Reutilization of Ex-Used ESDV for New Well Connection at Pertamina Hulu Mahakam

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This page will discuss about the reutilization of Ex-Used ESDV (emergency shut down valve) for new well connection at an Oil and Gas company, namely Pertamina Hulu Mahakam. ESDV has the function to shut-off the flow of fluid from the well head into the pipeline that distributes gas, to prevent pipeline damage. The topic will mainly focus on the reutilization of Ex-Used ESDV from past existing well to be used for future well connection. There are 2 study case, the first one is the fabrication of new coupling part that has the function to connect between the ball valve and actuator of the ESDV. The second study case is the evaluation of reutilized ex-used ESDV compared to new purchase ESDV in terms of cost, time, and quality.

TABLE OF CONTENT

CHAPTER I INTRODUCTION

1.1 Background
1.2 Objectives
1.3 Scope
1.4 Methodology
1.5 Date and Place of the On Job Training
1.6 Report Outline

CHAPTER II COMPANY PROFILE

2.1 Background of PT Pertamina Hulu Mahakam (PHM)
2.2 Vission and Mission of PT Pertamina (Persero)
2.3 Vission and Mission of PT Pertamina Hulu Mahakam
2.4 PT Pertamina (Persero) Priorities
2.5 PHM Operation Sites
2.6 PHM Organizational Structure
2.7 ECP (Engineering, Construction & Brownfield Project) Division
2.8 ECP/CST (Construction)

CHAPTER III ESDV BASIC INFORMATION

3.1 What is Emergency SDV or SDV (Shutdown Valve)
3.2 Valves
3.2.1 Valve Types
3.3 Actuators
3.3.1 Actuated Actuator Types

CHAPTER IV WELL CONNECTION & ESDV UTILIZATION

4.1 Oil and Gas Indsustry Sectors
4.2 Upstream Activities
4.3 Well Connection
4.3.1 Location
4.3.2 Well Slot Availability
4.3.3 Well Connection Sequence
4.4 Utilization of ESDV in PHM Well Connection
4.4.1 Tunu Remote Well Safety Instrumented System
4.4.2 ESDV Activation

CHAPTER V STUDY CASE

5.1 Valve Coupling Modification
5.1.1 Coupling Geometry
5.1.2 Calculation of Top Coupling Connection (Coupling to Actuator)
5.1.3 Calculation of Bottom Coupling Connection (Coupling to Valve)
5.2 ESDV Ball Valve Acceptance Criteria
5.2.1 Shell Test (Water)
5.2.2 High Pressure Closure Test (Water)
5.2.3 Low Pressure Closure Test (Air or Nitrogen)
5.2.4 High Pressure Closure Test (Nitrogen)
5.3 Evaluation for Ex-Used ESDV Reutilization
5.3.1 Actual Cost & Delivery Time of New ESDV
5.3.2 Estimated Breakdown Cost/Duration for Ex-Used ESDV Reutilization
5.3.3 Estimated Breakdown Duration for Ball Valve & Actuator Repair
5.3.4 Examples of ESDV Repair/Modification Estimated Cost & Duration
5.3.5 New & Repair/Modification ESDV Comparison in Terms of Cost & Duration
5.3.6 Highest/Lowest Cost & Duration of ESDV Repair/Modification
5.3.7 Quality of Reused/Repaired ESDV

CHAPTER VI CONCLUSION & RECOMMENDATION

REFERENCE

APPENDIX

CHAPTER I INTRODUCTION

1.1 Background

Internship as one of the requirements of graduating in the Mechanical Engineering program is one of the most important aspects in the studies as a mechanical engineer. It shows that in the near future as a fresh graduate, experience is needed as one of the needs and requirements for an individual to have in order to further compete in the professional level. To become an engineer, the knowledge on the reality of the operation is needed in order to make fair judgment as well as improvement not only based on theory but also the real condition. Since studies on campus is not covering this type of skill and experience, hence the internship program is an important experience for every mechanical engineer future graduate. Oil and gas is an energy resource that has an important role for the human daily needs. From year to year we realize that the need for oil and gas increases as the human needs for them increases throughout the year. For this reason, it is necessary to use an efficient and appropriate petroleum and natural gas extraction and processing technology so that an increase of production can be achieved to meet human energy needs. PT Pertamina Hulu Mahakam (PHM), which is affiliated under PT Pertamina Persero is an Indonesian-state owned oil and gas corporation that will be able to fulfill the needs of experience and knowledge for future graduate of mechanical engineering. The company runs its business as exploration and production of oil and gas in the Mahakam block located in East Kalimantan. It upholds a critical view on prioritizing QHSSE by contributing in an environment-friendly workplace as it holds safety, integrity of assets, environment, health, security, community, as well as the quality in all asset life cycle as a top priority. Numerous location of operations are spread around the Mahakam working area. Therefore, PT. Pertamina Hulu Mahakam is the perfect place for the internship, since one of the main reasons for this intership is to gain learning experiences as well as an on – site work experience. With the following values uphold, I believe that this program will support my future endeavor for the career ahead as a professional engineer.


1.2 Objectives

As an undergraduate student of Mechanical Engineering Departement of Universitas Indonesia, the objectives of job training in PT Pertamina Hulu Mahakam (PHM) are:

  1. To fulfill the requirement for graduation from the Mechanical Engineering Department of Universitas Indonesia, as part of the curriculum.
  2. To apply the theoritical knowledge obtained from lectures in the Mechanical Engineering Department of Universitas Indonesia in real life application.
  3. Gaining experience on how the overall organization of PT. Pertamina Hulu Mahakam works and how divisions that is related on mechanical engineering works.
  4. Obtain knowledge about inspection and testing procedure for emergency shutdown valve (ESDV)


1.3 Scope

The scope of the On the Job Training (OJT) program in PT Pertamina Hulu Mahakam includes the following:

  1. The trainee will obtain documents and study about emergency shut down valve and well connection activities
  2. The trainee will study the acceptance criteria for modification or reused ESDV
  3. The trainee will access the torque calculation of newly fabricated ESDV coupling based on the used actuator
  4. The trainee will access the result of ESDV refurbishment in terms of cost, time, and quality compared to new ESV unit


1.4 Methodology

Research methods which are used in the On the Job Training (OJT) program are as follow:

1. Preparation

Preparation includes the induction to the company, coordination with the mentor, knowing the working environment and the workers, as well as literature study on the information and reference about the object to be analyzed.


2. Initial Planning Determining the duration of the On the Job Training and the focus of topic, thus assigning work in relevance of each focus.


3. Data Gathering Gathering all sorts of relevant data throughout all process directly on the field, related literature study, and interviewing the workers.


4. Report Writing Writing all the information and evaluation of the training program in a report that must be given to the supervisor and home university. The format of the report is determined by the Mechanical Engineering Department of Universitas Indonesia.


1.5 Date and Place of the On Job Training

The period of this On Job Training is from the 17th of June 2019 until the 30th of August 2019 (55 working days) taking place in PT Pertamina Hulu Mahakam office Balikpapan.

  • Division/Department/Service : ECP/CST/OPT
  • Company Address : Jl. Yos Sudarso, Balikpapan


1.6 Report Outline

  • Chapter I Introduction

Describe about the background, objectives, scope, methodology, date and place of the On the Job Training, and report outline.

  • Chapter II Company Profile

Describe about the background of the company, company’s vision and mission, company’s priorities, operation sites, and organizational structure of the CST Department.

  • Chapter III ESDV Basic Information

Describe about all the basic theories which is related to the general conditions of emergency shutdown valve (ESDV).

  • Chapter IV Well Connection & Utilization of ESDV

Describe about the remote well connection activities, general utilization of ESDV on PHM wel connection, and ESD logic and ESDV inner workings.

  • Chapter IV Study Case

Describe about the study case given by the supervisor as well as discuss and analyse the result of the study case. The study case includes the calculation of new fabricated ESDV coupling and analysis of modification/reused ESDV based on cost, time, and quality.

  • Chapter V Conclusion and Recommendation

Describe about the conclusion based on the objectives and recommendations for the company.

CHAPTER II COMPANY PROFILE

2.1 Background of PT Pertamina Hulu Mahakam (PHM)

PT Pertamina was founded in 10 December 1957 as PT Permina which became PN Permina in 1961. On the 20th of August 1968 PN Permina and PN Pertamin merged into PN Pertamina (Persero), which then became PT Pertamina (Persero) on the 17th of September 2003. PT Pertamina (Persero) itself is a State Owned Enterprise that is 100% owned by the government of the republic of Indonesia and its business focuses on energy. The flow of Pertamina integrated business activities includes from E&P, Refinery, Shipping/Piping, Storage, Transportation, and finally to Fuel & Gas Sation. One of the key operating companies is PT Pertamina Hulu Indonesia (PHI) as part of PT Pertamina (Persero). PT Pertamina Hulu Indonesia inludes PT Pertamina Hulu Mahakam (PHM) as one of its subsidiary company under supervision of Special Unit for Upstream Oil and Gas Business Activities / Satuan Kerja Khusus Pelaksana Kegiatan Usaha Hulu Minyak dan Gas Bumi (SKKMIGAS). PT Pertamina Hulu Mahakam itself has the task to manage the Mahakam working area, where the management is carried out while maintaining the mahakam working area, controlling operating costs, as well as continuing to prioritize QHSSE (Quality, Health, Safety, Security and Environment). In the late 2017 PT Pertamina Hulu Mahakam took the management over the former owner, Total E&P who has operated the Mahakam block since 1968. The event was held on the 31st December 2017 at Gunung Utara Club House Longikis Street, Balikpapan. The cooperation contract for Mahakam block was signed by Total E&P Indonesie and Inpex on 6 October 1966 in term of 30 years. In 1991, Total E&P Indonesie extended the contract for 20 years until 31st march 2017. And the contract gets additional time for 9 months until 31 December 2017. This additional contract occurred because of the extended selling contract of LNG until 31 December 2017. Pertamina Hulu Mahakam moves in upstream sector (exploration and production). Mahakam block became the largest gas producer in Indonesia since 2000 and currently account for 82% of the total supply of LNG plant Bontang. More than 45 years is the Mahakam block active in the role to build the energy industries in this country. The Mahakam block consist of several oil and gas fields located in Mahakam delta, East Kalimantan: Handil oil field located I southern part of Mahakam Delta, Tambora oil field located in upstream of the Mahakam Delta, and Tunu gas field located in eastern part of Mahakam Delta. Other oil and gas fields in Mahakam Block are located offshore, i.e. Bekapai oil field, Peciko gas field, Sisi Nubi gas field, and South Mahakam gas field.


2.2 Vision and Mission of PT Pertamina (Persero)

The vision and mission that PT Pertamina (Persero) upholds are:

  • Vision: To be world class national energy company.
  • Mission: To carry out integrated core business in oil, gas, new and renewable energy based on strong commercial principles.


2.3 Vision and Mission of PT Pertamina Hulu Mahakam

The vision and mission that PT Pertamina Hulu Mahakam upholds are:

  • Vision: To be a world class national exploration and production company and to be one of Pertamina’s center of excellence.
  • Mission: To carry out a safe, sustainable, reliable, efficient and eco-friendly exploration and production activities by prioritizing value creation, utilizing innovation-based technology, robust commercial principles and world employee.


2.4 PT Pertamina (Persero) Priorities

PT Pertamina (Persero) has 8 main priorities in its business that is being implemented, which inlude Company Growth, HSSE & Sustainability, Human Capital Development, Upstream Growth, Gas Growth, Strengthening Refining & Petrochemical Business, New and Renewable Energy Development, and Infrastructure & Marketing Development.

To implement these priorities 6 core values (6C) are implemented by PT Pertamina (Persero), which are:

  • Clean: Professionally managed, avoid conflict of interest, never tolerate bribery, respect trust and integrity based on god coorporate governance principles.
  • Confident: Involvement in national economic development, as a pioneer in State-Owned Enterprise reform, and to build national pride.
  • Commercial: Create added value based on commercial orientation and make decisions based on fair business principle
  • Competitive: Able to compete both regionally and internationally, support growth through investment, build a cost effective and performance oriented culture.
  • Customer Focus: Focus on customers and commit to give the best services to customers.
  • Capable: Managed by professional, skilled and highly qualified leaders and workers, commited to building research and development capabilities.


2.5 PHM Operation Sites

Sites working area of PHM includes in the area of the Mahakam Block consisting of Tunu, NPU, Sisi Nubi, Bekapai, Peciko, South Mahakam, Tambora, Handil, CPU.

Figure 2.1 PHM Working Sites.png


  • Bekapai and Handil Fields

Bekapai’s discovery in 1972 was an early milestone for Mahakam block. The complex field covers some 20 square kilometers, just off the East Kalimantan coast in the Makassar Strait. Installations are sited in water at 30 to 40 meters depth, and the first phase was thus a floating unit. This was replaced by a multi-well platform linked to central processing and living quarter platforms. Up until now over 100 distinct oil reserve reservoirs have been identified at Bekapai, at depths ranging from 1,300 to 2,500 meters. In the end of 2006, 76 wells were already drilled from 9 multi-well platforms. Seventeen of these are still active. Bekapai is, at present, considered a mature oilfield, as approximately 95% of recoverable reserves have been extracted, but new wells drilled during the course of 2007 have shown that potential remains in the field. Handil is sited among swampy shores partially submerged at high tide in the Mahakam River Delta. These areas are covered with a thick forest of nypa palm vegetation. With an area of some 40 square kilometers, Handil Field requires swamp barge rigs for the drilling of deviated wells along island banks. Handil field consists in more than 550 hydrocarbon accumulations in structurally stacked and compartmentalized deltaic sands from 230mSS down to 3000mSS. Biggest reservoirs are concentrated in the so-called Main Zone of Handil located between 1500 and 2300mSS. Drilling first yielded promising results in March 1974, with production commencing about 15 months later; peaking at 200,000 BOPD in March 1977. To maintain its production level, PHM applied first water injection and then gas lift as depletion became more pronounced. Tertiary recovery by gas injection was an immiscible gas injection starting in November 1995. And in 2001 an air injection pilot was started up, to test a new oil production enhancing technique. By the end of 2009, 423 wells have been drilled at Handil, the current production is 20,000BOPD and 100MMscfd with cumulative oil of 860.4 MMbbl oil and cumulative gas of 1.7 Tcf. It is estimated that Handil is fully matured as far as conventional petroleum potential is concerned, as 95% of recoverable oil reserves have been extracted. A data acquisition campaign regarding Remaining Oil Saturation is on-going to better assess the means (EOR technique or others) to continue maximizing the oil recovery.

  • Tambora and Tunu Fields

Tambora is an onshore gas field, sited in the central part of the Mahakam River Delta. It was first discovered in 1974 and was the catalyst for the discovery in 1977 of the giant Tunu Field, a 400 square kilometer resource stretching 80 kilometers from north to south along the Mahakam River Delta coastline. Hydrocarbons from these two fields are collected at wellhead Gathering and Testing Satellites (GTS), then sent to the project’s first Central Processing Unit (CPU-1), an installation consisting of a gas separation unit, gas dehydration unit, oily water treatment unit (OWTU), condensate pumping and two electric gas turbine generators; CPU-1 has a processing capacity of 350 MMscfd. Four additional GTS units and one manifold platform were installed in 1993, together with new delivery lines and a second processing, CPU-2, with an additional capacity of 900 MMscfd. Two more GTSs were added in 1994. Production from the Northern extension of the Tunu field began in the late 1998 following a project to install four new GTS’s, linked to a new treatment center in the North part of the swamp (the Northern Processing Unit or NPU). This phase of the development was completed with new gas and condensate export lines, including a new metering center installed close to Badak known as the TATUN (Tambora-Tunu) Receiving Facilities (TRF). As the reservoir pressure declined, it became necessary to install compression facilities in the field. The first of these consisted of a medium-pressure compression platform installed next to CPU2 was the Tunu Compression Platform – TCP, with a 900 MMscfd capacity, a medium pressure (MP) pipeline network, along with various manifolds, scrapper traps and air cooler surface platforms. This came on stream in 2000, and was followed a couple of years later by a similar project in Tunu North – known as the Northern Compression Platform – NCP. In parallel to the compression facilities, additional wellhead GTSs were installed as the field limits were extended Northwards and Southwards. To maximize recovery of wells at lower wellhead pressures, Tunu Phase 11 Project was installed a low pressure (LP) compression facilities for the southern and northern fields with maximum capacity of 605 MMscfd for south field and 445 MMscfd for north field. Tunu Phase 11 was started up in late of 2009 allowing production configuration into MP and LP mode simultaneously. At the same time, the Tunu Phase 12 project consists of construction 3 GTSs and adjacent wellhead platforms (connected in a modular fashion to a common production and test header). The 3 GTSs are planned to be ready for drilling in 2009. This project is notable as being the first all steps of the project, including Basic Engineering, were carried out in Indonesia. Tunu 13 project of additional 2 GTSs and adjacent wellhead platform is being commissioned with the design similar with Phase 12 project.

  • Sisi Nubi Fields

These two offshore gas fields were first discovered in 1986, located 25 km offshore from Mahakam Delta and 30 km to the Southeast of the Tunu Field. The first phase of Sisi Nubi Project Development included construction of the Sisi Manifold and Wellhead Platform (MWPS), the Nubi Manifold and Wellhead Platform (MWPN), one Nubi Satellite Platform (WPN2) and one slug catcher platform (SNPS). A 26-inch main export pipeline, a 22-inch interfiled pipeline and a 16-inch trunkline are laid during this phase. Both fields are characterized by multiple layers of poorly consolidate sands. Therefore, this would be required an advanced drilling technique to drill 27 development wells in the first phase. Development drilling started in September 2007 and followed by production Start-Up in November 2007. Further development phases are foreseen later to extend the plateau period, which include extension of existing wellhead platform and additional wellhead platform.

  • Peciko Fields

Contained within an area of some 300 square kilometers, in water depths ranging from 30-50 meters offshore, Peciko is geologically complex with gas trapping both structural and stratigraphical. Its reservoir consists of a series of very fine-to medium grained sands distributed through shale siltsone deposits. The main reservoir is located at 2,100 to 3,900 meters below sea level. Peciko was first discovered in 1983, but its commercial viability was not confirmed until 1991 when the NW-1 well was drilled. Like Tunu, Peciko is also a giant gas field. The onshore processing unit is at Senipah (PPA-Peciko Process Area), linked to gas exports via an 82-kilometer of 42-inch onshore export pipeline. This massive project first came on stream in December 1999. Peciko condensate from PPA is mixed with Tunu condensate, then processed in the Senipah Condensate Stabilization Unit (CSU), before being exported through the SBM. Since the start up of the field, two trains of gas compression, each with a capacity of 450 MMscfd have been added.

  • Senipah Oil and Condensate Handling Terminal

Despite Mahakam Delta is rich in hydrocarbon deposits, it also lacks the deep-water access necessary for large tankers. Permanent oil-handling terminal was built near the coastal village of Senipah. Senipah oil terminal started-up operations in 1976 to deal with rapidly-increasing production in the mid 1970s. More than 3,000 vessels have docked at Senipah Terminal, to lift more than 1 billion bbl of crude oil and condensate. Oil and gas from Bekapai are transported via a 12-inch submarine pipeline, whereas oil from Handil is sent to dual diameter pipeline 20/24" burried to Senipah where field products are separated and stabilized, before oil is sent to storage and then exported from the Single Buoy Mooring (SBM). Tanks, each with a storage capacity of 2.6 MMbbl, along with an SBM loading facility capable of handling 125,000 DWT tankers, were constructed at Senipah. In June 1996, a Condensate Stabilization Unit (CSU) officially started to process and stabilized condensate before being marketed. Current processing capacity of the CSU is 40,000 bbl of condensate per day.

  • South Mahakam Fields

South Mahakam complex located approximately 35 kilometers offshore, at a sea depth of 45 to 60 meters, some 58 kilometers south of Peciko Field. The Stupa Field was discovered in 1996, yielding strongly, with highly over-pressured sections. Four more wells were drilled in 1998, confirming the scale and scope of the accumulation. The plan of development is currently under the approval process with the Authorities. Additional successful exploration drilling on the West Stupa and East Mandu structures conducted in 2007 further verifying the potential of the area. Development studies are currently being fast-tracked so that these fields can be included in the original Stupa development and brought into production by the beginning of the next decade. Geoscientists are now working with the latest seismic imaging techniques to identify greater potency in this area. Project is now under way with target of ready for startup at the first quarter of 2012.


2.6 PHM Organizational Structure

Pertamina Hulu Mahakam (PHM) based in Balikpapan, East Kalimantan, has a complex organizational structure. Director (DIR) is at the highest followed by the General Manager (GM), where there are several divisions under it. One of the division under General Manager (GM) is the East Kalimantan District & Operations (EVP). EVP covers all of the operational area in East Kalimantan with consisting of 10 divisions as follow:

  1. Well Construction and Intervention (WCI)
  2. Field Operations (FO)
  3. Losgistics, Land, Sea & Air (LSA)
  4. Integrity (EVP/INT)
  5. Technical Ref. & Performance (RPE)
  6. Greenfield Project (GFP)
  7. Development & Planning Div. (DP)
  8. Contract & Procurement (C&P)
  9. Information Systems & Tel (IST)
  10. Engineering, Construction & Project (ECP)


2.7 ECP (Engineering, Construction & Brownfield Project) Division

The Engineering, Construction & Brownfield Project (ECP) division has the mission to design, construct and deliver new project on surface facilities for TEPI operations. It also support modification and optimization of existing surface facilities. Several departement are under ECP with consisting of 7 departments as follow:

  1. ECP/PJC (Project) Departement
  2. ECP/PRO (Process Studies) Departement
  3. ECP/STD (Survey, Technology & Design) Departement
  4. ECP/QSE (Quality, Safety & Environment) Department
  5. ECP/ SVC (Services)
  6. ECP/CST (Construction)
  7. ECP/CMM (Commissioning)


2.8 ECP/CST (Construction)

The ECP/CST (Construction) department is the largest department under the Engineering Construction and Project (ECP) Division with personnel spreading at all Sites including CPU, NPU, SPU Handil/CPA, and SPS including Bekapai, and Balikpapan. The department has several missions, which includes managing the construction activities with the exception of the project activities led by project department or new project on surface facilities development, as well as to manage the dredging and diving/ROW to support construction activities. The department is supported by 5 services that include:

  1. ECP/CST/PWK
  2. ECP/CST/OPB
  3. ECP/CST/OPT
  4. ECP/CST/OFF
  5. ECP/CST/MTH

CHAPTER III ESDV BASIC INFORMATION

3.1 What is Emergency SDV or SDV (Shutdown Valve)

Shutdown valve (also known as SDV, ESV, ESD, or ESDV) is an actuated valve designed to stop the flow of a hazardous fluid upon the detection of a dangerous or unsufficient event. This provides protection against possible harm to people, equipment or the environment. Shutdown valves are primarily associated with the petroleum industry. ESDV are required by law on any equipment placed on an offshore drilling rig to prevent catastrophic events, moreover SDV has also been placed in the system cycle at process of production to stop the flowing gas in case of fire. Generally, ESDV consists of a valve and an actuated actuator. Shut down valve should be fail-safe, that is close upon failure of any element of the input control system (such as temperature controllers, steam pressure controllers), air pressure, fuel pressure, current from a flame detector, or current from other safety devices such as low water cutoff, and high pressure cutoff. ESDV must be able to function as called upon during an emergency and manage the situation. In the event that the set point is exceeded or power or signal are lost, the valve will close to isolate the flowing.


What distinguish SDV & ESDV:

  • Shutdown Valve (SDV): is an actuated valve, which is closed during partial or total process shutdown of system to which the valve protects.
  • Emergency Shutdown Valve (ESDV): is an actuated valve, which is closed when triggered by signal from ESD level signal during emergency condition occurs. It is commonly located in incoming line and outgoing line of the plant or platform.


How ESDV works:

The working principle of ESDV is quite simple and generally there are 2 main conditions of ESDV position, which are the following:

  • Full Opened Position (Normal Operation): In the normal process of production flows, the SDV will be in the normally opened state. The ESDV provides minimal pressure differential when the valve is in full open position. The ball valve virtually acts as a pipe, decreasing process fluid turbulence. The full opened position is shown in figure 3.1 below.
Figure 3.1 Full Opened Position.png


  • Full Closed Position (Emergency Situation): As set point pressure has been exceeded the ESDV will be fully closed, providing bubble-tight shutoff with its double-seated design. The full closed position is shown in figure 3.2 below.
Figure 3.2 Full Closed Position.png


3.2 Valves

A valve is a device that regulates, directs or controls the flow of a fluid (gases, liquids, or fluidized solids) by opening, closing, or partially obstructing various passageways. Valves are technically fittings, but are usually discussed as a separate category. In an open valve, fluid flows in a direction from higher pressure to lower pressure. The simplest, valve is simply a freely hinged flap which drops to obstruct fluid (gas or liquid) flow in one direction, but is pushed open by flow in the opposite direction. This is called a check valve, as it prevents or "checks" the flow in one direction only. Modern control valves may regulate pressure or flow downstream and operate on sophisticated automation systems. Valves have many uses, including controlling water for irrigation, industrial uses for controlling processes, residential uses such as on/off and pressure control to dish and clothes washers and taps in the home. In compressed air systems, the valves that are used with the most common type are ball valves. ESDV usually uses ball valve or butterfly valve.


3.2.1 Valve Types

Valves have lots of varities based on its function. The most common types of valves used for ESDVs can be ball valves and butterfly valves depending on the system requirements. Most popular valve that is used in PHM for SDV is commonly ball valve. Butterfly valves are used for regulating and can either be motoric by using actuator or manually operated.


3.2.1.1 Ball Valves

Ball valve is a type of piping equipment that shuts off or controls the flow in a pipeline by using a hollow sphere (rotary ball having a bore) and round seats held in a valve body. By rotating the ball a quarter turn (90 degrees) around its axis, the medium can flow through or blocked. Ball valves are used for straight fluid flow. Ball valves are characterized by a long service life and provide a reliable sealing over the life span, even when the valve is not in use for a long time. As a result, they are more popular as a shut-off valve than gate valve. Ball valves are also more resistant against contaminated media than most other types of valves.

Ball Valve Components:

The components of ball valve includes the valve body, ball, seats, stem, packing, bonnet, and operator or actuator. The components can be seen in figure 3.3 and the explanation of each components are as follow:

  • Valve Body: A pressure vessel that contains the components needed to control or shut off the flow through a pipe. It is designed to connect two or more sections of pipe or tubing to each other.
  • Ball: A sphere with a flow path (hole or tunnel) through the center of it and a connection point for a shaft to rotate it.
  • Seats: Round donut shaped discs that form a seal between the body and ball. Can be metal seated or soft seated.
  • Stem: A shaft that connects the internal ball to the outside of the valve to facilitate rotation of the ball.
  • Packing: Flexible seals that fit around the shaft and prevent the media travelling through the valve from escaping externally.
  • Bonnet: The part of the valve body that houses the stem and packing.
  • Operator or Actuator: An external device designed to rotate the stem of the valve. This can be a lever, a gear, a motor operated gear (Electric Actuator), or a pneumatic/hydraulic actuator.
Figure 3.3 Ball Valve Components.png


Ball Valve Design:

The design of ball valve can either be floating or trunnion based of the support on the ball valve. It can also be either reduced bore or full bore based on the system flow requirements and pigging requirements.


  • Floating

The most common design is the floating ball design. The ball is suspended in the media and held in place by two sealing rings. Floating ball valves don’t have extra anchoring system of the trunnion ball valves, and hence they ‘float’ connected only to the stem of the valve. The ball moves down slightly with the flow of the pipeline’s content until it reaches the opening, creating a seal and stopping the flow of liquid. Floating ball design is shown in figure 3.4 below.

Figure 3.4 Floating Ball Design.png


  • Trunnion

High-quality valves have a trunnion ball design. The ball is supported at the top and bottom to reduce the load on the valve seats. Trunnion valve has an extra anchoring system on the top and the bottom, which helps to relieve extra pressure and reduce friction to maintain the safe operation and lifetime of the ball valve. It is usually best and suitable for high-pressure and for large size valves. This design allows for reduction in valve torque as the ball is supported in two places, therefore the design requires a lower operating torque. Hence, reduces the size of the actuator and overall costs of the valve. Trunnion ball design can be seen in figure 3.5 below.

Figure 3.5 Trunnion Ball Design.png


  • Internal Bore of the Ball:

The internal bore of the ball can either be Reduced or Full bore, depending on the flow restriction needed by the system.

  • Reduced Bore (Standard Port)

Most ball valves have a reduced bore (reduced port). For reduced bore, the ball valve introduces friction losses in the system. These losses are still relatively small compared to other types of valves. Reduced bore valve has a straight flow path, and the flow path though the valve becomes narrower on the inside. Flow restriction produces pressure drop. One-piece ball valves are almost always reduced bore. Reduced bore design is shown in figure 3.6 below.

Figure 3.6 Reduced Bore.png


  • Full Bore

Full bore (full port) valves have the same bore internal diameter (ID) as the pipe internal diameter (ID). The advantage is that there are no extra friction losses and the system is mechanically easier to clean (pigging). Full bore valve has a straight flow path, and the flow path through the valve does not become narrower on the inside. Full bore valve offers little to no resistance to flow. The downside is that the ball and the housing are bigger than a standard ball valve with reduced bore. The cost is therefore slightly higher, and for many applications this is not required. Full bore design can be seen in figure 3.7 below.

Figure 3.7 Full Bore.png


  • Fail Position:

In the event of power loss, a valve will “fail” or stop in one of three positions, whether it is opened, closed, or in place. Power refers to the means by which the actuator is moved, whether by air pressure, gas pressure, or electric power. Air or gas pressure may be lost due to freezing, and electricity may be lost during a seasonal thunderstorm. It is important to carefully consider which fail action must be selected for the valves, as this will affect local equipment and production significantly. ESDV Valve failure can either be in Fail Close (FC) or Fail Open (FO) position explained as follow:

  • Fail Close (FC)

Fail close means that when the signal is interrupted or lost, the valve will close. Since air instrument pressure is needed to keep the valve open, it would automatically close when power is lost because there would no longer be a functioning air source. This is typically chosen in the case of a steam injection well where uncontrolled steam is extremely dangerous, so the valve closing automatically would be the best option to maintain control. This may also referred to as “spring to close” or “air to open.”

  • Fail Open (FO)

Fail open means that when there is a loss of signal or power, the valve opens. These types of valves require air instrument pressure to stay closed. Once the required air pressure is gone, the valve will naturally open. This is typically chosen to prevent overpressure in the event of a blocked line or in case of catastrophic failure. This may also be referred to as “spring to open” or “air to close.”


3.2.1.2 Butterfly Valve

Butterfly valve is a pressure vessel that controls flow through a pipe by use of a single disc mounted on a central shaft that creates a variable orifice. Butterfly valves are among the family of quarter-turn valves and work very similar to ball valves. The “butterfly” is a disk connected to a rod. It closes when the rod rotates the disc by a quarter turn to a position perpendicular to the flow direction. When the butterfly valve is fully closed, the disk completely blocks the flow. When the valve opens, the disk is rotated back to allow the flow. The working principle of butterfly valve can be seen in figure 3.8 below. Butterfly valves are used for on-off or modulating services and are popular due to their light-weight, small installation footprint, lower costs, quick operation and availability in very large sizes Butterfly Valve Components:

Figure 3.8 Working Principle of Butterfly Valve.png


The components of butterfly valve includes the valve body, disk, stem, and seat. The components can be seen in figure 3.9 and the explanation of each components are as follow:

  • Body: Butterfly valves generally have bodies that fit between two pipe flanges. The most common body designs are lug and wafer.
  • Disk: The disk is used to stops flow. It is equivalent to a ball in a ball valve. There are variations in disk design and orientation in order to improve flow, sealing and/or operating torque.
  • Stem: The stem of the butterfly valve may be a one-piece shaft or a two-piece (split-stem) design. The stem in most resilient seated designs is protected from the media, thus allowing an efficient selection of material with respect to cost and mechanical properties.
  • Seat (sealing): The seat of a resilient-seat butterfly valve utilizes an interference fit between the disk edge and the seat to provide shutoff. The material of the seat can be made from many different elastomers or polymers. The seat may be bonded to the body or it may be pressed or locked in.
Figure 3.9 Butterfly Valve Components.png


Butterfly Valve Types:

The design of ball valve can either be concentric or eccentric based on the disc closure design. It can also be either wafer or lug type based on the connection design.


  • Disc Closure Design

Butterfly valves can be concentric or eccentric depending on the location of the stem in relation to the disc and the seat surface angle on which the disc closes.


  • Concentric

The most basic type of butterfly valve design is concentric butterfly valve. For this design the stem passes through the centerline of the disc which is in the center of the pipe bore and the seat is the inside diameter periphery of the valve body. The concentric design can be seen on figure 3.10 below. Concentric butterfly valves are commonly used for low-pressure ranges. This design is also called resilient-seated because it relies on the flexibility of the seat rubber to efficiently seal the flow when closed. In this type of valve, the disc first comes into contact with the seat at around 85° during a 90° rotation.

Figure 3.10 Concentric Disc.png


  • Eccentric

For the eccentric butterfly valve design the stem does not pass through the centerline of the disc, but instead behind it (opposite of flow direction). If the stem is located right behind the centerline of the disc, the valve is called single-offset. This design was developed to reduce the disc contact with the seal before full closure of the valve with the aim of improving service life of the valve. The eccentric design can be seen on figure 3.11 below.

Figure 3.11 Eccentric Disc.png


  • Connection Design

Butterfly valves can be connected to a piping system in different ways. The most common methods are wafer type and lug type.


  • Wafer-type

Wafer-type butterfly valve is the most economical version and it is sandwiched between two pipe flanges. The wafer body is placed between pipe flanges, and the flange bolts surround the valve body. This type of connection is designed for sealing against bi-directional differential pressures and to prevent backflow in systems designed for universal flow. It accomplishes this with a tightly fitting seal (gasket, o-ring, precision machined, and a flat valve face) on both sides of the valve. Wafer-type connection can be seen in figure 3.12 below.

Figure 3.12 Waffer Type Connection.png


  • Lug-type

Lug-type butterfly valve has threaded inserts (lugs) in the periphery of the valve body that provides passage to bolt holes that match with those in the flanges. Two sets of bolts connect pipe flanges to each side of the bolt inserts without nuts. This design enables the disconnection of one side without affecting the other for dead-end service. Lug-style butterfly valves used in dead-end service generally have a lower pressure rating. The lug-style butterfly valves, unlike the wafer-style, carry the weight of the piping through the valve body. Lug-type connection can be seen on figure 3.13 below.

Figure 3.13 Lug Type Connection.png


3.3 Actuators

An actuator is a component of a machine that is responsible for moving and controlling a mechanism or system, for example by opening a valve. There are many valve actuators available, but there are things that should be considered to decide which one is suitable for the shutdown valve and also for the preparation of the process system. As the function of SDV is for emergency needs, the actuator must be able to close the valve quickly based on the standardized timing (i.e. 3 seconds). Often used actuator type is single acting spring return. ESDV generally uses an actuated actuator instead of manual actuator.


3.3.1 Actuated Actuator Types

There are several varieties of types of actuator available based on its function needed by the system. Actuators are divided based on the medium or fluid used in the actuator. It can either be pneumatic, hydraulic, and electrical. The types and explanation of actuators are as follow:


3.3.1.1 Pneumatic Actuators

Pneumatic actuators utilize compressed air to generate the operating energy. These actuators are quick and accurate to respond, but are not ideal for environments under high pressures, as gas is compressible. The actuators can either be spring return or double acting. Typical pneumatic actuators can be seen on figure 3.14 below.

Figure 3.14 Typical Pneumatic Actuator.png


  • Spring Return

Actuators in a spring return configuration have air/liquid supplied to only one side of the piston, and the energy to move the mechanisms comes from a spring on the opposite side. This configuration uses the air/liquid as energy to open or close the valve, while the spring acts to affect the opposite motion. These cylinders have only one compressed air connection. The incoming compressed air moves the piston in one direction, and the cylinder force is built up in this direction. If the piston needs to return to its initial position, the air is simply expelled from the cylinder. The mechanical spring pushes the piston back to its initial position. This part has a ventilation/exhaust hole so that no excess is generated through the piston movement in the second cylinder chamber. Spring return actuator can be seen on figure 3.15 below.

Figure 3.15 Spring Return Actuator.png


Advantages of Spring Return:

  • Simple design
  • Compact size
  • Reduction in valve and piping costs
  • Air consumption is halved compared with the equivalent sized double acting cylinder.


Disadvantages of Spring Return:

  • Return spring side of the cylinder is vented to atmosphere, which may allow the ingress of foreign matter that leads to malfunctioning and reducing the life of the cylinder.
  • Spring operation with extended cylinder life can become inconsistent and provide uncertain end of stroke positions.
  • Bore size and stroke of the cylinder is restricted due to limitations of the spring size and force.
  • A slight reduction of thrust due to the opposing spring force.


Spring to Close or Open:

In the event of power loss, an actuator will “fail” or stop in one of two positions, whether it is opened or closed. ESDV spring return actuators can either be in Spring to Close or Spring to Open condition explained as follow:

  • Spring to Close (Ex: Neles B1J)

“Spring to close” or “air to open” indicates Fail Close (FC). Fail close means that when the signal is interrupted or lost, the actuator will cause the valve to close. Since air pressure is needed to keep the valve open, it would automatically close when power is lost because there would no longer be a functioning air source. This is typically chosen in the case of a steam injection well where uncontrolled steam is extremely dangerous, so the valve closing automatically would be the best option to maintain control. The example of Spring to Close spring return actuator is the Neles B1J actuator as seen on figure 3.16 below.

Figure 3.16 Spring to Close Actuator.png


  • Spring to Open (ex: Neles B1JA)

“Spring to open” or “air to close” indicates Fail Open (FO). Fail open means that when there is a loss of signal or power, the actuator causes the valve to open. These types of actuators require air pressure in order for the valve to stay closed. Once the required air pressure is gone, the valve will naturally open. This is typically chosen to prevent overpressure in the event of a blocked line or in case of catastrophic failure. The example of Spring to Open spring return actuator is the Neles B1JA actuator as seen on figure 3.17 below.

Figure 3.17 Spring to Open Actuator.png


  • Double Acting

Actuators in a double acting configuration have air/liquid supplied to both sides of the piston with one side being higher pressure, which achieves the movement required to actuate the valve. This configuration uses the air/liquid as energy to both open and close the valve. Example of double acting actuator can be seen on figure 3.18 below.

Figure 3.18 Double Acting Actuator.png


Advantages of Double Acting:

  • ISO standards are generally based on the design of double acting cylinders.
  • A more extensive range of double acting cylinders compare to single acting cylinders, giving many more options of bore and stroke sizes.

Disadvantages of Double Acting:

  • Cannot be simply held in a mid-position,
  • Air is a compressible medium – if a pneumatic cylinder is to be used as a feed cylinder, it has to be coupled to a hydraulic slave cylinder to give a constant feed.
  • Long stroke cylinders need adequate guiding of the piston rod.


  • Double Acting (ex: Neles B1C)

This actuator configuration uses air pressure to control both the opening and closing of the valve. The example of Double Acting actuator is the Neles B1C actuator as seen on figure 3.19 below.

Figure 3.19 Neles B1C Double Acting Actuator.png


3.3.1.2 Hydraulic Actuators

Hydraulic actuators use liquid as a means to apply pressure to the actuators mechanical components. They generally can exert a large amount of force because liquid is not compressible, but are generally limited in acceleration and speed. Unlike pneumatic actuators that are for quick and accurate response, hydraulic actuators are used when a large amount of force is required to operate a valve. Hydraulic actuators can also be either spring return or double acting as seen on figure 3.21. The cylinder is separated into two chambers. The top chamber contains the spring and the lower chamber contains the hydraulic fluid. When there is no hydraulic fluid pressure, the spring force holds the valve in the closed position. When fluid enters the lower chamber, pressure in the chamber increases and moves the piston up the stem and against the force caused by the spring. As the piston moves upwards and compresses the spring, the valve opens. The valve is closed when the hydraulic fluid is drained from the lower chamber. The components of Hydraulic Actuator can be seem on figue 3.20 below.

Figure 3.20 & 3.21.png


3.3.1.3 Electric Actuators

Electric actuator uses an electric motor to provide torque to operate a valve. They are quiet, non-toxic and energy efficient. However, electricity must be available, which is not always the case. Electric actuators can also operate on batteries as a power source. They usually include intricate electrical circuitry to program when the actuator operates. Because of their use of electricity as a power source, however, they may not be the best actuator for remote installations.

CHAPTER IV WELL CONNECTION & ESDV UTILIZATION

4.1 Oil and Gas Industry Sectors

Figure 4.1 Oil & Gas Sectors.png


The oil and gas industry comprises of three sectors namely the upstream, midstream, and downstream. Upstream sector deals with the oil & gas exploration and production at offshore and onshore. Midstream sector deals with gathering, transport and storage of processed crude oil products. Downstream sector deals with product preparation and usage, which includes the distribution and marketing of products. The upstream sector is also known as the E&P (Exploration and Production) sector. It is consisted of processes and operations that involve searching for potential underground or underwater crude oil and natural gas fields, drilling of exploratory wells, and subsequently drilling and operating the wells that recover and bring the crude oil and/or raw natural gas to the surface. In this case, Pertamina Hulu Mahakam only takes part in upstream of oil and gas industry. The midstream sector is usually combined in the literature with the downstream sector. This segment in the supply chain, involves the transportation, storage and marketing of various oil and gas products. Transportation options can vary from small connector pipelines to massive cargo ships making trans-ocean crossings, depending on the commodity and distance covered. When it comes to the downstream sector, it encompasses the refining, processing, distillation and purification before turning it into usable, sell-able and consumable products (i.e. fuels, raw chemicals and finished products, etc.). All the afore-mentioned services transform crude oil into usable products such as gasoline, fuel oils, and petroleum-based products. Retail marketing activities help move the finished products from energy companies to retailers.


4.2 Upstream Activities

PT Pertamina Hulu Mahakam only takes part in the upstream sector of oil and gas industry. Upstream activities that include exploration and production encompass several areas, starting from the wellhead until the storage and export. The upstream process sections are explained as follow:


  • Wellheads

The wellhead sits on top of the actual oil or gas well leading down to the reservoir. A wellhead may also be an injection well, used to inject water or gas back into the reservoir to maintain pressure and levels to maximize production. Once a natural gas or oil well is drilled and it has been verified that commercially viable quantities of natural gas are present for extraction, the well must be “completed” to allow petroleum or natural gas to flow out of the formation and up to the surface. This process includes strengthening the well hole with casing, evaluating the pressure and temperature of the formation, and installing the proper equipment to ensure an efficient flow of natural gas from the well. The well flow is controlled with a choke. We differentiate between, dry completion (which is either onshore or on the deck of an offshore structure) and subsea completions below the surface. The wellhead structure, often called a Christmas tree, must allow for a number of operations relating to production and well workover. Well workover refers to various technologies for maintaining the well and improving its production capacity.


  • Manifolds and Gathering
  • Onshore

The individual
well streams are brought
into the main production facilities over a network of gathering pipelines and manifold systems. The purpose of these pipelines
is to allow setup of production "well sets" so
that for a given production level, the best reservoir utilization well flow composition (gas, oil, water), etc., can be selected from the available wells. For gas gathering systems, it is common to meter the individual gathering lines into the manifold as shown in this picture. For multiphase flows (combination of gas, oil and water), the high cost of multiphase flow meters often leads to the use of software flow rate estimators that use well test data to calculate actual flow.

  • Offshore

The dry completion wells on the main field center feed directly into production manifolds, while outlying wellhead towers and subsea installations feed via multiphase pipelines back to the production risers. Risers are a system that allows a pipeline to "rise" up to the topside structure. For floating structures, this involves a way to take up weight and movement. For heavy crude and in Arctic areas, diluents and heating may be needed to reduce viscosity and allow flow.


  • Separation

Some wells have pure gas production, which can be taken directly for gas treatment and/or compression. More often, the well produces a combination of gas, oil and water, with various contaminants that must be separated and processed. The production separators come in many forms and designs, with the classic variant being the gravity separator. In gravity separation, the well flow is fed into a horizontal vessel. The retention period is typically five minutes, allowing gas to bubble out, water to settle at the bottom and oil to be taken out in the middle. The pressure is often reduced in several stages (high pressure separator, low pressure separator, etc.) to allow controlled separation of volatile components. A sudden pressure reduction might allow flash vaporization leading to instability and safety hazards.


  • Metering, Storage and Export

Most plants do not allow
local gas storage, but oil
is often stored before
loading on a vessel, such
as a shuttle tanker taking
oil to a larger tanker
terminal, or direct to a
crude carrier. Metering stations allow operators to monitor and manage the natural gas and oil exported from the production installation. These employ specialized meters to measure the natural gas or oil as it flows through the pipeline, without impeding its movement. This metered volume represents a transfer of ownership from a producer
to a customer (or another
division within the company), and is called
custody transfer metering. It forms the basis for
invoicing the sold product
and also for production
taxes and revenue sharing
between partners. Accuracy requirements are
often set by governmental authorities. Typically, a metering installation consists of a number of meter runs so that one meter will not have to handle the full capacity range, and associated prover loops so that the meter accuracy can be tested and calibrated at regular intervals.


4.3 Well Connection

Well connection is the activity to connect new wells to existing adjacent well or GTS (Gathering Testing Satellite). This includes the construction and installation of new pipelines to connect new remote well to existing GTS. Well connection is determined by the well configuration. The well configuration can be classified into two different parameters including its location and well slot availability.


4.3.1 Location

The well can be classified based on its location. The location of the well can be further divided into two types, which are adjacent and remote well. Adjacent well are the ones that are located near the GTS (Gathering Testing Satellite) and connected to the existing facilities, while for the remote well it is located far from the GTS and connected through pipelines equipped with emergency shutdown valve (ESDV). Remote well can be further classified into remote adjacent well, which are wells that are located near and connected to the existing remote well.


4.3.2 Well Slot Availability

The wells can be classified based on the well-slot availability on the available platform. The platforms are further divided into four types based on the available slots, which includes bi-slot, quadri-slot, 3rd CP (third conductor pipe) on bi-slot platform, and free slot.

  • Bi-slot

For Bi-slot platforms there are 2 available well slots on the platform. Bi-slot platforms can either be Bi-slot - Adjacent or Bi-slot - Remote. Bi-slot - Adjacent are connected to the existing facilities located near the GTS. While the Bi-slot - Remote are connected to the GTS by means of Pipeline. Typical Bi-slot - Adjacent Well connection diagram can be seen on figure 4.2, while the Bi-slot - Remote Well connection diagram can be seen on figure 4.3.

Figure 4.2 Bi Slot - Adjacent.png
Bi Slot - Remote.png


  • Quadri-slot

For Quadri-slot platforms there are 4 available well slots on the platform. Quadri-slot platforms can either be Quadri-slot - Adjacent or Quadri-slot - Remote. Quadri-slot - Adjacent are connected to the existing facilities located near the GTS. While the Quadri-slot - Remote are connected to the GTS by means of Pipeline. Typical Quadri-slot - Adjacent Well connection diagram can be seen on figure 4.4, while the Quadri-slot - Remote Well connection diagram can be seen on figure 4.5.

Figure 4.4 & 4.5 Well conn.png


  • 3rd CP (Third Conductor Pile)

For 3rd CP platform (Third Conductor Pile), modification on the existing platform is initiated. Initially the platform is Bi-slot where there are only 2 available well slots. 3rd CP platform modify and adds an extension on the existing wellhead platform to make the 3rd slot. Typical 3rd CP Well connection diagram can be seen on figure 4.6.

Figure 4.6 3rd CP.png


  • Free Slot

For Free slot platform, minor modification on the existing platform is initiated. The minor modification is conducted by adding a new flow line of the new well to the flow line of the existing well. Typical Free slot Well connection diagram can be seen on figure 4.7.

Figure 4.7 Free Slot.png


4.3.3 Well Connection Sequence

The overall well connection sequence implemented by ECP includes fabrication, platform construction, pipe laying, tie in, pre commissioning and commissioning. Explanation of each Sequence is as follow:


  • Fabrication

Fabrication sequence includes the welding of double joint pipeline and fabrication of the wellhead platform at the fabrication yard. The pipeline double joint is fabricated by fitting up 2 pipes and weld them together as seen on figure 4.8. The welder has to make sure that during the welding process both pipes are inline with each other through the implementation of NDT (radiography test). The double joint pipeline will then be coated as means of protection from corrosion. The double joint pipeline length used is 24 m, with each pipes having length of 12 m. Wellhead platform fabrication includes the cutting process of material and welding to construct the structure. The structure is then sandblasted to remove excess paint and dirt from the surface of the material. Finally it is then coated with paint as means of protection against corrosion.

Figure 4.8 fit up & welding.png


  • Platform Installation

Installation of platform includes template positioning and piling. Use of template is used to ease the installation of the platform leg to be inline. Template positioning can be seen on figure 4.9. Piling is the process of installing the conductor pile used for the drilling process. Piling process can be seen on figure 4.10

Figure 4.9 & 4.10.png


  • Pipelaying & Trenching

Pipelaying is the process of laying pipeline under the seabed. Pipelines are used to transport and distribute oil and gas from one facility to another facility. Pipelines for well connections are generally used to connect a remote well with the GTS (Gathering Testing Satellite), since remote wells are far away from the GTS. Before pipelaying can be initiated, the pipeline route must be excavated beforehand. This process of excavation for pipeline route is called trenching and the trench must be done several meters (2 m) below the seabed through the use of crane barge. Trenching process can be seen on figure 4.11. As the pipeline trench is available the pipelaying can be performed through the use of pipelaying barge stinger. The pipelaying process can be seen on figure 4.12. Inside the barge, welding stations are available to weld the double joint pipeline before pipelaying activities. Radiography is performed to know whether internal cracks are present within the pipeline. Coating and Cathodic protection is performed to prevent corrosion of the pipeline. The end process of pipelaying is back filling to recover the pipeline under the trench.

Figure 4.11 & 4.12.png


  • Tie in

Tie in is the sequence of connecting the new pipeline to the existing platform or GTS. Tie in includes the lifting of pipeline, installation of the dogleg, installation of riser, installation of aerial pipe and installation of the flowline. The lifting process and the welding of the pipeline to the dogleg can be seen on figure 4.13. The flowline installation can be seen on figure 4.15.

Figure 4.13-4.15.png


  • Pre-commissioning and commissioning

Pre-commissioning included the hydro test of each individual instrumentation, piping, and pipeline to determine whether leaks are present. As for commissioning is the Gas (N2) test of the whole system after pre-commissioning activities has been done.


4.4 Utilization of ESDV in PHM Well Connection

Emergency shutdown valve (ESDV) is used as a part of safety instrument system (SIS) for well connection. Safety instrumented system is used for the process of providing automated safety protection upon the detection of a hazardous or insufficient conditions. This hazardous and insufficient conditions includes fire hazard and high/low pressure conditions. In the case of well connection, ESDV are used to stop the flow of fluid in the flow line from the well platform before reaching the pipeline that connects to another platform or GTS. To further explain the use of ESDV in well connection, one example of ESDV utilization as part of safety instrumentation system is taken from the Tunu Remote Well of Pertamina Hulu Mahakam.


4.4.1 Tunu Remote Well Safety Instrumented System

The inner working of ESDV in well connection is correlated to the working of other instrumentation as part of the system. This indicates that it is required to have an understanding on the function of other instrumentation at the Tunu well that correlates to the ESDV. The main purposes of the instrumentation provided at the Tunu Remote well are generally for monitoring and as a safety system. The monitoring function includes pressure, temperature, flow, and corrosion monitoring and data collecting. The safety system covers protection from abnormal or insufficient condition such as fire, high or low pressure, and high sand rate detection. The simple diagram of the Tunu Remote Well Instrumentation working principle can be seen on figure 4.16 below.

Figure 4.16 Tunu Well Instrumentation.png


Based on figure 4.16, the instrumentation can be classified based on its use, namely for monitoring or safety system. The explanation of each instrumentations at the Tunu Remote Well are as follow:


4.4.1.1 Safety System Instrumentation
  • Sand Probe

The Sand Probe is a sacrificial tube inserted into the flow and can be used as an early warning (safety) device for alerting the operator that a critical metal loss (erosion) has occurred due to the effects of sand or solids erosion in the flow. Sand probe are located near the wellhead and acts as the first barrier to prevent catastrophic event, it is also located at elbows where collision from pressure happens. As the inserted tube is crushed over time, the pressure within will increase causing it to send safety signal to the WHCP so that the control panel may regulate the ESDV. Sand probe can be seen on figure 4.17.

Figure 4.17 Sand Probe.png


  • Fusible Plug

Fusible Plugs are used to detect fire by sensing heat. To make a complete heat detection system, fusible plug is installed along with pressurized tubing and a panel. Tubing will be pressurized by instrument air or nitrogen with constant pressure from the panel. At the end of each tubing the fusible plug is located on the area where fire can possibly happen. It will melt at certain temperature during fire subsequently release the pressure within the tubing. If the pressure falls below its set point, it will generate signal to the WHCP and the panel will execute pre-determined action such as activating the fire alarm and closing the ESDV. Fusible plug can be seen on figure 4.18.

Figure 4.18 Fusible Plug.png


  • Pressure Switch

The function of pressure switch is divided into PSHH and PSLL. PSHH is used to detect abnormal condition and primary protection due to overpressure on the wellhead flow line. PSLL is used to detect abnormal condition and primary protection from leak due to low pressure and backflow. The pressure switch sends safety signal to the WHCP so that the control panel may regulate the ESDV. PSHH and PSLL can be seen on figure 4.19.

Figure 4.19 PSHH & PSLL.png


  • Emergency Shut Down Valve (ESDV)

The emergency shut down valve (ESDV) acts as the final barrier to prevent catastrophic event by stopping the flow of fluid in the flow line into the pipeline that connects other well. The ESDV is activated and regulated by the Well Head Control Panel (WHCP) that receives safety signal from the above instrumentation explained beforehand. The ESDV itself is interconnected between the flowline from the well and aerial pipe to the pipeline. Figure 4.20 shows the location point where the ESDV will be interconnected.

Figure 4.20 ESDV connection point.png


4.4.1.2 Monitoring Instrumentation
  • Flow Pressure Temperature Recorder (FPTR)

FPTR is used to measure and record differential pressure, pressure, temperature and flow meter pulses. The device can scale and calculate flow as well as indicate and record data, which can be downloaded to a user’s PC via a USB connection. Alternatively, the integral keypad can be used to configure basic parameters and access historical data. The recorded data is taken from the Orifice Flange and Thermowell. FPTR can be seen on figure 4.21.

Figure 4.21 FPTR.png


  • Orifice Flange

Orifice Flanges are used with orifice meters for the purpose of measuring the flow rate of the fluid. Pairs of pressure tapings mostly on 2 sides directly opposite each other are machined into the orifice flange. The flow rate of the fluid is recorded based on the differential pressure. The orifice flange can be seen on figure 4.22.

Figure 4.22 Orifice Flange.png


  • Thermowell

Thermowell acts as a barrier between a process medium and the sensing element of a temperature measurement device. It protects against corrosive process media, as well as media contained under pressure or flowing at a high velocity. A thermowell also allows the sensing element to be removed from the application while maintaining a closed system.

  • Pressure Monitor (Pressure Gauge)

A pressure gauge is a measurement device, which determines the pressure in a compressed gas or liquid. It is used to show the pressure of the fluid by visual contact.

  • Corrosion Coupon

Corrosion coupon is used to monitor the corrosion rate of a material in a process. Generally, a corrosion coupon is inserted into the process and is held in place by a holder so the corrosivity of the process can be monitored. The test coupon might be the same material as the pipe. The corrosion coupon can be seen on figure 4.23.

Figure 4.23 Corrosion Coupon.png


4.4.1.3 Well Head Control Panel (WHCP)

The main purpose of the wellhead control panel is to ensure controlled opening and closing of the ESDV and Christmas tree valves in the event of an emergency shutdown or process shutdown from the signal sent by the field safety instrumentation devices. The WHCP can be seen on figure 4.24. The Christmas tree valves include the master valve, wing valve, choke valve, and manual wing valve. The valves can be seen on figure 4.25.

Figure 4.24 & 4.25 WHCP & Xmas Tree Valve.png


4.4.2 ESDV Activation

This part will discuss the ESD Logic and inner working principles of ESDV that are important to understand the activation of ESDV at the Pertamina Hulu Mahakam Tunu Well Connection.


4.4.2.1 ESD Logic

The activation of the ESDV, in this case the closing of the ball valve since it is Fail Closed (FO) depends on the ESD (emergency shutdown) logic of the safety instrumentation system. An example of ESD logic is taken from the Tunu TN-W32rc New Remote Well Connection. The TN-W32rc safety level of shut down is divided into ESD.1, SD 2, and SD 3 and it can be seen on figure 4.26. ESD.1 level mainly consist of safety signals from Push Buttons that are used manually by the worker during fire condition. Wellhead ESD push button is available at the wellhead to directly shutdown the DHSV, ESDV, master valve, wing valve and instrument gas by the press of a button. Rig and Boat Landing push button is also already available but are only used during emergency conditions when the Rig is inserted to directly shutdown the ESDV and valves. DHSV (Down Hole Safety Valve) is used to protect from the reservoir, by isolating reservoir fluid from the surface when it is closed. Master valve is used to protect the Christmas tree by controlling all flow from well bore. Wing valve is used to protect out of the Christmas tree before entering the flowline by isolating production from well to surface facilities. ESDV is used to protect the flowline until before entering the pipeline by isolating them when closed. ESD.1 level is used during fire conditions therefore it closes everything to isolate gas from entering and leaving into the pipeline. SD 2 level consist of only the Instrument Gas from the GTS. This gas is instrumented from the GTS to the WHCP through the use of 2” pipe sitting at the top of the pipeline. The instrumentation available is only the pressure switch (PSLL only). It is only used to indicate low pressure at the 2” pipe, which indicates leak. Low-pressure signal from the pressure switch will trigger the ESDV and Christmas tree valves to close. SD 2 level closes the instrument gas which in turn close the master valve, wing valve and ESDV. SD 3 level consist of the safety system instrumentations available at the flowline namely consisting of sand probe and pressure switch (PSHH & PSLL). Safety signals are triggered to the WHCP to close the ESDV and Christmas tree valves when one of the emergency conditions happen. Safety signal from the sand probe triggers when there is a detection of high sand quantity based on the safety limits prescribed by the company. Safety signal from the pressure switch is triggered when there is a detection of either high pressure (PSHH) or low pressure (PSLL). The maximum pressure prescribed by the company is 65 barg and the minimum pressure prescribed by the company is 3 barg, therefore if the pressure is higher or lower than the prescribed value the signal will trigger the WHCP. SD 3 level only close the flowline consisting of master valve, wing valve and ESDV; therefore instrument gas is still running and it does not inhibit the working process of other well.

Figure 4.26 ESD Logic.png


4.4.2.2 ESDV Inner Workings

The working principle of ESDV depends on the other safety instrumentations, wellhead control panel (WHCP), and the ESDV Control Panel itself. The instrumentation includes the sand probe and pressure switch that sends signals during emergency or insufficient situations to the WHCP. The WHCP gather the signal from the safety instruments and further distribute it to the ESDV Control Panel. The ESDV Control Panel plays an important role in actuating and controlling the ESDV for emergency conditions. Inside the ESDV Control Panel consists of several pilot valves. This pilot valves are used to regulate the flow of air from the inlet that may enter the pneumatic actuator. Pilot valves may regulate the flow of air based on the signal received by the ESDV control panel from the WHCP. During normal conditions the pilot valve will open and let the air flow into the pneumatic actuator. Since air pressure is available at the actuator chamber the piston shaft will be pushed by the compressed air to keep the Ball Valve open. During emergency conditions, emergency signal from the WHCP will be received by the pilot valve to close itself and prevents the flow of air to reach the pneumatic actuator chamber. Since no additional air pressure is generated at the chamber, the remaining air will leave and the piston will return to its initial position through the help of the spring. The ESDV used by PHM Tunu Well Connection is Fail Close (FC), which means during emergency (failure) the ESDV will close. The inner workings of the ESDV can be seen on figure 4.27.

Figure 4.27 ESDV Working Schematics.png

CHAPTER V STUDY CASE

This section will discuss the reutilization of ex-used ESDV at PHM. One of the problems that are faced by Pertamina Hulu Mahakam at the moment is the shortage of ESDV due to no procurement process during the transition period from TEPI (Total E&P Indonesie) to Pertamina Hulu Mahakam. The transition had an impact on the delay of putting Pre Order for new well connection ESDV. As a solution to this problem, it was decided to reutilize ex-used ESDV from past well. The reutilization of ex-used ESDV encompasses the modification, minor repair, and major repair of ESDV.


5.1 Valve Coupling Modification

8” ball valve with 2500 pressure class will be reused for future use in PHM well connection. The reused ball valve will be mounted to the actuator from TN-B72 well. However, some problems were found before the testing process where the coupling part was missing during the dismantling process from the existing well. The actuator to be reused with the valve will be pneumatic spring return type actuator VALVITALIA LPS-16-430-CM23-FO with supply pressure rating of 7 barg and produces maximum torque of 15953 Nm (assumptions using LPS-16-430-CM29 maximum torque). Fabrication of the coupling part should be in accordance with the actuator torque. Therefore, the new design of the valve coupling must be able to withstand the amount of torque produced by the actuator. The modification section will cover only the Maximum Allowable Torque for the coupling, and the design of part other than coupling is not included. The coupling is designed to be sufficient enough to withstand the actuator torque. During valve operation, torque delivered by the pneumatic actuator at any stage, should not exceed the Maximum Allowable Torque value of the coupling. If it happens the coupling may be subjected to mechanical failure. The maximum allowable torque is calculated for the top coupling connection (coupling to actuator yoke) and bottom coupling connection (coupling to stem).


The proposed material for the coupling is AISI 4340

This material has yield strength of 840 MPa


5.1.1 Coupling Geometry

Coupling geometry is divided into Top and Bottom Coupling geometry as follow:


5.1.1.1 Top Coupling Geometry
Figure 5.1 Top Coupling Geometry.png


Given:

a = (32 mm)/2 = 16 mm

b = 120.1 mm – 107.5 mm = 12.6 mm

r = (120.1 mm)/2 = 60.05 mm

a/b = (16 mm)/(12.6 mm) = 1.269

b/r = (12.6 mm)/(60.05 mm) = 0.208


Width of Keyway = 32 mm

Length of Keyway = 230 mm


5.1.1.2 Bottom Coupling Geometry
Figure 5.2 Bottom Coupling Geometry.png


Given:

w = 20.2 mm

L = 85 mm

di = 69.9 mm

do = 120.1 mm

ri = (69.9 mm)/2 = 34.95 mm

ro = (120.1 mm)/2 = 60.05 mm

a = (20.2 mm)/2 = 10.1 mm

b = (85 mm-69.9 mm)/2 = 7.55 mm

a/b = (10.1 mm)/(7.55 mm) = 1.338

b/r = (7.55 mm)/(34.95 mm) = 0.216


5.1.2 Calculation of Top Coupling Connection (Coupling to Actuator Yoke)

The upper part of coupling is connected to actuator yoke, so the following equations are based on the upper part of coupling’s shape and size.


  • Method 1 Calculation using Roark’s Formula
Figure 5.3 Roark.png


Based on Roark’s formulas for torsional deformation and stress, the calculation used formula based on figure 5.3 in accordance with the top coupling geometry.


K1 = 1.169 -0.3168(a/b) + 0.049(a/b)2

K1 = 1.169 -0.3168(1.269) + 0.049 (1.269)2

K1 = 0.84589


K2 = 0.4349 -1.5096(a/b) + 0.8677(a/b)2

K2 = 0.4349 -1.5096(1.269) + 0.8677(1.269)2

K2 = -0.08347


K3 = -1.183 + 4.2764(a/b) -1.7024 (a/b)2

K3 = -1.183 + 4.2764(1.269) -1.7024 (1.269)2

K3 = 1.50291


K4 = 0.8812 -0.2627(a/b) -0.1897(a/b)2

K4 = 0.8812 -0.2627(1.267) -0.1897(1.267)2

K4 = 0.24384


Hence B is,

B = K1 + K2(b/r) + K3(b/r)2 + K4(b/r)3

B = 0.84589 -0.08347(0.208) + 1.50291(0.208)2 + 0.24384(0.208)3

B = 0.8957


To calculate top coupling torque, the allowable shear stress (τ) of the top coupling is needed which is τ = 1/2 γs based on Tresca’s yield criterion.

τ= (T.B)/r3 with, τ= 1/2 γs thus,

1/2 γs = (T.B)/r3

T = (γs . r3)/(2.B)


Therefore the top coupling torque (T) is,

T = (840 MPa (60.05 × 10-3 m)3)/(2 × 0.8957)

T = 101537.33 Nm


  • Method 2 Calculation using the Robert I. Isakower’s Chart

For the calculation using the Robert I. Isakower’s Chart the top coupling shear stress is τ = T (f/r3 ) and f is known as the stress factor. However, b/r and a/b is first needed to find f. The value of b/r used is 0.208 and a/b is 1.269 based on the top coupling geometry. Therefore, the stress factor (f) can be obtained from Figure 5.4 below.

Figure 5.4 Isakower.png


To calculate top coupling torque, the allowable shear stress (τ) of the top coupling is needed which is τ = 1/2 γs based on Tresca’s yield criterion.


τ = T(f/r3 ) with, τ = 1/2 γs thus,

1/2 γs = (T.f)/r3

T = (γs . r3)/(2.f)


Therefore the top coupling torque (T) is,


T = (840 MPa (60.05 × 10-3 m)3)/(2 × 0.9)

T = 101052.21 Nm


  • Maximum Allowable Torque (Coupling to Actuator Yoke)

Based on the calculation using the Roark’s formula and Robert I. Isakower’s Chart the maximum allowable torque at the top coupling can be determined. The lowest value is chosen for safety reasons, therefore the coupling section connected to the actuator yoke can withstand until:

T = 101052.21 Nm


5.1.3 Calculation of Bottom Coupling Connection (Coupling to Valve Stem)

Calculation of Coupling that connects to valve stem used the approach method. This method use calculation of torsional stress on shaft with circular section reduced (subtracted) by the calculation of stress on shaft with 2 splines. The bottom part of coupling is connected to valve stem, so the following equations are based on the bottom part of coupling’s shape and size.


5.1.3.1 Calculation of Shaft with Circular Section
  • Method 1 Calculation using Roark’s Formula
Figure 5.5 Roark.png


Based on Roark’s formulas for shear stress of solid circular section, the calculation used formula based on figure 5.5 in accordance with the bottom coupling geometry. However, to calculate the bottom coupling torque of solid circular section the allowable shear stress (τ) of the bottom coupling is needed which is τ = 1/2 γs based on Tresca’s yield criterion.


τ = (2.T)/(π.r3) with, τ= 1/2 γs thus,

1/2 γs = (2.T)/(π.r3)


Therefore the bottom coupling torque (T) for solid circular section is,


T = (γs . π . r3)/4

T = (840 MPa × π × (60.05 × 10-3 m)3)/4

T = 142859.196 Nm


  • Method 2 Calculation using the Robert I. Isakower’s Chart

There is no Isakower's Chart for shaft with circular section therefore the calculation based on Isakower’s Chart will not be calculated.


5.1.3.2 Calculation of Shaft with 2 Splines


  • Method 1 Calculation using the Roark’s Formula
Figure 5.6 Roark.png


Based on Roark’s formulas for torsional deformation and stress for shaft with two splines, the calculation used formula based on figure 5.6 in accordance with the bottom coupling geometry.


K1 = 0.6366


K2 = 0.0069 -0.0229(a/b) + 0.0637(a/b)2

K2 = 0.0069 -0.0229(1.338) + 0.0637(1.338)2

K2 = 0.0903


K3 = -0.0675 +0.3996(a/b) -1.0514(a/b)2

K3 = -0.0675 +0.3996(1.338) -1.0514(1.338)2

K3 = -1.415


K4 = 0.3582 -1.8324(a/b) + 1.5393(a/b)2

K4 = 0.3582 -1.8324(1.338) + 1.5393(1.338)2

K4 = 0.7583


Hence B is,

B = K1 + K2(b/r) + K3(b/r)2 + K4(b/r)3

B = 0.6366 -0.0903(0.216) -1.415(0.216)2 + 0.7583(0.216)3

B = 0.5587


To calculate the bottom coupling torque for shaft with 2 splines, the allowable shear stress (τ) of the bottom coupling is needed which is τ = 1/2 γs based on Tresca’s yield criterion.

τ = (T.B)/r3 with, τ = 1/2 γs thus,

1/2 γs = (T.B)/r3


Therefore the bottom coupling torque (T) for shaft with 2 splines is,

T = (γs . r3)/(2.B)

T = (840 MPa × (34.95 × 10-3 m)3)/(2 × 0.5587)

T = 32093.14 Nm


  • Method 2 Calculation using the Robert I. Isakower’s Chart

For the calculation using the Robert I. Isakower’s Chart the bottom coupling shear stress of 2 spline shaft is τ = T (f/r3 ) and f is known as the stress factor. However, b/r and a/b is first needed to find f. The value of b/r used is 0.216 and a/b is 1.338 based on the bottom coupling geometry. Therefore, the stress factor (f) can be obtained from Figure 5.7 below.

Figure 5.7 Isakower.png


To calculate bottom coupling torque, the allowable shear stress (τ) of the bottom coupling is needed which is τ = 1/2 γs based on Tresca’s yield criterion.


τ = T(f/r3 ) with, τ= 1/2 γs thus,

1/2 γs = (T.f)/r3


Therefore the bottom coupling torque (T) for shaft with 2 splines is,


T = (γs . r3)/(2 f)

T = (840 MPa × (34.95 × 10-3 m)3)/(2 × 0.61)

T = 29394.16 Nm


  • Maximum Allowable Torque (Coupling to Valve Stem)

The maximum allowable torque at the bottom of the coupling (coupling to valve stem) is calculated through the approach method of superposition by subtracting the solid circular shaft with the inner shaft with 2 splines. The calculation is as follow:


T = Tcircular -T2 splines = 142859.196 -32093.14

T = 110766.056 Nm


Since the calculation used the approach method uncertainties may have happened, therefore a correction factor of 15% is used by subtracting 15% of the above value with the calculated value above. The calculation is as follow:


Tef = T -0.15T

Tef = 110766.056 -0.15(110766.056)

Tef = 94151.148 Nm


Based on the above calculations, if coupling material used is AISI 4340:

  • Top coupling connection (coupling to actuator yoke) is capable of withstanding torque up to 101052.21 Nm 

  • Bottom coupling connection (coupling to valve stem) is capable of withstanding torque up to 94151.148 Nm, with correction value of 15% used for calculating the bottom coupling connection.
  • If the proposed actuator to be installed to the Ball Valve is VALVITALIA LPS-16-430-CM23-FO, the actuator has maximum torque of 15953 Nm at 7 barg (supply pressure) with an assumption of having similar torque with LP-16-430-CM29. This indicates that the coupling design is safe to withstand the actuator torque.


5.2 ESDV Ball Valve Acceptance Criteria

Several tests are performed after the modification process to ensure that the ESDV is in accordance with the PHM general specification for piping, valves, and vessels (MHK-COMP-SPE-EP-PVV-0142). These tests include:


5.2.1 Shell Test (Water)
  • Ball in half open position (minimum 10 degrees opening).
  • Apply pressure to the values shown on one of the applicable tables 5.1, 5.2, 5.3, 5.4 (shell tests).
  • Isolate the valve from the pressure source.
  • Clean and dry the valve body.
  • Minimum duration of pressure test according to table 5.5.
  • Acceptance criteria: no visible leakage is acceptable.


5.2.2 High Pressure Closure Test (Water)
  • Ball in half open position, valve at atmospheric pressure.
  • Close the valve.
  • Apply pressure on one seat to the values shown on one of the applicable table 5.1-5.4 (high-pressure closure tests), the volume beyond this seat being at atmospheric pressure.
  • Duration of pressure test according to table 5.5.
  • Acceptance criteria: Maximum acceptable leakage rate according to table 5.6 (leakage to be measured in the valve body cavity or on the opposite side).
  • The same test shall be carried out on the other seat.

Gas tests shall only be carried out after all water pressure tests have been passed satisfactorily. For safety reasons, high-pressure gas tests shall be performed in an area especially dedicated to it and specifically designed to resist a possible high-pressure gas explosion, such as a heavy wall concrete building or pit. No personnel may be allowed to approach the valve whilst it is under high-pressure gas test.


5.2.3 Low Pressure Closure Test (Air or Nitrogen)
  • Ball in half open position, valve at atmospheric pressure.
  • Close the ball.
  • Carry out one open to closed cycle without pressure.
  • Put one seat under pressure (5.5 bars + 10% for all valve pressure classes and diameters), the volume beyond this seat being at atmospheric pressure. Only air supply or nitrogen shall be used for this test.
  • Isolate the valve from the pressure source.
  • Duration of pressure test according to table 5.5. This test duration is meant to be measured after venting of the body cavity for the minimum stabilization time also shown on table 5.5.
  • Inspection shall be carried out on an outlet located between the two seats in the valve body cavity or on the opposite side for floating ball, using soap bubble test method.
  • Acceptance criteria: no leaks are acceptable.
  • The same test shall be carried out on the other seat.


5.2.4 High Pressure Closure Test (Nitrogen)
  • Ball in half open position, valve at atmospheric pressure.
  • Close the ball.
  • Apply pressure on one seat to the values shown on one of the applicable table 5.1-5.4 (high pressure closure tests), the volume beyond this seat being at atmospheric pressure.
  • Duration of pressure test according to table 5.5 (this test duration is meant to be measured after venting of the body cavity for the minimum stabilization time also shown on table 5.5).
  • Leakage rate measurement is carried out on an outlet located between the two seats in the valve body cavity or on the opposite side for floating ball, using a calibrated flow meter (the unit for leakage measures is in cm3/min).
  • Acceptance criteria: the maximum acceptable leakage rate shall be according to table 5.6.
  • The same test shall be carried out on the other seat.


Table 5.1.png


Table 5.2 & 5.3.png


Table 5.4.png


Table 5.5.png


Table 5.6.png


5.3 Evaluation for Ex-Used ESDV Reutilization

This section discuss about the comparison between buying 1 new ESDV unit with the repair/modification of ESDV in terms of cost, delivery time, and quality.


5.3.1 Actual Cost & Delivery Time of New ESDV

The actual cost of 1 ESDV unit is USD 45,253, which is about IDR 633,542,000. The delivery time itself for 1 batch is 42 weeks (10 months) or 294 days ARO (After Received Order).

Figure 5.8 One ESDV Unit Cost.png


5.3.2 Estimated Breakdown Cost/Duration for Ex-Used ESDV Reutilization

Several cost and duration of activities that are important for reused and modification of ESDV are as follow:


5.3.2.1 Removal/Dismantling from Existing Well (Manpower):
  • Estimate Cost : IDR 60,000,000
  • Duration : 2 days


5.3.2.2 LCT (Sea Transportation)
  • Estimate Cost : IDR 30,000,000 (IDR 15,000,000/day)
  • Duration : 2 days


5.3.2.3 Mob-Demobilization (Land Transport)
  • Estimate Cost : IDR 3,000,000
  • Duration : 2 days
  • Scope : Transport from Handil or Senipah to Contractor’s Workshop, back and forth.


5.3.2.4 Pre Inspection/Testing
  • Estimate Cost : IDR 22,000,000
  • Duration : 7 days
  • Scope : Leak Test and Function Test referring to Company Specification.


5.3.2.5 Repair Cost:
  • Repair Ball Valve:
  • Minor Repair
  • Estimate Cost : IDR 77,440,000
  • Duration : 40 days
  • Scope : Dismantling; cleaning & blasting; sanding; gasket, packet & o-ring replacement; and final testing according to GS-EP-PVV 142.
  • Major Repair (Never Performed Before)
  • Estimate Cost : IDR 154,880,000
  • Duration : 90 days
  • Scope : Machining; replacement of ball valve, metal seats, and stem; and all activities of ball valve minor repair.


  • Repair Actuator:
  • Minor Repair
  • Estimate Cost : IDR 72,600,000
  • Duration : 38 days
  • Scope : Paint remover; blasting & cleaning; seal, gasket, bolt and nuts replacement; and final testing according to GS-EP-PVV 142.
  • Major Repair
  • Estimate Cost : IDR 142,200,000
  • Duration : 66 days
  • Scope : Machining, weld repair, spare part replacement, reconditioning, and all activities of actuator minor repair.


5.3.2.6 Modification
  • Estimate Cost : IDR 30,000,000
  • Duration : 21 days
  • Scope : Fabrication/modification of spool adapter, gearbox, stem, coupling, and key; torque calculation, and final testing according to GS-EP-PVV 142.


5.3.2.7 LCP (Local Control Panel)
  • New Fabricate
  • Estimate Cost : IDR 72,500,000
  • Duration : 90 days


  • Refurbishment
  • Estimate Cost : IDR 43,500,000
  • Duration : 3 days
  • Scope : Installation of instrument on the refurbished LCP.


5.3.3 Estimated Breakdown Duration for Ball Valve & Actuator Repair
5.3.3.1 Ball Valve Minor & Major Repair
Table 5.7 & 5.8.png
5.3.3.2 Actuator Minor & Major Repair
Table 5.9 & 5.10.png


5.3.4 Examples of ESDV Repair/Modification Estimated Cost & Duration

Several case of reused and modification of ESDV based on total process cost and duration are presented on the following tables:

Reutilized Ex-Used ESDV Cost & Duration Table.png


5.3.5 New & Repair/Modification ESDV Comparison in Terms of Cost & Duration

Major repair of ball valve is still a rare condition in PHM. One example of ESDV repair case that has happened in PHM is minor repair of ball valve and major repair of actuator with refurbished LCP. The total cost and duration for this case example is estimated as follow:


Minor Repair of Ball Valve & Major Repair of Actuator, Refurbished LCP

  • Total Cost : IDR 381,140,000
  • Duration : 82 days
  • Scope : Dismantling, LCT (Sea Transport), Mobilization & Demobilization (Land Transport from Handil to Contractor), Pre-Inspection, Ball Valve Minor Repair & Actuator Major Repair (performed at the same moment), and LCP Refurbishment
Figure 5.9 BV & Actuator Repair.png


New ESDV Cost & Duration

  • Total Cost : IDR 633,542,000
  • Duration : 294 days


Based on the above values it can be said that repair costs about 50% less than a new ESDV unit, and the duration is much faster as it takes only 82 days. Based on these data it can be said that repair is much more effective than buying new ESDV in terms of cost and duration.


5.3.6 Highest/Lowest Cost & Duration of ESDV Repair/Modification

Based on the calculation of cost and duration in section 5.3.4 table, the highest cost for repair goes to the case example where major repair of ball valve and actuator as well as buying new LCP is performed, the cost and duration is as follow:


Major Repair of Ball Valve and Actuator, New LCP

  • Total Cost : IDR 487,580,000
  • Duration : 193 days


The lowest cost and duration for repair goes to the case example where only modification (ball valve/actuator) and refurbishment of LCP is performed, the cost and duration is as follow:


Modification Only and Refurbished LCP

  • Total Cost : 188,500,000
  • Duration : 37 days


Based on these costs it can be indicated that the major repair of ball valve is critical in causing the highest cost of all repair case since the repair costs IDR 154,880,000. Major repair of ball valve is critical for the cost, but it is still preferred compared to buying 1 new ESDV unit. As for buying a New LCP it is critical in causing the highest duration of the process since it takes an additional 90 days compared to the refurbishment of LCP having duration of only 3 days. Therefore, buying new LCP for repair/modification should be avoided to minimize total process duration.


5.3.7 Quality of Reused/Repaired ESDV

The quality of reused/repaired ESDV can be assessed based on the pressure testing that has been tested on the particular ESDV. Generally the pressure testing and acceptance criteria for new ESDV are in accordance with the PHM general specification for piping, valves, and vessels (MHK-COMP-SPE-EP-PVV-0142) that has been explained in section 5.2. However, the acceptance criteria of reused/repaired ESDV pressure test has been decreased to only 65 barg for remote well and 220 barg for adjacent well (based on STANDING INSTRUCTION, ESDV Inspection and Test Instruction). This decision was made to meet the requirements of needing ESDVs as fast as possible for new wells. The pressure test has been set to 65 barg for remote well because it is the minimum pressure requirements for the ESDV to close based on the PSHH. The new testing procedure and acceptance criteria are as follow:


1. High Pressure Closure Test (Nitrogen)

  • Ball in half open position, valve at atmospheric pressure.
  • Close the ball.
  • Apply pressure on one seat to the values 65 bar or 220 bar while value on the other seat is at atmospheric
  • Observe the pressure stabilize for 1 minute.
  • Hold the pressure for 5 minutes.
  • Measure and record the passing quality.
  • Acceptance criteria: Passing quantity (in bubbles/s) shall be noted where the maximum acceptable leakage rate shall be according to table 5.6.
  • Repeat from the first step for the other seat.


2. Low Pressure Closure Test (Nitrogen)

  • Ball in half open position, valve at atmospheric pressure.
  • Close the ball.
  • Carry out one open to closed cycle without pressure.
  • Apply pressure on one seat (10% x operating pressure + 5.5 barg), while value on the other seat is at atmospheric.
  • Observe the pressure stabilize for 1 minute.
  • Hold the pressure for 5 minutes.
  • Inspect on the outlet located between the two seats using soap bubble method.
  • Release all the pressure.
  • Acceptance criteria: no leak is observed with soap bubble test.
  • Repeat from the first step for the other seat.


3. Shell Test (Water)

  • Ball in half open position. Valve at atmospheric pressure
  • Apply pressure at 65 barg for remote well or 220 barg for adjacent well
  • Hold the pressure for 5 minutes.
  • Clean and dry the valve.
  • Observe the valve from any visible leak.
  • Release all the pressure.
  • Acceptance criteria: no visible leakage is permitted.
  • Repeat from the first step for the other seat.


There are still uncertainties to know whether lowering the acceptance criteria of reused/repaired ESDV is safe for the system. One of the potential problem that may arise is that passing could still happen if the pressure in the flowline is higher than 65 barg for remote well or higher than 220 barg for adjacent well. Based on the well flowline design pressure of Tunu well, the maximum flowline design pressure for shallow zone is 250 barg and for Tunu mainzone is 310 barg. The system components that are important to withstand the maximum pressure are the master valve, wing valve, choke valve, and ESDV. The system has to be fully rated, which means each of theses component must be able to withstand the maximum flowline design pressure (250 or 310 barg). The advantage of a fully rated system is that it does not need the addition of relief system such as PSV (Pressure Safety Valve). Since the pressure testing for the reused ESDV is only at 65 barg there is a possibility that passing can happen because the maximum design pressure of the flowline is at 250 barg. Even if the operating pressure is only at 30-40 barg it does not ensure that the pressure may not increase as the ESDV is closed.


5.3.7.1 Potential Risk

One of the potential risks of overpressure due to pressure accumulation is taken from the TN-W32rc and TN-Q74rc incoming flowline to GTS Q. The diagram of pressure accumulation can be seen on figure 5.10.

Figure 5.10 Potential Risk.png


Figure 5.10 indicates that when a pressure of higher than 65 barg is achieved at the TN-W32 flowline there is the risk of ESDV passing due to overpressure. As passing happen it will trigger the PSHH at GTS Q when a pressure of higher than 42 barg is achieved, which in turn closes the ESDV at GTS Q. As the ESDV at GTS Q stays closed there is a potential of pressure accumulation from TN-Q74rc that eventually leads to overpressure. This pressure accumulation may eventually cause damage to the ESDV when a pressure higher than 65 barg is achieved, since the reutilization of ESDV is only pressure tested at 65 barg.


5.3.7.2 Mitigations

Based on the previous section potential risks, there are several mitigations available. One of the mitigation is the availability of other valves such as the master valve and wing valve that also close when the ESDV closes. Since the wing and master valve closes when pressure of higher than 65 barg is achieved, the potential for pressure accumulation is relatively low. The second mitigation is the availability of two PSHH at the GTS Q. This PSHH has the function of closing the incoming GTS Q ESDV from TN-W32rc and TN-Q74rc. Other than closing it also functions sending alarm to the processing unit to inform the monitor. Then through the use of push button available ate the processing unit, it can be used to shutdown the instrument gas at GTS Q. Since the instrument gas at GTS Q is shutdown, no instrument gas is supplied to commingle well TN-W32rc and TN-Q74rc. Another mitigation is the availability of PSV (Pressure Safety Valve) at GTS Q. The function of PSV is as a relief system when a pressure of higher than 46.3 is achieved. As setting pressure is reached, venting happens for depressurization. Since depressurization at GTS Q happens, the incoming GTS Q ESDV will reopen. From these mitigations it can be said that the reused/repaired ESDV pressure tested at 65 barg is safe for use, however it will depend on the reliability of other components. The purpose of a fully rated system is that each component (ESDV, Master valve, Wing valve, PSV, etc) must be able to withstand the maximum design pressure of the well. The reason is that if one component fails the other may still be able to function as its own. The purpose of ESDV is also as isolation between flowline from Christmas tree to Pipepline. If the ESDV fails it means that no protection is available for the pipeline.

CHAPTER VI CONCLUSION AND RECOMMENDATION

Based on Chapter V Study Case, it can be concluded and recommended for PHM as follow:


  1. The calculation of Maximum Allowable Coupling Torque can be done by 2 methods. The first one is Roark’s formula and the second one is based on Robert Isakower’s chart. The result of both calculations doesn’t show any significant difference.
  2. Based on the coupling torque calculation, the top coupling connection (coupling to actuator yoke) is capable of withstanding torque up to 101052.21 Nm
and the bottom coupling connection (coupling to valve stem) is capable of withstanding torque up to 94151.148 Nm.
  3. If the proposed actuator to be installed to the Ball Valve is VALVITALIA LPS-16-430-CM23-FO with maximum torque of 15953 Nm at 7 barg (assumed of having similar torque with LP-16-430-CM29). It can be concluded that the proposed coupling design with material of AISI 4340 (yield strength of 840 MPa) is safe to withstand the actuator torque.
  4. Based on the evaluation for Ex-Used ESDV reutilization, the purchase of new LCP (Local Control Panel) leads to a much higher duration, therefore it is not recommended.
  5. Based on the evaluation for Ex-Used ESDV reutilization compared to buying one new ESDV unit, in terms of cost and time repair/modification is more efficient as it cost less and has less delivery time.
  6. In terms of quality, the reutilized ex-used ESDV pressure tested based on PSHH (65 barg or 220 barg) will depend on the reliability of other components (Master Valve, Wing Valve, & PSV).
  7. Reutilization of ex-used ESDV pressure tested based on PSHH is recommended only during the condition of ESDV limited stock and the emergency of needing ESDV, as it requires less duration than buying new unit. Therefore, for future well connection it is ideal to utilize & purchase new ESDV based on the required design pressure of the well.
  8. Reutilization of ex-used ESDV is also recommended for well with low production potential that would not last for long periods of time, as it would benefit in the reduction of cost.
  9. However, if possible it is recommended to pressure test the reutilized ex-used ESDV based on the maximum flowline design pressure (250 barg for Tunu Shallow Zone & 310 barg for Tunu Main Zone).

REFERENCE

  1. Pertamina Hulu Mahakam General Specification for Piping, Valves, and Vessels (MHK-COMP-SPE-EP-PVV-0142)
  2. Pertamina Hulu Mahakam Standing Instruction for ESDV Inspection and Test Instruction
  3. PT. Duta Katup Mas Ball Valve 6” #600 RF MAST (Maximum Allowable Stem Torque) Calculation Report
  4. Young, Warren C., & Budynas R.G. Roark’s Formulas for Stress and Strain (7th ed.). New York: McGraw-Hill.
  5. Isakower, Robert I. (1980). The Shaft Book (Design Charts for Torsional Properties of Non-Circular Shafts). New Jersey: Arradcom.
  6. Pilkey, Walter D. Peterson’s Stress Concentration Factors (2nd ed.). New York: John Wiley & Sons,
  7. http://www.piping-engineering.com/maximum-allowable-stem-torque-mast.html
  8. http://www.drillingformulas.com/surface-christmas-tree-dry-tree-basic-knowlege/
  9. http://www.drillingformulas.com/surface-christmas-tree-dry-tree-basic-knowlege/
  10. https://instrumentationtools.com/shutdown-valve/
  11. https://automationforum.in/t/emergency-shutdown-valve/4517

APPENDIX

Appendix 1 ESDV.png


Appendix 2 ESDV.png


Appendix 3 ESDV.png


Nicoivander

7 months ago
Score 0+

Hello, I'm curious for the PSLL, PSHH, and ESDV pressure settings. Does the pressure setting for those 3 components always kept same or changing depends on a certain conditions? Thank you 😁

Nico Ivander - 1606907562

Arkan.cesnanda

7 months ago
Score 0+
Hello Nico, the settings of the PSHH and PSLL varies depending on the location of the well. In this case since the well is a remote well the PSHH is 65 barg and the PSLL is 3 barg. For adjacent well the settings of the PSHH is at 220 barg.

Andaruwrtm

7 months ago
Score 0+

Halo Arkan, ada yang ingin saya tanyakan. Mengapa Ex-ESDV yang ingin digunakan kembali hanya diuji dengan pressure test 65 barg saja? Apa yang terjadi jika Ex-ESDV diuji dengan pressure test sesuai dengan kondisi tekanan sesungguhnya pada flowline, yaitu 250-310 barg?

Andaru Wiratama - 1606904503

Arkan.cesnanda

7 months ago
Score 0+
Halo Andaru, untuk Ex-ESDV yang di gunakan kembali hanya diuji pada 65 barg karena mengikuti setting dari PSHH yang merupakan 65 barg. Pada kondisi 65 barg atau diatasnya maka PSHH akan menyebabkan ESDV tertutup. Namun nyatanya kondisi di lapangan dapat terjadi pressure diatas 65 barg dikarenakan Flowline Design Pressure yang mungkin terjadi adalah 250-310 barg. Sehingga jika ESDV hanya diuji pada pressure 65 barg, kondisi dari ESDV tersebut tidak diketahui dan ada kemungkinan leak maupun passing terjadi. Dengan dilakukannya pressure test pada 250-310 barg dapat meningkatkan kepercayaan kita dalam reuse ESDV, namun dari segi repair akan lebih sulit untuk mengembalikan kondisi reused ESDV pada kondisi tersebut.

Anonymous user #1

7 months ago
Score 0 You
Andaru sebagai tambahan bahwa spec design awal ESDV dapat mampu menahan 500 barg.

Aldorenaldy

7 months ago
Score 0+

Halo Arkan. Saya ingin bertanya. Mengapa PHM perlu melakukan procurement ESDV? Dan mengapa refurbish harus dilakukan pada ESDV yang lama?

Aldo Renaldy - 1606881115

Arkan.cesnanda

7 months ago
Score 0+
Halo Aldo, PHM harus melakukan procurement ESDV dikarenakan terjadinya keterlambatan untuk meng-procure ESDV ketika terjadi transisi dari Total E&P menjadi PHM. Dikarenakan keterlambatan ini, maka terjadi shortage 17 unit ESDV untuk project well connection yang akan mendatang. Jika pembelian baru dilakukan maka akan memakan waktu minimal 42 minggu, sehingga dengan dilakukannya refurbishment pada Ex-used ESDV akan mempercepat ketersediaan ESDV. Dari sisi lain, refurbishment ESDV juga memerlukan cost yang lebih rendah dari pembelian unit ESDV baru.
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