
3. The ht is run with a mono bore completion riser, and the ht is coupled to the tubing spool.
4. The drilling riser/bop is run and coupled to the connection on top of the ht.
5. The storm packer is removed.
6. The remaining hole sections are drilled.
7. The production tubing/TH is run with a subsurface test tree (SSTT) and a mono bore
completion riser or landing string. This system will be run through the drilling riser/BOP.
8. The well is flowed back to surface via the completion riser (landing string) or the internal tree
cap is run, and the well flows through the subsea manifold/pipeline.
9. Pull the subsurface test tree (SSTT) and a mono bore completion riser or landing string.
10. Pull the drilling riser/BOP.
11. Run the external tree cap on drill pipe.
The Full Drilling HT concept was used for the following projects:
1. Dalia (Total Fina Elf – Block 17 Offshore Angola)
2. Ross (Talisman Energy – North Sea UK)
5.4 Tree Selection Summary:
Since the cost of VT and HT tree components are very close, the key driver for the subsea tree
selection process becomes the cost, availability, and operation of the completion/workover riser
system during initial installation. Certain assumptions for well intervention versus subsea tree
failures can also contribute to the subsea tree selection process. If it is assumed that more tubing
pull work overs would be required due to down hole completion failures, the HT concept
becomes more attractive.
The subsea trees have generally proved more reliable than the overall down hole tubing and sand
face completion. Thus, ExxonMobil has preferred horizontal trees for recent deepwater
developments to capture the operational and financial benefits associated with installation
efficiencies and to eliminate the need for a dedicated completion riser system.
A significant advantage of the vertical tree is that routine interventions into the wellbore can be
accomplished without the risks associated with pulling and resetting wire line plugs, but a
dedicated completion riser system is needed. The major advantage of the horizontal tree is that
the production tubing can be pulled from the wellbore without pulling the HT body, (using the
MODUs well control system, e.g. no dedicated completion riser system is needed). In many
development areas this is a significant driver to the tree selection decision.
A qualitative and quantitative, development specific, intervention study will be needed to
determine the frequency of the expected intervention operations. This exercise will help
27. T120026423 AMAR MADUKAR GAIKWAD Page 27
highlight which tree concept is most cost effective for a given scope of intervention work. In
general, if tree failures are the source of the majority of interventions, then vertical trees tend to
offer substantial benefits. If down hole failures have the higher potential, then horizontal trees
have inherent benefits.
For example, a quantitative intervention study for a particular development may determine that
artificial lift is required and/or the risk of sand control failure is high. In that case, the project will
likely benefit from the use of a horizontal tree that allows tubing string removal without the cost
of subsea tree removal.
In contrast, a development of naturally flowing wells with no sand control requirement and little
risk of down hole mechanical failure could likely benefit from use of a vertical tree. This is
because the relative frequency of tree related intervention with respect to down hole intervention
is likely greater. A major failure of a vertical tree requiring a pulling operation could be
conducted without pulling tubing. With a horizontal tree, the tubing must be pulled prior to
pulling the tree.
Other considerations are driven by rig selection and rig availability issues. The deck space,
variable deck load constraints and moon pool size/height under the rig floor is a critical aspect of
handling trees and completion equipment. The VT is typically taller than the HT and so requires
more height clearance under the rig floor. The HT is typically wider than the VT and therefore
requires a large moon pool area. If a dedicated completion/workover riser is utilized, the drilling
riser would likely need to be offloaded between wells. These size constraints and riser issues will
dictate the type of MODU (Fourth or Fifth Generation) is capable of conducting the operation.
For deepwater operations, horizontal trees provide a number of key advantages over
vertical trees.
1. When cleaning up and testing a subsea well to a Mobile Offshore Drilling Unit (MODU), two
independent well control systems are fully functional. First, the subsea test tree with shut-in and
disconnect functions, provides the primary well control system. Second, the rig blowout
prevention stack (BOP) provides shearing and disconnect capabilities in the event of a subsea
test tree failure.
As a result, well control risk is substantially reduced.
2. Horizontal trees can be batch set on the subsea wellhead before commencement of completion
operations; thus reducing overall installation times, equipment costs and complexities of vertical
trees.
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CHAPTER 6
Case Study – Tree Selection For Deepwater GOM Project
Horizontal trees were selected for all of the recent deepwater Gulf of Mexico subsea
developments (Diana, Marshall, Madison and Mica). The basis for the recommendation was a
single well comparison of an Eccentric Vertical Tree versus a Partial Drilling Horizontal Tree.
The time motion analysis of the vertical tree versus Horizontal tree installation sequence showed
that the HT concept would take about 2 days more of rig time than the vertical tree concept.
However, the lower leased cost of the SSTT more than offset the higher cost of a leased dual
bore completion/workover riser system.
Additionally, the future availability of the leased completion/workover riser system for
workovers was identified as a concern. Purchase of a dual bore completion/workover riser
system for the small number of wells in the development could not be justified. The analysis
suggested that selection of the Horizontal Tree would result in an average savings of about
$800k/well. Even though the horizontal tree concept had not previously been used at the required
water depth (~4,650 feet of water), the drilling organization supported the HT recommendation,
since it appeared that it had greater potential to reduce completion installation time and costs.
Use of the Eccentric Vertical Tree concept and dual bore completion/workover riser system
could expose operations to potential weather delays if offloading of the drilling riser was
required due to deck space limitations on MODU. Drilling estimated that weather delays
offloading or loading riser could add $1.0M per well if sufficient boats were not available to
conduct these operations out of critical path. Actual installation times for horizontal trees
installed at the Diana field were compared to the vertical trees installed at the Zinc field. This
comparison showed an average savings of 6.7 days per well for horizontal trees using a single
derrick MODU. Minimizing tripping of the BOP stack and batch installation operations were key
drivers to this savings in time achieved at Diana. Additionally, the elimination of the
completion/workover riser system by using the MODUs drilling riser increased available deck
space for other completion equipment and decreased overall cost.
The HT concept provided future flexibility by being able to use existing drilling risers from
many different MODUs. Assumptions for well intervention can also contribute to the subsea tree
selection decision. The ability to sidetrack and re-drill through the HT further reduces costs since
sidetracks can be performed without pulling the HT. One sidetrack re-drill through the horizontal
tree has already been performed at Diana, and the development plan anticipates future sidetrack
re-drill opportunities. Drilling operations personnel also preferred the SSTT system and the
MODU BOP stack for well control instead of a specialized completion/workover riser system
that included a workover BOP and EDP. The decision to use the production tubing as the landing
string also provided additional cost savings to the project.
29. T120026423 AMAR MADUKAR GAIKWAD Page 29
Conclusion
The capability and flexibility offered by modern subsea Christmas trees and production systems
is, by any measure, truly impressive. The industry has moved from simple production systems to
more expansive ones incorporating complex controls and sensors and a range of monitoring and
diagnostic systems. For the last 20 years the Horizontal Christmas tree has been the preferred
design for deepwater fields, while in recent years the focus in the industry is returning to the
conventional Vertical Christmas tree system. The demands for the production of hydrocarbons
from deep water at higher pressures and temperatures, coupled with a range of additional design
constraints, ensure that subsea tree systems will continue to evolve to meet these challenges both
now and in the future. The design of the Vertical Christmas tree and the Tubing Hanger (TH)
were a dual-bore configuration. The handling and operation with dual-bore systems compared to
mono-bore systems are more complex and time-consuming, and then again more costly.
30. T120026423 AMAR MADUKAR GAIKWAD Page 30
References
1. Towns, T. K., Deeken, D. G., Derby, L. M., Exxon Mobil Development Company, “Diana
Subsea Tree Selection and Installation Results in 4,653 Feet of Water” Deep Offshore
Technology held in Rio de Janeiro, Brazil, October 17-19, 2001.
2. Moyer, M.C., Barry, M.D., Tears, N.C., "Hoover-Diana Deepwater Drilling and
Completions", OTC 13081, Offshore Technology Conference, Houston, Tx, May 2001.
3. Havard Devold," Oil And Gas Production Handbook", An Introduction to Oil And Production,
ABB Oil And Gas, May (2009), Edition 2.0 Oslo,29-32.
4. Oda Ingeborg Stendebakken, NTNU Trondheim, "A reliability study of a Deepwater Vertical
christmas Tree with attention to XT retrieval rate", June (2014),11-32.
5. Randy J. Wester and Eric P. Ringle / FMC Energy Systems," Installation and Workover Time
Savings: Key Drivers for Deepwater Tree Selection" ,OCT 12943, Offshore Technology
Conference, May (2001).