The document is a summer training report submitted by four students to ONGC, Ankleshwar detailing their training in well control practices and procedures. It contains:
1. An introduction and contents listing the various sections in the report.
2. Sections on the drilling rig systems - power, hoisting, circulating, rotary, well control and monitoring systems.
3. Details on well control principles like primary and secondary control, kick tolerance, equivalent circulation density, leak-off tests, well control methods and procedures for kicks, blowsouts and pressure control.
4. Sections on lost circulation, well control equipment like BOP stacks, annular and ram preventers, locks, diverters and well
A drill stem test (DST) is used to test characteristics of a newly drilled well while the drilling rig is still on site. It can provide estimates of permeability, reservoir pressure, fluid types, wellbore damage, barriers and fluid contacts. There are three main methods to analyze DST data: Horner's plot method, type curve matching method, and computer matching. Type curve matching involves matching pressure change over time data from the DST to standard type curves to determine properties like permeability and skin factor. Gringarten type curves are commonly used and account for variations in pressure over time based on reservoir-well configurations.
This document provides an overview of well control procedures. It discusses causes of kicks such as swabbing or pumping light mud that can lead to underbalance. Primary well control relies on mud hydrostatic pressure, while secondary control uses a blowout preventer. Tertiary control involves pumping substances to stop downhole flow. Methods for killing a well are also presented, including the driller's method, wait and weight, volumetric, and bullheading. Kick detection equipment like the pit volume totalizer and flow indicator are also outlined.
This document provides procedures for well testing at ENI S.p.A. Agip Division. It outlines responsibilities for personnel involved in well testing, describes various types of production tests, safety barriers, downhole and surface equipment used, and procedures for preparing wells, installing test strings, executing tests, collecting data, sampling, and abandoning or suspending wells. The document is confidential property of ENI and intended to guide their technicians and engineers in well testing activities worldwide.
Well testing provides essential information for characterizing oil and gas reservoirs and evaluating their economic potential. It involves short-term production of reservoir fluids to estimate deliverability and analyze pressure transients caused by changes in flow rates. Integrated analysis of multiple well tests helps optimize development by assessing near-wellbore conditions, estimating reservoir boundaries and drive mechanisms, and characterizing permeability. Modern testing combines downhole measurements and computer analysis to maximize information about the reservoir.
This 5 day training course is designed to give you a comprehensive account of methods and techniques used in modern well testing and analysis. Subsequently to outlining well test objectives and general methodologies applied, the course will provide real case studies and practice using modern software for Pressure Transient Analysis. These exercises will demonstrate clearly the limitations, assumptions and applicability of various techniques applied in the field.
This document provides an overview of offshore oil and gas facilities, including wellhead platforms. It describes the typical components and functions of wellhead platforms, such as slots for drilling wells, wellhead control equipment, production manifolds, test separators, and utilities. The document outlines the process systems of a typical wellhead platform and summarizes the purpose and design of components like pig launchers, vents, flares, utility gas systems, drain systems, and chemical injection. Diagrams illustrate the installation and components of wellhead platforms such as the jacket, decks, cranes, pipelines, and safety equipment.
Hi,friend,
This presentation will give some effectiveness for entry level drilling engineers!
Thanks and Best regards,
Myo Min Htet
MPRL E&P Pte Ltd.
+95933336767
myominhtetz2012@gmail.com
This document discusses well testing and well test analysis software programs. It provides information on:
- The objectives of well testing including identifying fluid types and reservoir parameters
- Types of well tests including productivity tests for development wells and descriptive tests for exploration wells
- Popular well test software programs for analytical and numerical analysis including Saphir, PanSystem, Interpret 2000, and Weltest 200
- An overview of the Weltest 200 program which links analytical and numerical well test analysis through different modules
- Using an example of liquid productivity or IPR testing to demonstrate how well test data is incorporated and analyzed in the software
A drill stem test (DST) is used to test characteristics of a newly drilled well while the drilling rig is still on site. It can provide estimates of permeability, reservoir pressure, fluid types, wellbore damage, barriers and fluid contacts. There are three main methods to analyze DST data: Horner's plot method, type curve matching method, and computer matching. Type curve matching involves matching pressure change over time data from the DST to standard type curves to determine properties like permeability and skin factor. Gringarten type curves are commonly used and account for variations in pressure over time based on reservoir-well configurations.
This document provides an overview of well control procedures. It discusses causes of kicks such as swabbing or pumping light mud that can lead to underbalance. Primary well control relies on mud hydrostatic pressure, while secondary control uses a blowout preventer. Tertiary control involves pumping substances to stop downhole flow. Methods for killing a well are also presented, including the driller's method, wait and weight, volumetric, and bullheading. Kick detection equipment like the pit volume totalizer and flow indicator are also outlined.
This document provides procedures for well testing at ENI S.p.A. Agip Division. It outlines responsibilities for personnel involved in well testing, describes various types of production tests, safety barriers, downhole and surface equipment used, and procedures for preparing wells, installing test strings, executing tests, collecting data, sampling, and abandoning or suspending wells. The document is confidential property of ENI and intended to guide their technicians and engineers in well testing activities worldwide.
Well testing provides essential information for characterizing oil and gas reservoirs and evaluating their economic potential. It involves short-term production of reservoir fluids to estimate deliverability and analyze pressure transients caused by changes in flow rates. Integrated analysis of multiple well tests helps optimize development by assessing near-wellbore conditions, estimating reservoir boundaries and drive mechanisms, and characterizing permeability. Modern testing combines downhole measurements and computer analysis to maximize information about the reservoir.
This 5 day training course is designed to give you a comprehensive account of methods and techniques used in modern well testing and analysis. Subsequently to outlining well test objectives and general methodologies applied, the course will provide real case studies and practice using modern software for Pressure Transient Analysis. These exercises will demonstrate clearly the limitations, assumptions and applicability of various techniques applied in the field.
This document provides an overview of offshore oil and gas facilities, including wellhead platforms. It describes the typical components and functions of wellhead platforms, such as slots for drilling wells, wellhead control equipment, production manifolds, test separators, and utilities. The document outlines the process systems of a typical wellhead platform and summarizes the purpose and design of components like pig launchers, vents, flares, utility gas systems, drain systems, and chemical injection. Diagrams illustrate the installation and components of wellhead platforms such as the jacket, decks, cranes, pipelines, and safety equipment.
Hi,friend,
This presentation will give some effectiveness for entry level drilling engineers!
Thanks and Best regards,
Myo Min Htet
MPRL E&P Pte Ltd.
+95933336767
myominhtetz2012@gmail.com
This document discusses well testing and well test analysis software programs. It provides information on:
- The objectives of well testing including identifying fluid types and reservoir parameters
- Types of well tests including productivity tests for development wells and descriptive tests for exploration wells
- Popular well test software programs for analytical and numerical analysis including Saphir, PanSystem, Interpret 2000, and Weltest 200
- An overview of the Weltest 200 program which links analytical and numerical well test analysis through different modules
- Using an example of liquid productivity or IPR testing to demonstrate how well test data is incorporated and analyzed in the software
This document discusses well control equipment used in drilling operations. It describes blowout preventers (BOPs) which are used to close the well and control kicks before they become blowouts. There are different types of BOPs including annular preventers, ram preventers, and rotational preventers. Other important well control equipment includes an accumulator unit to operate BOPs hydraulically, inside BOPs, choke and kill lines, and a wellhead with casing heads to support tubulars and control fluid flow. Components should be function tested at least weekly to verify operations and actuation times should be recorded.
This document provides an overview of rig operations and equipment used in drilling wells. It describes the personnel involved in drilling, including the tool pusher, driller, derrick worker, and floor workers. It then explains the major surface and subsurface equipment used, including the hoisting system, drawworks, block and tackle, drilling line, mud circulation system, rotary system, and mud pumps. Finally, it discusses different types of rigs and factors considered when selecting a rig, such as water depth, load capacity, and stability.
This document discusses various artificial lift methods used to increase production from oil and gas wells as reservoir pressure declines. It describes the basic principles and components of common artificial lift techniques, including sucker rod pumps, gas lift, electrical submersible pumps, hydraulic jet pumping, plunger lift, and progressive cavity pumping. For each method, it provides information on advantages, limitations, and typical application ranges for operating parameters such as depth, production rate, temperature, and wellbore geometry. The document aims to provide an overview of different artificial lift options and considerations for selecting the appropriate production method.
Slot recovery operation for well J58-87, as a preparation of J58 platform to drill a new Extended-Reach Well SB293-4
Drilled by GULF OF SUEZ PETROLEUM CO. GUPCO
Joint Venture with BP, EGYPT. 2013
@ Gulf of Suez, EGYPT.
Petroleum Production Engineering - PerforationJames Craig
This document provides an overview of perforation for oil and gas wells. It discusses key objectives and components of perforation including shaped charges, explosives, perforating guns, and efficiency factors. It also covers well and reservoir characteristics relevant to perforation and provides equations for calculating perforation skin effects on well performance. The high-level goal of perforation is to establish communication between the wellbore and formation while maintaining reservoir inflow capacity.
1. Open-hole completions, also called 'barefoot' completions, involve setting casing above the productive interval and drilling into and through the reservoir, leaving it uncased and exposed to the wellbore.
2. For a simple open-hole well completion, the process involves setting production casing above the zone of interest before drilling into it, leaving it open to the wellbore, and then installing wellhead equipment to control flow.
3. Key steps include drilling into the formation, installing wellhead valves and pipes to direct and burn off initial flow, and cleaning the well until the flow stabilizes before testing and starting production.
This document discusses packers, which are used in oil and gas well completions to isolate sections of the wellbore. It describes the main components and functioning of packers, including cones that force slips into the casing and compressed sealing elements. The document outlines different types of packers classified by function, installation method, and duration. Removal techniques for permanent and retrievable packers are also summarized. Safety joints are explained as a means to release packers in emergency situations by shearing pins and allowing retrieval of completion equipment above. In conclusion, the document emphasizes that packers are critical for well integrity and outlines key aspects of their design and application.
This document provides abbreviations commonly used in drilling reports. Some examples include:
- BHA: Bottomhole assembly, includes tools below drillpipe
- BHP: Bottomhole pressure, usually measured with downhole gauge
- BLD: Bailed, removing cuttings with cylindrical tool on wireline
- BO, BOPD, BPH, BPD: Measurements of oil production like barrels per day
- CBL: Cement bond log to check cement quality around casing
- CIRC: Circulate drilling mud
- DRLG: Drilling
- GR: Gamma ray log to indicate lithology
- IP: Initial production test
- MW: Mud weight in pounds per
Nodal Analysis introduction to inflow and outflow performance - nextgusgon
This document discusses nodal analysis concepts for analyzing inflow and outflow performance in fluid systems. It introduces key terms like nodal analysis, inflow, outflow, upstream and downstream components, and graphical solutions. It provides an example problem calculating system capacity and the impact of changing pipe diameters. It also covers topics like single-phase and multiphase fluid flow, flow regimes, flow patterns, and calculating pressure drops and flow performance in pipes.
Coiled tubing is a unique fluid and tool conveyance means used to intervene throughout the entire well lifetime. Its flexibility of use is certainly one of the largest in the oil-and-gas industry, ranging from logging to stimulation to cleanout and even drilling. However, for the longest time, it was only seen as a rudimentary fluid conveyance system, despite its capability to service any well deviation.
With the development of instrumented tools for downhole point measurements and the use of fiber optics for distributed sensing, the recent advent of coiled tubing real-time monitoring has completely transformed this image. The access to live wellbore information—such as pressure, temperature, or flow—along with accurate depth control thanks to casing collar locator and gamma ray sensors have greatly enhanced fluid placement. Meanwhile, the ability to monitor the load, torque, and accelerations the bottomhole assembly is subjected to significantly improves the performance and possibility to use and manipulate downhole tools. Thanks to real-time monitoring, a whole new realm of optimization possibility was discovered.
This lecture describes the various real-time measurements that are available today during coiled tubing interventions and how they can be used to provide the industry with faster, safer, and more efficient operations while maximizing return on investment. A wide range of applications and examples will be discussed. Through them, one will be able to appreciate how coiled tubing has now entered a new era where the limits of operational optimization still have not been reached.
Metering systems are used to accurately measure oil and gas volumes being sold along the supply chain. For small volumes, oil is directly measured in storage tanks, while large volumes use automated LACT units. Natural gas can be measured using orifice meters, which determine flow rates based on differential pressure. Fiscal metering, which is used for custody transfer, employs meters, analyzers, and prover loops to ensure measurements are accurate to within 0.3% for liquids and 1.0% for gases. The data is used to calculate invoices and payments between partners.
This document provides an overview of basic drilling engineering. It discusses the types of drilling including rotary, cable tool, and coil tubing drilling. It describes the historical development of drilling from the early 1800s to modern advances. It also outlines the key components of a conventional drilling rig including those used for hoisting, rotating, circulating, and controlling the drill string. Common drilling fluid types and their uses are also mentioned. Finally, it notes some factors that characterize a successful drilling operation.
This presentation is a course a bout wellheads which includes the basic components of the well head and the advanced techniques.
helping students who are cared about petroleum industry to increase their knowledge about this tool that is important for both drilling and production.
For Further information, use the following LinkedIn account:
https://www.linkedin.com/in/mohamed-abdelshafy-abozeima-9b7589119/
This document discusses well intervention techniques using coiled tubing. It describes coiled tubing as continuously-milled tubular product that is straightened before insertion into the wellbore. The main types of well intervention discussed are pumping, slickline, snubbing, workover, and coiled tubing. It provides details on the components and functions of a coiled tubing unit, including the reel, injector head, control cabin, power pack, blowout preventer, stripper, and bottom hole assembly.
The document discusses well control systems used in drilling engineering. It describes the components of the well control system including sensors to detect fluid influx, the blowout preventer (BOP) stack, choke manifold, and associated equipment. The BOP stack is made up of different sealing devices like annular and ram BOPs that can shut off the well in an emergency. Sensors and monitoring systems are used to detect kicks and monitor drilling parameters important for well control. The overall system aims to safely detect, control, and remove any unexpected influx of formation fluids into the wellbore.
This document discusses the drilling fluid circulation system used in drilling operations. It describes the key components of the system including mud pumps, solids removal equipment, and treatment equipment. Mud pumps are typically positive displacement pumps, namely duplex or triplex pumps. The document provides details on how drilling fluid is pumped from the surface to the drill bit, circulates in the wellbore, and returns to the surface while removing cuttings.
The document outlines the steps for well drilling and site preparation. It describes leveling the site, digging a cellar and mud pits, hammering a conductor pipe, drilling a rathole, and transporting equipment to the site. It then details rig setup including raising the mast and substructure, connecting the conductor pipe, rig acceptance checks, and making up drill pipes. Preparing the spud mud by mixing and pumping it is covered. The process of spudding in the hole and cleaning mud returns is also outlined. Subsequent steps reviewed are picking up drill pipes, running and cementing the surface casing, waiting for the cement to cure, and completing the cement job.
PetroSync - IWCF Drilling Well Control 6.0Shanice Sua
This document provides information about PetroSync's IWCF-accredited well control certification courses. It outlines the different course levels, durations, prerequisites, content, and examination structures. Level 2 is a 4-day introductory course for all drilling roles. Levels 3 and 4 are for supervisory roles and include practical assessments. Candidates must pass written and practical exams to obtain certifications valid for 2-5 years depending on level. The document provides course dates, locations, prices, and registration details.
Advanced blowout and well control robert d. graceThần Chết Nụ Hôn
= Critical velocity, ft/sec
= Constant, dimensionless
= Fluid density, Ib/ft3
= Pressure, psia
= Universal gas constant, ft-lbf/lb-°R
= Temperature, °R
= Particle diameter, ft
= Specific gravity of particles
This chapter discusses important well control equipment such as the blowout preventer stack, choke line, choke manifold, separator, and stabbing valve. It notes that while blowout preventers themselves are generally reliable, auxiliary equipment often has problems that can exacerbate well control issues. Issues discussed include leaking or non-functioning equipment, poor design of choke lines that are not resistant to erosion from abras
This document discusses well control equipment used in drilling operations. It describes blowout preventers (BOPs) which are used to close the well and control kicks before they become blowouts. There are different types of BOPs including annular preventers, ram preventers, and rotational preventers. Other important well control equipment includes an accumulator unit to operate BOPs hydraulically, inside BOPs, choke and kill lines, and a wellhead with casing heads to support tubulars and control fluid flow. Components should be function tested at least weekly to verify operations and actuation times should be recorded.
This document provides an overview of rig operations and equipment used in drilling wells. It describes the personnel involved in drilling, including the tool pusher, driller, derrick worker, and floor workers. It then explains the major surface and subsurface equipment used, including the hoisting system, drawworks, block and tackle, drilling line, mud circulation system, rotary system, and mud pumps. Finally, it discusses different types of rigs and factors considered when selecting a rig, such as water depth, load capacity, and stability.
This document discusses various artificial lift methods used to increase production from oil and gas wells as reservoir pressure declines. It describes the basic principles and components of common artificial lift techniques, including sucker rod pumps, gas lift, electrical submersible pumps, hydraulic jet pumping, plunger lift, and progressive cavity pumping. For each method, it provides information on advantages, limitations, and typical application ranges for operating parameters such as depth, production rate, temperature, and wellbore geometry. The document aims to provide an overview of different artificial lift options and considerations for selecting the appropriate production method.
Slot recovery operation for well J58-87, as a preparation of J58 platform to drill a new Extended-Reach Well SB293-4
Drilled by GULF OF SUEZ PETROLEUM CO. GUPCO
Joint Venture with BP, EGYPT. 2013
@ Gulf of Suez, EGYPT.
Petroleum Production Engineering - PerforationJames Craig
This document provides an overview of perforation for oil and gas wells. It discusses key objectives and components of perforation including shaped charges, explosives, perforating guns, and efficiency factors. It also covers well and reservoir characteristics relevant to perforation and provides equations for calculating perforation skin effects on well performance. The high-level goal of perforation is to establish communication between the wellbore and formation while maintaining reservoir inflow capacity.
1. Open-hole completions, also called 'barefoot' completions, involve setting casing above the productive interval and drilling into and through the reservoir, leaving it uncased and exposed to the wellbore.
2. For a simple open-hole well completion, the process involves setting production casing above the zone of interest before drilling into it, leaving it open to the wellbore, and then installing wellhead equipment to control flow.
3. Key steps include drilling into the formation, installing wellhead valves and pipes to direct and burn off initial flow, and cleaning the well until the flow stabilizes before testing and starting production.
This document discusses packers, which are used in oil and gas well completions to isolate sections of the wellbore. It describes the main components and functioning of packers, including cones that force slips into the casing and compressed sealing elements. The document outlines different types of packers classified by function, installation method, and duration. Removal techniques for permanent and retrievable packers are also summarized. Safety joints are explained as a means to release packers in emergency situations by shearing pins and allowing retrieval of completion equipment above. In conclusion, the document emphasizes that packers are critical for well integrity and outlines key aspects of their design and application.
This document provides abbreviations commonly used in drilling reports. Some examples include:
- BHA: Bottomhole assembly, includes tools below drillpipe
- BHP: Bottomhole pressure, usually measured with downhole gauge
- BLD: Bailed, removing cuttings with cylindrical tool on wireline
- BO, BOPD, BPH, BPD: Measurements of oil production like barrels per day
- CBL: Cement bond log to check cement quality around casing
- CIRC: Circulate drilling mud
- DRLG: Drilling
- GR: Gamma ray log to indicate lithology
- IP: Initial production test
- MW: Mud weight in pounds per
Nodal Analysis introduction to inflow and outflow performance - nextgusgon
This document discusses nodal analysis concepts for analyzing inflow and outflow performance in fluid systems. It introduces key terms like nodal analysis, inflow, outflow, upstream and downstream components, and graphical solutions. It provides an example problem calculating system capacity and the impact of changing pipe diameters. It also covers topics like single-phase and multiphase fluid flow, flow regimes, flow patterns, and calculating pressure drops and flow performance in pipes.
Coiled tubing is a unique fluid and tool conveyance means used to intervene throughout the entire well lifetime. Its flexibility of use is certainly one of the largest in the oil-and-gas industry, ranging from logging to stimulation to cleanout and even drilling. However, for the longest time, it was only seen as a rudimentary fluid conveyance system, despite its capability to service any well deviation.
With the development of instrumented tools for downhole point measurements and the use of fiber optics for distributed sensing, the recent advent of coiled tubing real-time monitoring has completely transformed this image. The access to live wellbore information—such as pressure, temperature, or flow—along with accurate depth control thanks to casing collar locator and gamma ray sensors have greatly enhanced fluid placement. Meanwhile, the ability to monitor the load, torque, and accelerations the bottomhole assembly is subjected to significantly improves the performance and possibility to use and manipulate downhole tools. Thanks to real-time monitoring, a whole new realm of optimization possibility was discovered.
This lecture describes the various real-time measurements that are available today during coiled tubing interventions and how they can be used to provide the industry with faster, safer, and more efficient operations while maximizing return on investment. A wide range of applications and examples will be discussed. Through them, one will be able to appreciate how coiled tubing has now entered a new era where the limits of operational optimization still have not been reached.
Metering systems are used to accurately measure oil and gas volumes being sold along the supply chain. For small volumes, oil is directly measured in storage tanks, while large volumes use automated LACT units. Natural gas can be measured using orifice meters, which determine flow rates based on differential pressure. Fiscal metering, which is used for custody transfer, employs meters, analyzers, and prover loops to ensure measurements are accurate to within 0.3% for liquids and 1.0% for gases. The data is used to calculate invoices and payments between partners.
This document provides an overview of basic drilling engineering. It discusses the types of drilling including rotary, cable tool, and coil tubing drilling. It describes the historical development of drilling from the early 1800s to modern advances. It also outlines the key components of a conventional drilling rig including those used for hoisting, rotating, circulating, and controlling the drill string. Common drilling fluid types and their uses are also mentioned. Finally, it notes some factors that characterize a successful drilling operation.
This presentation is a course a bout wellheads which includes the basic components of the well head and the advanced techniques.
helping students who are cared about petroleum industry to increase their knowledge about this tool that is important for both drilling and production.
For Further information, use the following LinkedIn account:
https://www.linkedin.com/in/mohamed-abdelshafy-abozeima-9b7589119/
This document discusses well intervention techniques using coiled tubing. It describes coiled tubing as continuously-milled tubular product that is straightened before insertion into the wellbore. The main types of well intervention discussed are pumping, slickline, snubbing, workover, and coiled tubing. It provides details on the components and functions of a coiled tubing unit, including the reel, injector head, control cabin, power pack, blowout preventer, stripper, and bottom hole assembly.
The document discusses well control systems used in drilling engineering. It describes the components of the well control system including sensors to detect fluid influx, the blowout preventer (BOP) stack, choke manifold, and associated equipment. The BOP stack is made up of different sealing devices like annular and ram BOPs that can shut off the well in an emergency. Sensors and monitoring systems are used to detect kicks and monitor drilling parameters important for well control. The overall system aims to safely detect, control, and remove any unexpected influx of formation fluids into the wellbore.
This document discusses the drilling fluid circulation system used in drilling operations. It describes the key components of the system including mud pumps, solids removal equipment, and treatment equipment. Mud pumps are typically positive displacement pumps, namely duplex or triplex pumps. The document provides details on how drilling fluid is pumped from the surface to the drill bit, circulates in the wellbore, and returns to the surface while removing cuttings.
The document outlines the steps for well drilling and site preparation. It describes leveling the site, digging a cellar and mud pits, hammering a conductor pipe, drilling a rathole, and transporting equipment to the site. It then details rig setup including raising the mast and substructure, connecting the conductor pipe, rig acceptance checks, and making up drill pipes. Preparing the spud mud by mixing and pumping it is covered. The process of spudding in the hole and cleaning mud returns is also outlined. Subsequent steps reviewed are picking up drill pipes, running and cementing the surface casing, waiting for the cement to cure, and completing the cement job.
PetroSync - IWCF Drilling Well Control 6.0Shanice Sua
This document provides information about PetroSync's IWCF-accredited well control certification courses. It outlines the different course levels, durations, prerequisites, content, and examination structures. Level 2 is a 4-day introductory course for all drilling roles. Levels 3 and 4 are for supervisory roles and include practical assessments. Candidates must pass written and practical exams to obtain certifications valid for 2-5 years depending on level. The document provides course dates, locations, prices, and registration details.
Advanced blowout and well control robert d. graceThần Chết Nụ Hôn
= Critical velocity, ft/sec
= Constant, dimensionless
= Fluid density, Ib/ft3
= Pressure, psia
= Universal gas constant, ft-lbf/lb-°R
= Temperature, °R
= Particle diameter, ft
= Specific gravity of particles
This chapter discusses important well control equipment such as the blowout preventer stack, choke line, choke manifold, separator, and stabbing valve. It notes that while blowout preventers themselves are generally reliable, auxiliary equipment often has problems that can exacerbate well control issues. Issues discussed include leaking or non-functioning equipment, poor design of choke lines that are not resistant to erosion from abras
This document provides an overview of well control techniques. It discusses the importance of maintaining primary well control by keeping hydrostatic pressure greater than formation pressure. It describes what a kick is and types of kicks that can occur. Common causes of kicks include not keeping the hole full, insufficient mud density, swabbing, lost circulation, and poor well planning. Warning signs of a kick and methods for recognition are outlined. Finally, it discusses the objective of well control and some important well control concepts like determining reservoir pressure and selecting a well control method.
This document provides an overview of basic well control procedures including:
- Kick detection and control methods like primary prevention and secondary detection and control
- Shut-in procedures such as hard, soft, and specialized shut-ins
- Well kill procedures including calculating initial and final circulating pressures, the wait-and-weight/engineer's method, and providing an example pump schedule.
It describes the key objectives and considerations for safely controlling a well when kicks occur and bringing the well pressure to a controlled state.
The document summarizes a senior capstone design project for Cameron to improve tracking of work progress at their manufacturing facility. The project involved modeling the current production system, analyzing causes of waste, and creating a new workboard and tracking system. The proposed system uses a workboard, phone app, and VBA program to collect and analyze real-time production data to monitor line balancing and workstation utilization.
PROBLEMA 1A
Gradiente de presiónpsi/pie = Densidad del fluidoppg x Factor de conversión
= 9.5 ppg x 0.052
= 0.494 psi/pie
Gradiente de Presiónbar/m = Densidad del fluidokg/m3 x Factor de conversión
= 1138 kg/m3 x 0.0000981
= 0.1115 bar/m
PROBLEMA 1B
Gradiente de presiónpsi/pie = Densidad del fluidoppg x Factor de conversión
= 8.33 ppg x 0.052
= 0.433 psi/pie
Gradiente de Presiónbar/
The document provides information about a blowout preventer (BOP) used on an oil rig. It discusses the various components of the BOP including annular preventers, ram preventers, and control systems. It describes the purpose and functioning of different types of rams, and provides specifications for components like annular preventers, ram types, pressure ratings, and inspection procedures. Maintenance and testing of the BOP is important for safety and preventing blowouts when drilling oil wells.
The document provides specifications and operating instructions for Cameron U Blowout Preventers (BOPs) used in surface oil and gas drilling applications. It includes dimensional drawings and specifications for various sizes of single and double U BOPs with different pressure ratings. The document outlines procedures for disassembly, assembly, operation, installation, maintenance, testing and storage of the equipment. It also provides specifications for related BOP components like rams, seals, and control systems.
This document contains a pre-school exercise book for well control with 769 pages of content across multiple sections. The introduction explains that the exercises were designed to help prepare students for well control school by providing up-to-date self-study questions with answers in the back. Section A contains questions about well control equipment, including blowout preventers, diverters, control systems and their components. Further sections cover topics like causes of kicks, kick indications, shut-in procedures, and example kick scenarios. Formulas for well control calculations are also included at the end.
This study was conducted at Kilang Minyak Sawit Kamunting Sdn. Bhd, Taiping to improve palm oil production by making improvements to the ripple mill machine. The ripple mill machine is part of the equipment in palm oil mills used to separate palm nut shells and kernels. The scope of the study was to examine the percentage efficiency of cracked shells and kernels. This percentage efficiency can be increased by improving the existing machine. According to the existing design of the ripple mill machine, the service life of the ripple rods was found to be short due to wear and tear. Parameters expected to affect the percentage efficiency of cracked palm nuts and shells and wear include optimum rotor speed, suitable distance between rotor and
Analytical Hierarchy Process applied to maintenance strategy selection for of...Nnaemeka Nwogbe
The aim of this research was to integrate the Analytical Hierarchy Process (AHP), to select the most appropriate maintenance strategy for a challenging environment faced by offshore platforms. Whilst providing new insight into the capability of the AHP methodology. This aim has been accomplished utilizing interview response from shell Maintenance and Inspection supervisors and two case studies based on: Petronas and Analysis of the failure of an offshore compressor crankshaft.
As a result from this research, the maintenance strategy based on information obtained was produced using the AHP multi criteria decision weighing methodology as implemented on a compressor in a corrosive environment.
The document provides a summary of a summer training report on installing DL-765 KV transformers at a project site in Jatikalan. It discusses the company profile of Larsen & Toubro, the basics of transformers including their principles of operation, parameters, losses, and construction. It also covers transformer oil, electric power distribution and transmission systems, the electrical grid, and jacks used for lifting transformers.
Colombo Dockyard PLC Industrial Training Reportakash de silva
Colombo Dockyard PLC is Sri Lanka's leading ship repair facility located in Colombo. It has 4 dry docks with a maximum capacity of 125,000 DWT. The report details the author's 3 month industrial training experience in various divisions of Colombo Dockyard including machinery outfitting, hull construction, hull treatment, ship repair, plant shop, engine fitting, and calibration. The training provided hands-on experience and knowledge of ship repair and engineering processes.
This document provides a training report from an internship at Holcim (Lanka) Ltd, a cement manufacturing company. It includes:
1) An introduction to Holcim (Lanka) Ltd, including its organizational structure, vision, products, and SWOT analysis.
2) A description of the experiences and tasks completed during the training period, including learning safety protocols, familiarizing with different departments, understanding the quarrying and cement production processes, and conducting analyses and projects.
3) A conclusion that the training provided valuable experience and insights into quarry operations and cement manufacturing, and suggestions for improving future training programs.
The document provides details about the author's 2-month industrial training at BASREC, a ship repair and engineering company in Bahrain. The author observed maintenance of ships, including docking, engine room components, hull blasting and painting. The author also learned skills like valve and pump overhaul, lathe machining, and bending aluminum. The training covered various departments at BASREC and provided hands-on experience in mechanical engineering fields.
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Similar to Well control practices and procedures to control any uncontrolled situation (20)
Well control practices and procedures to control any uncontrolled situation
1. SUMMER TRAINING REPORT
OIL AND NATURAL GAS CORPORATION LIMITED, ANKLESHWAR
WELL CONTROL PRACTICES AND
PROCEDURES TO DEAL WITH ANY
UNCONTROLLED SITUATION &
CASE STUDY
Under the guidance of Mr. R. P. Singh CE (D) – I/C CMT
ONGC, Ankleshwar.
Submitted by:
University of Petroleum and Energy
Studies, Dehradun
Shricharan Arumugam
B.Tech (Applied Petroleum Engineering)
Sugat Srivastava
B.Tech (Applied Petroleum Engineering)
Shiv Prakash Legha
B.Tech (Applied Petroleum Engineering)
Vivek Pathak
B.Tech (Applied Petroleum Engineering)
2. P a g e | 1
If you know the laws of buoyancy it doesn’t mean that you know how to
swim. It’s only through jumping in the water that you get to feel the depth.
This is applicable to every aspect of life.
Therefore Industrial training is of utmost importance.
The objective of the undergoing training was to familiarise with the day to
day functioning of the industry, hands on training and most importantly to
learn to put theory into practice.
I have been greatly privileged to have undergone training at,
OIL & NATURAL GAS CORPORATION LTD., ANKLESHWAR ASSET, GUJARAT
The report contains the extracts of the operations in well control & drilling
services during my training period.
4. P a g e | 3
CONTENTS
...................................6
........................................................................................7
................................................................................................................8
.....................................................................................................9
POWER SYSTEM .....................................................................................................10
HOISTING SYSTEM .................................................................................................10
CIRCULATING SYSTEM .........................................................................................11
ROTARY SYSTEM....................................................................................................12
WELL CONTROL SYSTEM.....................................................................................13
WELL MONITORING SYSTEMS............................................................................14
..........................................................................15
KICK.............................................................................................................................15
BLOWOUT..................................................................................................................15
PRIMARY WELL CONTROL ...................................................................................15
SECONDARY WELL CONTROL ............................................................................15
TERTIARY WELL CONTROL..................................................................................15
PRESSURE................................................................................................................15
3.6.1 Hydrostatic Pressure..................................................................................................15
3.6.2 Pressure Gradient ......................................................................................................15
3.6.3 Bottom Hole Pressure (BHP)....................................................................................16
3.6.4 Formation Pressure....................................................................................................17
3.6.5 Kick Tolerance ............................................................................................................17
CAUSES OF REDUCTION IN HYDROSTATIC HEAD .......................................17
3.7.1 Failure to fill the hole..................................................................................................17
3.7.2 Water dilution at surface (on rotary or at shale shaker) .......................................17
3.7.3 Removal of parts of barite from the mud, by mud handling system, such as
centrifuge etc..............................................................................................................17
3.7.4 Cement Setting...........................................................................................................17
3.7.5 Settling of Weighing Material....................................................................................18
MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE (MAASP) ........18
SWAB AND SURGE EFFECTS ..............................................................................18
TRIP MARGIN............................................................................................................19
EQUIVALENT MUD DENSITY IN THE ANNULUS..............................................19
EQUIVALENT CIRCULATION DENSITY (ECD)..................................................19
LEAK-OFF TEST .......................................................................................................19
6. P a g e | 5
...................................................................................50
...............................................50
.....................................51
......................................................................................51
6.3.1 ....................................................................................................51
6.3.2 ..................................................................................................54
6.3.3 ..........................................................................................................57
6.3.4 ..........................................................................................................60
6.3.5 ....................................................................................................61
6.3.6 ................................................................................62
..................................................................................................65
........................................................................................................67
.............................................................................................68
...............................................................................................69
STANDARD OPERATING PROCEDURE TO BE FOLLOWED: .......................69
PERIODIC INSPECTION AND MAINTENANCE..................................................70
DRILLS AND TRAINING ..........................................................................................71
7.3.1 ....................................................................................................71
7.3.2 ......................................................................................71
7.3.3 ....................................................................72
7.3.4 .................................................................................72
.............................................................................................................73
CASE STUDY – 1......................................................................................................73
CASE STUDY – 2......................................................................................................75
.............................................................................................................77
9. P a g e | 8
Figure 2 CMT Organogram
HCMT Corporate
Mumbai
RCMT, Mumbai RCMT, SBS RCMT, RJY RCMT, Baroda
CMT, Ahemdabad CMT, Mehsana CMT, Ankleshwar
R P Singh, CE(D)- I/C CMT
J M Bemat, DySE (D)
Saket, EE (D)
D G Valand, EE(D)
Sanjay Kumar, AEE(D)
Sandip Vasava, FO(D)
S K Sahare, AEE(P)
S D Patel, AEE(M)
Head Drilling
Services
Ankleshwar
11. P a g e | 10
POWER SYSTEM
Figure 4 Power System
HOISTING SYSTEM
12. P a g e | 11
Figure 5 Hoisting System
CIRCULATING SYSTEM
13. P a g e | 12
Figure 6 Circulating System
ROTARY SYSTEM
14. P a g e | 13
Figure 7 Rotary System
WELL CONTROL SYSTEM
15. P a g e | 14
Figure 8 Well Control Stack
WELL MONITORING SYSTEMS
16. P a g e | 15
KICK
BLOWOUT
PRIMARY WELL CONTROL
SECONDARY WELL CONTROL
TERTIARY WELL CONTROL
PRESSURE
3.6.1 Hydrostatic Pressure
(psi) (TVD-feet) (ppg)
(0.052 is a conversion constant)
3.6.2 Pressure Gradient
17. P a g e | 16
(psi)
(psi /ft) (feet) (psi)
x x (psi)
3.6.3 Bottom Hole Pressure (BHP)
BHP in different well situations:
i)
NOTE: Usually annular pressure losses are not taken into account for calculation of BHP during
killing.
(Note: Terms Surge & Swab pressure are explained at 3.9 in detail)
18. P a g e | 17
3.6.4 Formation Pressure
3.6.5 Kick Tolerance
CAUSES OF REDUCTION IN HYDROSTATIC HEAD
3.7.1 Failure to fill the hole
NOTE: Reduction in bottom hole pressure due to pulling out without filling hole will be much higher
for drill collars, if pulled out dry or, wet without filling the hole.
3.7.2 Water dilution at surface (on rotary or at shale shaker)
3.7.3 Removal of parts of barite from the mud, by mud handling system, such as
centrifuge etc.
3.7.4 Cement Setting
19. P a g e | 18
3.7.5 Settling of Weighing Material
MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE
(MAASP)
NOTE: MAASP value must be known & posted on the rig at all times during drilling. As the mud weight
is changed or another LOT is conducted, MAASP must be recalculated accordingly.
SWAB AND SURGE EFFECTS
20. P a g e | 19
TRIP MARGIN
(ppg) = [8.33 / 98( - )]
Where,
= lbs/100 sq.ft
= inches
= inches
EQUIVALENT MUD DENSITY IN THE ANNULUS
EQUIVALENT CIRCULATION DENSITY (ECD)
(ppg) (ppg) (psi)
(ft)
LEAK-OFF TEST
21. P a g e | 20
Figure 9 Idealised Leak-off test curves
26. P a g e | 25
4.1.2
Suitable safety valves with appropriate connections of crossover subs to fit all drillpipe and B.H.A.
connections must be on the rig floor, in the 'open' position ready for use with proper fittings and
handling devices. The closing/opening wrench must be readily available for immediate use.
A trip sheet will be filled out on each trip
27. P a g e | 26
When tripping, flow checks will be taken as follows
Just off bottom
At the lowest casing shoe
Prior to pulling drill collars through the BOP stack.
If the hole is taking the proper amount of fluid and if there is no drag or overpull which could
generate swabbing, then the pipe wiper will be installed after pulling the first 5 stands or after
the bit is pulled into cased hole.
28. P a g e | 27
Drilling breaks will be flow checked.
30. P a g e | 29
Clear written instruction must be issued to the drillers by the man-incharge, regarding the specific
action to take in case of a kick while drilling the tophole section. This could involve either shutting in
or diverting the well. A copy of the procedure must be prominently posted near the BOP/diverter
control panels.
31. P a g e | 30
SECONDARY CONTROL
4.2.1
.
Examples of full opening safety valves are T.I.W., Hydril, S.M.F. but not Gray.
32. P a g e | 31
IF UNABLE TO SHUT-IN THE DRILLSTRING, CLOSE SHEAR RAMS OR
DROP STRING.
4.2.2
33. P a g e | 32
i)
4.2.3
NOTE: All methods at keeping bottom hole pressure constant and equal to formation pressure
Note : While bringing the pump to kill speed keeping casing pressure constant, there might be slight reduction
in bottom hole pressure due to expansion of gas but this is compensated by the annular pressure losses.
34. P a g e | 33
NOTE: In case recorded SIDPP & SICP are equal but more than original SIDPP value, it indicates trapped
pressure in wellbore. Whereas if SICP is more than original SIDPP, it indicates that some influx is still in the
wellbore.
v.
35. P a g e | 34
Figure- Pressure profile – 1st cycle of Driller’s Method
Figure- Pressure profile – 2nd cycle of Driller’s Method
42. P a g e | 41
5.2.1
5.2.2
Power to force the pipe in the hole is generated by a system of pulleys and cables or
chains attached to the rig traveling block. As the traveling block is pulled upward, the
traveling snubbers grip the pipe and force the pipe into the hole.
5.2.3
The standard hydraulic snubbing unit is self-contained. A traveling snubber with
slips is connected to a piston that supplies the force to move pipe in the hole. In
addition to a set of traveling snubbers, the unit is equipped with a set of stationary
snubbers that are closed after the piston has moved the pipe the length of its full
stroke. The stationary snubbers grip the pipe and the piston is retracted. The
traveling snubber is then engaged, the stationary snubbers are opened and the
process is repeated.
5.2.4
43. P a g e | 42
If normal well killing techniques with conventional circulation are not possible or
will result in critical well control conditions, bullheading may be considered as a
useful method to improve the situation. Mud/influx are displaced/squeezed back
down hole into the weakest exposed open hole formation.
5.3.1
5.3.2
73. P a g e | 72
7.3.3
7.3.4
Well control training
Asst. Shift In-charge/Asst. Driller and above supervisory personnel should have accredited control
certificate (of the appropriate level). At least one trained person should be present on derrick floor to
observe well for activity even during shutdown period.
74. P a g e | 73
CASE STUDY – 1
1
•Made pumping line connections from cementing unit to annulus and tested the same at 2500 psi.
•Started pumping water through annulus line to make the gas wet to prevent fire.
•Attempted to kill the well dynamically by pumping 50 m3 mud of sp. gr. 1.6gm/cc at high rate but no
success.
•The blowing stream was continuously cooled by pumping water through annulus as well as through fire
monitor of fire services to keep the gas wet.
2
•A plan was made to change the Pipe ram with blind rams in the lower cavity.
•Changed the pipe rams with blind rams in the lower cavity under full water umbrella and with
utmost safety.
•Closed the rams and observed flow reduced considerably.
•Pumped 10 m3 water from annulus followed by 40 m3 mud of Sp. Gr. 1.6 at very high rate, flow got
reduced drastically but well could not be controlled as sealing area of ram cavity of the BOP got cut
due to the severe flow.
3
•Plan was made to change the damaged BOP with a 7 1/16" HCR Valve to cap the well. A CMT
meeting was held in the Morning to put the capping operation with micro planning on paper and
assigning the duties to CMT members.
•Four teams were made to carry out the different jobs simultaneously in assigned sequence of
operations. Role of each person was defined to avoid any confusion at the time of actual operation.
In between the total operation two safety meetings were planned to carry out the capping
operation with utmost safety and competently.
•Well continued to blow gas and water and was cooled by water jets and by pumping water through
annulus
•During blow out control operations while working for changing the damaged BOP to cap the
blowing well, suddenly well caught fire at about 12.30 hours.
•Four CMT personnel and five crane and rig crew sustained burn injuries, they were immediately
given first aid and were sent to hospital. Subsequently seven people were shifted to a burns
specialty hospital by ICU on wheels to Mumbai.
75. P a g e | 74
4
•Preparation to control blowing well with fire started immediately and blow out control equipment were
mobilized from RCMT Vadodara and Rajahmundry.
•Two International Blowout control experts from M/S Boots & Coots were mobilized to advise CMT
ONGC to carry out further safe blow out control operations.
•Simultaneously preparation of relief well started as standby option other than top intervention for
capping,
•As the well caught fire it damaged the structure and mast of the rig, in this condition to control the well
it was essential to remove all the debris lying around the well to access the blowing well.
•Started digging fire pits for water storage.
5
•Received blow out control equipment from RCMT Baroda which include 03 fire pumps, Athey wagon,
Bulldozer, sand cutter etc.
•Two Nos fire pits for water storage were dug having total capacity of 3500 m3.
•Placed the three pumps and all the fire monitors were installed with heat shield after fabrication of
manifold.
•OSD (T&FS) inspected the well by going close to the well under water umbrella.
6
• Debris removal operation started under heavy water umbrella.
•Removed the crane, mast, rig carrier, mud pumps, tanks and ell the bunk houses and fallen stands of
pipes.
•Removed Huge pile of damaged pipe stands & tubing stands, Koomey unit, Generator & its electrical
control panel.
•Placed two more fire pumps and made it operational-
7
•Assembled the Athey wagon and fabricated the rack arrangement and assemble the same.
•Athey wagon was taken from staging area to blowout site and kept at e strategic position.
•While removing the sub structure, with the help of Athey wagon the pumping line from annulus to
cementing unit got snapped and flow started from annulus also horizontally.
•Cut the frames of substructure with the help of oxy-lance magna rod cutting and removed the same.
•The entire operation was carried out under heavy water umbrella and within a distance of about 2 to 3
meters from the well.
8
•Well bridged and fire stopped at hours on 30 April. Observed feeble fire. Put off the fire.
•Inspected the Well head closely and removed remaining debris around it.
•Removed old annulus valve and installed new valves on both side of tubing spool.
•Prepare annulus pumping line to cementing unit. Tested the line at 3000psi.
•Suddenly observed fierce flow of gas from kill side valve of tubing spool.
•Closed the valve and started pumping. Pumped 7 m3 of 1.12 mud and kill the well.
•Placed the accumulator unit at a safe distance end charged up to 3000psi.
•Cut the studs of damaged BOP and removed the same.
•Capped the well successfully by installing pre- tested 7 1/16’’ double ram BOP fitted with two blind rams,
closed the Lower Blind rams and secondary control was restored.
76. P a g e | 75
CASE STUDY – 2
1
•Well was subdued with 1.05 sp gr. High viscosity bentonite gel and the X-
MAS tree was removed for installation of 7 1/16” BOP.
•Observed well flow, rig crew tried to tighten the X-MAS tree but the
intensity of flow increased.
•Well was flowing dry gas vigourously, the fire tenders were mobilized to
spray water on the gas flow to avoid fire.
•The area was cordoned off.
•Gas blowout at well RO #9 was reported at 20.30 hrs
2
•Team CMT reached the site at 1430 hrs.
•line was laid from well to cementing unit.
•Plan was to pump water followed by mud to control the well.
•When mud was pumped it came out immediately from X-MAS tree flange
•Observed no mud flow from crown valve
3
•The blowout was controlled in the shortest possible time of 6 days.
•The well was capped by in- house expertise before arrival of M/s Boots &
Coots.
•Utmost safety precautions taken have resulted in no fire and no injury
78. P a g e | 77
1. ONGC-Well Control Training Manual.
2. Schlumberger-Well Control Manual.
3. Sedco Forex-Well Control Manual.
4. Rigtrain – Well Control for the Drilling Team.
5. Aberdeen Drilling Schools and well control training center – well control
for the rig site drilling team.
6. Heriot Wyatt University- Drilling engineering.