SUPPLEMENT Well Control for Drilling Operations Workover & Completion for Drillers Core Curriculum and Related Learning Objectives

Transcription

1 SUPPLEMENT Well Control for Drilling Operations Workover & Completion for Drillers Core Curriculum and Related Learning Objectives Form WSP-02-DO-SU-WOC-D Revision 0 13 February 2015 DC 2015 COPYRGHT PROTECTED DOCUMENT ll rights reserved. No part of this document may be distributed outside of the recipient s organization unless authorized by the nternational ssociation of Drilling Contractors.

2 Contents 1.0 Course Overview Curriculum ntroduction to Workover and Completions for Drilling Operations Completion and Workover Fluids Well Completion and Workover Equipment Workover Well Control Practices and Kill Methods Complications Page 2 of 13

3 1.0 Course Overview The purpose of this course core curriculum is to identify the well control body of knowledge and set of job skills needed by drilling personnel who may be engaged in completion and workover operations. The curriculum is designed to supplement the Drilling Operations Driller-level course. cceptable Delivery Methods: nstructor-led training for the initial and repeat delivery of this Supplement is required, along with a knowledge assessment. Simulator or live well exercises are also required; however, simulator assessment is not required for this supplement. Minimum Course Length: Eight (8) hours are required for teaching the core curriculum. Course length includes simulator exercises, but excludes the knowledge assessment time. Maximum knowledge assessment time is forty-five (45) minutes. Course Curriculum Notes: The curriculum that follows includes four components: Sub-modules, M, Learning Topics, and Learning Objectives and ssessment Guidelines. M: The M letters indicate the level of knowledge and skills required at the job level. The codes used in the M column are as follows: = wareness of Learning Topic = mplementation of the Learning Topic at this job level; needs an increased level of knowledge because they may have to take action on some task related to the topic. M = Mastery of Learning Topic at this job level; needs a full knowledge because they have to take action, perhaps unsupervised, on some task related to the topic. Learning Topics: This section provides guidance for instructors on what the trainee should learn. Learning Objectives and ssessment Guidelines: This section defines what trainees should be able to do at the conclusion of the training and gives guidance on the assessment process, whether theoretical or practical, by providing examples of assessment content and expectations. Page 3 of 13

4 2.0 Curriculum 2.1 ntroduction to Workover and Completion for Drilling Operations Module Name: 2.1 ntroduction to Workover and Completion for Drilling Operations Describe the purpose of conducting a workover or Objectives of workover and completion completion (for example, initiates, improves, or restores operations. production). ntroduction to Workover and Completions Differences Between Drilling Operations and Workover / Completion Operations M Different workover activities and types. Completion activities and types. Differences in workover and drilling activities that could result in a loss of containment. Describe the different types of activities that may occur during a workover in order to accomplish the objective (for example, wellbore activities: acidizing, fracking, sand clean out and removal, recompleting in new reservoir, scale, or paraffin removal, control water, sidetrack or deepen, plug and abandon; equipment activities: removal or addition of tools, mechanical repair of worn or damaged equipment, pump change, clean perforation, or skin damage). Describe the different types of activities that may occur during a completion in order to accomplish the objective (for example, perforating, fracking, acidizing, flowing, reservoir test, openhole vs. cased-hole completion techniques). Describe the primary differences between workover/completions and drilling (for example, fluid differences, downhole equipment (plugs, packers, flowthrough valves), shut-in considerations, formation pressures, depleted reservoirs, damage to tubing/casing, open hydrocarbon reservoir, fluid column characteristics). Page 4 of 13

5 2.2 Completion and Workover Fluids Module Name: 2.2 Completion and Workover Fluids Friction loss in the different well sections. Describe frictional losses in different well sections (slimhole, tight tubing/casing clearances). Explain how downhole tools/equipment affect friction and fluid flow. Friction Describe the friction losses in the circulating system and Reverse Circulation method. the resulting well pressures when reverse circulating. Effect of friction on bottomhole pressure. Explain the effect on bottomhole pressure when circulating with tools, equipment. Types of fluid. Describe the different types of brine and completion fluids (water-based, oil-based mud/synthetic based mud). Completion and Workover Fluids M Purpose of fluid. Describe the purpose and characteristics of fluids that make them suitable for workover and completions (for example, compatibility with the zone; pressure control). Purpose of packer fluid. Describe the purpose of packer fluid in a completion. Explain solids carrying capacity of brines with viscosifiers M Solids carrying capacity. and without viscosifiers (for example, brines without viscosifiers have poor solids transport capacity, lower than that of drilling fluids). Brine Characteristics M Gas migration in brines. Density and composition. Temperature and pressure. Crystallization. Explain gas migration in brines (for example, gas migrates at a much higher rate in brine than in viscous drilling fluid). Explain how various salt compositions affect the density range (for example, sodium chloride brine solutions can be weighted up to 10.0 ppg before saturation is reached. Describe the effect of temperature and pressure on brine density. Explain the causes of brine density loss and the effect on the well. Page 5 of 13

6 Module Name: 2.2 Completion and Workover Fluids Saturation. Describe brine saturation and the limitations of different salts used. 2.3 Well Completion and Workover Equipment Module Name: 2.3 Well Completion and Workover Equipment Show how the wellhead, tubing hanger, and Christmas Surface equipment. Barrier tree act as a barrier to flow. M Management dentify the steps and barriers used to isolate the well BOP or Christmas tree removal. prior to removing a BOP or Christmas tree. dentify primary components of a Christmas tree and their M Christmas tree components. purpose (for example, tree-cap; why use of a secondary master valve is important). Choose the appropriate locations of the equipment. Christmas Tree dentify pressure-sealing components and explain when (Valves, Tees, these components should be tested as a barrier (for Gauge Panels, Pressure testing. example, explain why a wing valve may need to hold Tree Caps, pressure during a Bullhead). Chokes, Surface Safety Valves) dentify the pressure rating, mechanical limits, and limits Pressure limitations. based on the condition of equipment. Summarize how equipment may be degraded after service exposure. Metallurgical composition. Recall that different trim types have different service limits (for example, is a trim type). Page 6 of 13

7 Module Name: 2.3 Well Completion and Workover Equipment Ring seals and O-ring seals. Describe the type of seal created by: 1. a ring gasket between connections, and 2. O-ring seals between other components (for example, ring gasket seals provide a metal-to-metal seal and require compression; O-ring seals do not require compression and typically have shorter service life). Tubing hangers and wellhead bowls. Explain the purpose of a tubing hanger and wellhead bowl (for example, access to the annulus for pressure monitoring, chemical injection, barrier to flow for the annulus and possible barrier to the tubing). dentify test ports and voids that are tested to verify a Tubing Hangers Testing tubing hanger seals. tubing hanger seal. and Wellhead Bowls Subsurface Equipment Types of tubing hanger and wellhead bowl annulus seals. Control lines, electric submersible pump cables and other components penetrating tubing hangers. Name types of tubing hanger and wellhead bowl annulus seals, and identify the correct uses of each (for example, elastomer seals; metal to metal seals). ndicate where tubing hangers must hold pressure (including around this external equipment). Downhole equipment recognition. Match downhole equipment to the correct name. M Pressure isolation. dentify various downhole components that provide pressure isolation (packers, subsurface safety valve (SSSV), plugs, completion equipment, retrievable bridge plug (RBP), surface controlled subsurface safety valve (SCSSSV), wireline plugs, tubing, etc.). Explain how subsurface equipment provide pressure isolation (for example, SCSSSV retains tubing flow when the wellhead is damaged by shutting a flapper). Testing of downhole equipment. Give examples of how to test downhole equipment to confirm it is a competent barrier. dentify limitations of downhole tests. Page 7 of 13

8 Module Name: 2.3 Well Completion and Workover Equipment Working pressure. dentify factors that affect working pressure ratings and limitations of subsurface equipment (for example, corrosion, wear, degradation, and burst rating). Subsurface complications. Describe where hazards may be present with downhole equipment (for example, trapped pressure under retrievable plugs; variation of thread types and correct matching of threads; correct rental equipment selection to match rig and completion equipment; testing limitations). dentify how to mitigate hazards. Definition of removable wellhead equipment. Define removable wellhead equipment. Removable wellhead equipment. Explain what valve removal plugs, two-way checks, and backpressure valves are and where they are located on a tree or wellhead. State reasons for using removable wellhead equipment; Removable pplications. state when it could be used versus should not be utilized. Wellhead Equipment Describe the key components of a lubricator and how a Lubricator tools. lubricator may be used to pull or retrieve removable wellhead equipment. dentify when trapped pressure may be present prior to Safe removal of wellhead equipment. removal of wellhead equipment and demonstrate the ability to check for trapped pressure. Page 8 of 13

9 2.4 Workover Well Control Practices and Kill Methods Module Name: 2.4 Workover Well Control Practices and Kill Methods Maintaining a fluid column. dentify reasons why keeping the hole full in workover or completion may not always be an option. Hole fill and fluid loss. Choose the correct action to take if filling the hole does not maintain enough hydrostatic (for example, losses of 10 bbl/hr are acceptable but any losses above 60 bbl/hr on a certain job may require a lost circulation material pill). Practices Explain the importance of tracking losses when unable to Tracking fluid loss. maintain fluid level. Demonstrate the ability to shut in the tree at the proper Shut-in procedures for tree components. location (for example, using the crown valve to isolate wireline lubricator). Choose correct procedures for shutting in on downhole Shut-in procedures. equipment and completions (for example, kill stand, blind shear ram, drop the string). dentify conditions when Bullheading may be preferred to Reasons for using the Bullheading method. circulation (for example, toxic gas present; unable to handle influx at surface; potential to exceed equipment limitations if circulated to surface). Describe the basic principles of Bullheading (for example, Basic principles. push the formation fluid back into the formation). Bullheading Explain how the rate of gas migration affects the chosen Effect of gas migration. Bullhead rate (for example, circulating rates must overcome the rate of migration). Formation limitations. Describe how a Bullheading operation can fracture the formation (for example, hydrostatic pressure plus surface pressure can exceed formation strength and thereby fracture the formation). Page 9 of 13

10 Module Name: 2.4 Workover Well Control Practices and Kill Methods Mechanical limitations. Determine the weakest mechanical link in a Bullheading operation Summarize how to mitigate a mechanical issue (for example, place pressure on the annulus to assist in burst). Calculating Bullhead volume. Calculate the volume needed to Bullhead and kill the well. Determining if Bullheading was a success. Explain the difference between trapped pressure post Bullhead and a well in which hydrostatic is not sufficient to kill the well. M Flow paths and barriers. dentify the flow paths of kill fluid during a Bullhead operation and the barriers restricting flow elsewhere. Volumetric Techniques and Lubricate (Lube) and Bleed Detecting initial injection (break over) and Kill Mud Weight (KMW) hitting the perforations. pplying the Volumetric technique to a workover kill. pplying the Lube and Bleed technique to a workover kill. Distinguish between rising surface pressure and injection. Demonstrate the ability to respond to lack of injection and KMW hitting the perforations. Explain the main differences between the Volumetric technique during drilling phase and during workover (for example, fluids in the well, gas migration rates, well configuration, potential leak paths). Explain the main differences between a Lube and Bleed technique during drilling phase and during workover (for example, fluids in the well, well configuration, reducing pressure to a level for Bullheading). Page 10 of 13

11 Module Name: 2.4 Workover Well Control Practices and Kill Methods Explain the main differences between a normal circulation kill technique during drilling phase and during workover pplying Normal Circulation method to a (for example, potential for greater friction, uncertainty of a workover kill. clear flow path, integrity of circulating path, different wellbore fluids). Constant Bottomhole Pressure Methods (Forward and Reverse Circulation) pplying Reverse Circulation method to a workover kill. Explain the main differences between a normal circulation kill technique during drilling phase and a reverse circulating technique during workover (for example, position of choke in the circulating path, startup procedure, tubing string friction, different fluids in the well, integrity of circulating path). Page 11 of 13

12 2.5 Complications Module Name: 2.5 Complications Trapped pressure. Explain the occurrence of trapped pressure in a workover operation and give examples of where this may occur. Explain and give examples of common failed barriers and mechanical parts occurring during workover. Explain and give examples of how to mitigate failed Workover issues resulting from mechanically barriers and mechanical parts (for example, a hole in the degraded equipment. tubing that leads to formation communication between the tubing/casing annulus; seals or packer leak; poor cement condition or placement). Workover Complications ccuracy of well records. mportance of proven barriers. Explain the importance of accurate well records to the workover operation (development and execution of the plan); List potential data issues with well records and how these inaccuracies can affect the workover plan and execution (for example, lost sinker bars; wireline or other tools left in the hole and never reported; incorrect depth correlation; perforations out of zone or in the wrong place; bridge plugs or cement dumped in the wrong place; debris; inaccurate old surveys). Explain the importance of proving a barrier has pressureretaining capability (for example, never assume a well barrier has integrity until tested; well conditions or data accuracy can mislead rig crews into believing they have barrier integrity; having contingency plans if the barriers installed are not holding pressure or fail during a workover; understanding of maximum pressure that could be trapped below a shallow plug if a lower plug fails). Page 12 of 13

13 Module Name: 2.5 Complications Hydrates their formation and hazards. ndicate where hydrates may form, how pressure and temperature influence hydrate formation, and the hazards they present (for example, trapped pressure, equipment blockage). Paraffin / sphaltenes. Describe where paraffin / asphaltenes are found and the problems they can cause (for example, commonly found in older oil producing wells; prevent wireline tools from being run in the hole; plug up valves and surface equipment). Scale. Explain the problems scale can cause and the potential for contamination and other associated risk. Page 13 of 13