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(1)RD. ILLIN G S. C. CE. NTRE. OL S •. • ABE. N DR. HO. ON. C. & Well Control Training Centre. L & WEL. ABERDEEN DRILLING SCHOOLS. EE. TROL TRAININ. G. WELL INTERVENTION PRESSURE CONTROL. Written and Published by Aberdeen Drilling Schools Ltd..

(2) OL S • NTRE. CE. LC. ON. TROL TRAININ. FOREWORD Well pressure control is the most critical consideration in the planning and performing any well servicing operation. The awareness of well pressure control in the prevention of injury to personnel, harm to the environment and potential loss of facilities, must be fully appreciated by planning engineers and well site personnel. This appreciation must include a sound knowledge of legislative requirements, completion equipment, pressure control equipment and operating practices and procedures. ‘Well Intervention’ and ‘Workover’ are commonly used terms to describe servicing operations on oil and gas wells and which have, in the past, had many different interpretations. However, in general,‘Workover’ describes well service operations on dead wells in which the formation pressure is controlled with hydrostatic pressure. Workover operations are carried out by a drilling rig, workover rig or Hydraulic Workover Unit (HWO) where the Xmas tree is removed from the wellhead and replaced by blow out preventor (BOP) equipment.‘Well Intervention’ is a term used to describe ‘through-tree’ live well operations during which the well pressure is contained with pressure control equipment.Well Interventions are generally conducted by wireline, coiled tubing or snubbing methods. Snubbing operations are now usually conducted with HWO units. This ADS course is designed to train personnel in Well Intervention Pressure Control. Well pressure control equipment used by wireline, coiled tubing and snubbing units is so termed as it must control well pressure during live well intervention operations. It significantly differs from BOP systems used on dead well workovers. As most well servicing is now carried out by these live well intervention methods, it is essential that these are fully addressed during this course. The term Well Control specifically applicable to drilling or dead well workover operations are not addressed in this manual. However, it is necessary to review Production Well Kill Techniques and have a thorough understanding of Pressure Basics to minimise risks involved when placing fluids in the well, whether it is to provide a barrier or when performing a well intervention activity. To have an understanding of well operations conducted by live well intervention methods and the associated pressure control equipment, it is first necessary to have, or obtain, a basic knowledge of completion designs, completion equipment, practices, well service methods and their applications. An overview of these activities is given in the manual with a multitude of exercises the student can work through to review their knowledge. Training in well intervention well pressure control is an essential part in ensuring the competence of personnel involved in the planning and carrying out of live well servicing operations.The Aberdeen Drilling Schools Ltd. WELL INTERVENTION PRESSURE CONTROL TRAINING COURSE and course materials intend to provide this essential knowledge in order to help delegates to obtain an IWCF (International Well Control Forum) certificate in Well Intervention Pressure Control.. © ABERDEEN DRILLING SCHOOLS 2001. C HO. RD. ILLIN G S. • ABE. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. G.

(3) RD. ILLIN G S. C. C. ON. IWCF WELL INTERVENTION PRESSURE CONTROL. CE. L & WEL. NTRE. OL S •. • ABE. N DR. HO. EE. TROL TRAININ. G. AIMS AND OBJECTIVES The overall aim of the course is to provide a delegate with the theoretical skills essential in applying well pressure control during well intervention and servicing operations with the objective of improving the individuals knowledge and level of competence. AIMS The individual aims are to: • Provide an appreciation of completion types, equipment, equipment functions and practices as recognised by the industry. • Establish an increased awareness of well intervention/servicing well control equipment, methods and practices. • Furnish a student with a knowledge of legislative guidelines and standards. • Provide an awareness of how to discern well pressure control problems and apply solutions. OBJECTIVES The individual objectives are to assist the delegate to: • Improve his/her competence in well intervention pressure control. • Obtain IWCF certification. • Identify well pressure control problems from available well data i.e. pressure, volume and flow characteristic. • Identify solutions to various well pressure control problems. • Understand legislative guidelines and standards. • Determine if pressure control equipment is fit for purpose.. © ABERDEEN DRILLING SCHOOLS 2001.

(4) • ABE. RD. 1.. OVERVIEW OF COMPLETIONS. 1.1. INTRODUCTION. 1.2. CLASSIFICATION OF COMPLETIONS. 1.3. COMPLETION EQUIPMENT. ILLIN G S. C. OL S • NTRE CE. LC. ON. SECTION 1. N DR. HO. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. TROL TRAININ. G.

(5) • ABE. RD. 2.. WELL CONTROL METHODS. 2.1. GENERAL. 2.2. BARRIER THEORY. 2.3. WELL INTERVENTION PRESSURE CONTROL. ILLIN G S. C. OL S • NTRE CE. LC. ON. SECTION 2. N DR. HO. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. TROL TRAININ. G.

(6) • ABE. RD. 3.. REASONS FOR WELL INTERVENTION. 3.1. GENERAL. 3.2. TUBING BLOCKING. 3.3. CONTROL OF EXCESSIVE WATER OR GAS PRODUCTION. 3.4. MECHANICAL FAILURE. 3.5. STIMULATION OF LOW PRODUCTIVITY WELLS. 3.6. PARTIALLY DEPLETED RESERVOIRS. 3.7. SAND CONTROL. ILLIN G S. C. OL S • NTRE CE. LC. ON. SECTION 3. N DR. HO. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. TROL TRAININ. G.

(7) RD • ABE. 4.. WELL INTERVENTION SERVICES. 4.1. GENERAL. 4.2. SNUBBING / HYDRAULIC WORKOVER UNITS (HWO). 4.3. COILED TUBING UNITS. ILLIN G S. C. OL S • NTRE CE. LC. ON. SECTION 4. N DR. HO. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. TROL TRAININ. G.

(8) • ABE. RD. 5.. PREVENTION OF FORMATION DAMAGE. 5.1. FORMATION DAMAGE. 5.2. DAMAGE PREVENTION. ILLIN G S. C. OL S • NTRE CE. LC. ON. SECTION 5. N DR. HO. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. TROL TRAININ. G.

(9) • ABE. RD. 6.. PRESSURE BASICS. 6.1. FUNDAMENTALS OF FLUIDS AND PRESSURE. 6.2. FORMATION PRESSURE. 6.3. FORMATION FRACTURE PRESSURE. 6.4. FORMATION INTEGRITY TESTS. 6.5. MAXIMUM ALLOWABLE ANNULUS SURFACE PRESSURE - MAASP. 6.6. CIRCULATING PRESSURE LOSSES. ILLIN G S. C. OL S • NTRE CE. LC. ON. SECTION 6. N DR. HO. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. TROL TRAININ. G.

(10) • ABE. RD. 7.. PRODUCTION WELL KILL PROCEDURES. 7.1. WELL PREPARTATION. ILLIN G S. C. OL S • NTRE CE. LC. ON. SECTION 7. N DR. HO. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. TROL TRAININ. G.

(11) • ABE. RD. 8.. WELL CONTROL EQUIPMENT. 8.1. GENERAL. 8.2. SNUBBING OPERATIONS. 8.3. WIRELINE OPERATIONS. 8.4. COILED TUBING OPERATIONS. 8.5. SUBSEA WELL INTERVENTIONS. ILLIN G S. C. OL S • NTRE CE. LC. ON. SECTION 8. N DR. HO. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. TROL TRAININ. G.

(12) • ABE. RD. 1.. OVERVIEW OF COMPLETIONS. 1.1. INTRODUCTION. 1.2. CLASSIFICATION OF COMPLETIONS. 1.3. COMPLETION EQUIPMENT. ILLIN G S. C. OL S • NTRE CE. LC. ON. SECTION 1. N DR. HO. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. TROL TRAININ. G.

(13) NTRE. CE. ON. TROL TRAININ. OVERVIEW OF COMPLETIONS. 1.1 INTRODUCTION In combination with the disciplines of geology, geophysics, and geochemistry, the usual purpose of drilling a well is to establish the subsurface location of hydrocarbon reservoirs.The term ‘completion’ is derived from the operation to complete a well for production after it has been successfully drilled. Dependent upon the reason for a well to be drilled (i.e. wild cat exploration, appraisal or production) and the results of logging and/or well test results, the well will then be: i. ii iii.. Plugged and abandoned (as it has no further use i.e. a duster). Suspended as a future or possible production well. Completed as a production well.. In the early days, if the well was to be ‘completed’ (as in iii) above, the hardware installed, i.e. packer, tubing, Xmas tree and other accessories, was termed the ‘completion’.The purpose of completing a well is to produce hydrocarbons to surface production facilities. Commercial reasons demand that this is achieved in an efficient, cost effective and safe manner throughout the producing life of the well. Completing a well consists of a series of operations that are necessary to enable a well to produce (and to sustain the production of) hydrocarbons following the installation and cementing of the casing. Well completion operations include: • • • • • • •. Perforating. Sand control. Production packer installation. Tubing (completion) string / tubing hanger installation. Downhole safety valve installation. Xmas tree installation. Bringing the well onto production.. Well servicing methods must be considered as a fundamental element in the planning and completion design process. For example, early measurement of formation parameters (porosity, permeability) may indicate the need to stimulate (fracturing, acidising) a well to enhance the production rate. An appropriate completion design must cater for these and any future possible well servicing operations, both planned and unplanned. Similarly, subsea completions will necessitate operations such as flowline and surface safety valve installations. It should be emphasised here that such completion operations are not independent and the engineer needs to understand the basics in every area to be most effective in producing a completion design to cater for all contingencies. An engineer, when considering completion options, should adopt a realistic approach to the overall project economics i.e. the cost of the equipment, service life, type of servicing and respective rig time etc. In general, the ideal completion is the lowest cost completion which will meet the demands placed on it during its producing life. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. RD. ILLIN G S. HO. 1.. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-1. G.

(14) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. In reality, many unforeseen problems can arise due to the initial available data being deficient and it is commonly seen that subsequent completion designs on a field are developed as the data base increases. 1.2. CLASSIFICATION OF COMPLETIONS Even though different types of wells present distinct design and installation problems for the engineer, most completion types are simply variations on a few basic designs, therefore the equipment installed is generally similar. Completions may be classified with respect to the following. Reservoir/Wellbore Interface In the absence of formation damage, this determines the rate at which well fluid is transferred from the formation to the wellbore. The types of completion involved here are: • • • •. Open hole completions. Uncemented liner completions. Perforated liner completions. Perforated casing.. Mode of Production This relates to the way well fluid is transferred from the wellbore at the formation depth to the surface, i.e.: • •. Flowing. Artificial lift.. Number of Zones Completed This effectively governs the volume of hydrocarbons recoverable from a single bore hole: • •. Single. Multiple.. Figure 1.1 indicates the types of completions and various methods used to produce well fluid to surface.. 1-2. © ABERDEEN DRILLING SCHOOLS 2002.

(15) • ABE. RD. Multiple Zone. NTRE. CE. ON. TROL TRAININ. Interval segregation Concentric String Multiple Strings Twin String, Dual Completion. Single Zone. Single String, Dual Completion. Interval Co-Mingling Standard. Artificial Lift. Mode of Production. Plunger Lift Gas Lift Hydraulic Pump. HighPressure Temporary, simple, low cost Tubingless. Internal Gravel Pack Standard. Uncemented Liner. Perforated Liner. Perforated Casing. High Rate Liner. External Gravel Pack Pre Packed Screen Wire Wrapped Screen Slotted Pipe. Open Hole. Vertical/ Deviated Wells. Flowing (Single String). Rod. Horizontal Wells (See figure 1.13). Interface Between Wellbore and Reservoir. COMPLETIONS. Electric Submersible Pump. Figure 1.1- Classification of Completions for Vertical or Deviated Wells. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. Number of Zones Completed. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-3. G.

(16) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. 1.2.1 Classification by Reservoir/Wellbore Interface Open Hole Completions In this type of completion the casing is set in place and cemented above the productive formation(s). Further drilling extends the wellbore into the reservoir(s) and the extended hole is not cased; See Figure 1.2. This completion method is used where it is desirable to expose all zones to the wellbore. Producing formations must be of firm rock which will remain in place during production. Open hole completions are also referred to as ‘barefoot’ completions. Advantages of Open Hole Completions are: • • • • • • •. The entire pay zone is open to the wellbore. Perforating cost is eliminated. Log interpretation is not critical since the entire interval is open to flow. Maximum wellbore diameter is opposite the pay zone(s), hence gives reduced drawdown. The well can easily be deepened. Is easily converted to liner or perforated casing completion. Minimal formation damage is caused by cement.. Cement. Cement Production Casing. Formation. Formation. Figure 1.2 - Open Hole Completion Schematic. 1-4. © ABERDEEN DRILLING SCHOOLS 2002.

(17) NTRE. CE. ON. TROL TRAININ. Disadvantages of Open Hole Completions are: • • • • • •. The formation may be damaged during the drilling process. Excessive gas or water production is difficult to control because the entire interval is open to flow. The casing may need to be set before the pay zone(s) are drilled and logged. Separate zones within the completion cannot be selectively fractured or acidised. Requires frequent clean out if producing formations are not consolidated. May be difficult to kill if installed in a horizontal well for well servicing or workover or abandoned purposes.. Limitation of Open Hole Completions are: • •. Unsuitable to produce pay zones with incompatible fluid properties and pressures. Mainly limited to Limestone formations.. Uncemented Liner Completions In some formations hydrocarbons exist in regions where the rock particles are not bonded together and sand will move towards the wellbore as well fluids are produced, this formation is usually referred to as being ‘Unconsolidated’. The use of uncemented liners (slotted or screened) act as a strainer stopping the flow of sand. Liners are hung off from the foot of the production casing and usually sealed off within it to direct any well flow through the liner bore. Various examples of uncemented liner operations implementing sand control are as follows: Advantages of Uncemented Liner Completions are: • • • • • •. Entire pay zone open to the wellbore. No perforating cost. Log interpretation is not critical. Adaptable to special sand control methods. No clean out problems. Wire wrapped screens can be placed later.. Disadvantages of Uncemented Liner Completions are: • • • •. The formation may be damaged during the drilling process. Excessive water or gas is difficult to control. Casing is set before pay zones are drilled and logged. Selective stimulation is not possible.. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. RD. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-5. G.

(18) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. Various examples of uncemented liner operations implementing sand control are as follows: a) Slotted Liner Slot widths depend on the size of the sand grains in the formation and are typically 0.01 ins. - 0.04 ins. (0.254 - 1.016 mm) wide; See Figure 1.3a b) Wire Wrapped Screens Liner is drilled with 3/8 ins - 1/2 ins. (9.53 - 12.7 mm) holes along its length and then lightly wrapped with a special V-shaped wire; See Figure 1.3b Uncemented liner completions are not used very often since: • •. Sand movement into the wellbore causes permeability (flow rate) impairment. Screen erosion can occur at high production rates.. These problems may be overcome by filling the annulus between the open hole and screen with graded coarse sand, i.e. gravel packing, which acts to support the open hole section as well as prevent formation sand movement. c) External Gravel Pack The open hole is enlarged to about twice its diameter and a liner is run. Correctly sized gravel is placed between the outside of the screen and the formation by using special gravel pack running equipment; See Figure 1.3c d) Pre-packed Screen A Pre-packed screen is constructed of an outer and inner wrapped screens with resin coated gravel placed between the screens. This gives a performance better than a wire wrapped screen but less that an open gravel pack. These are used when there may be difficulty in installing a gravel pack.. 1-6. © ABERDEEN DRILLING SCHOOLS 2002.

(19) C OL S •. • ABE. RD. ILLIN G S. HO NTRE. ON. CE. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. TROL TRAININ. G. Cement Liner Hanger. Production Casing. Slotted Liner. Unconsolidated Sand Formation. Unconsolidated Sand Formation. a) Slotted Pipe. Slotted Liner. Slotted Liner. Graded Gravel. b) Wire Wrapped Screen. c) External Gravel Pack. Resin Coated Gravel. d) Pre-packed Screen. Figure 1.3 - Uncemented Liner Completion Schematics. © ABERDEEN DRILLING SCHOOLS 2002. 1-7.

(20) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. Perforated Cemented Liner Completions In perforated cemented liner completions, the casing is set above the producing zone(s) and the pay section(s) drilled. Liner casing is then cemented in place which is subsequently punctured (perforated) by bullet-shaped explosive charges. These perforations are designed to penetrate any impaired regions around the original wellbore to provide an unobstructed channel to the undamaged formation. By using various depth measuring devices (i.e. casing collar locator, CCL) various sections of pay zone can be perforated accurately (excluding unproductive regions), avoiding the production of undesirable fluids (gas or water), or production from unconsolidated sections that might produce sand. The various methods of completing a well using perforated cemented liner operations are: • •. Single, See Figure 1.4, or multiple pay zones. Single or multiple pay sections.. Cement Production Casing Liner Cement. Formation. Liner Hanger Perforations. Formation. Figure 1.4- Perforated Cemented Liner Schematic. 1-8. © ABERDEEN DRILLING SCHOOLS 2002.

(21) NTRE. CE. ON. TROL TRAININ. Perforated Cemented Casing Completions In a perforated cemented casing completion, sometimes referred to as the ‘set through’ completion, the hole is drilled through the formation(s) of interest and production casing is run and cemented across the section. Again, this requires that perforations be made through the casing and cement to reach the zone(s) of interest and allow well fluids to flow into the wellbore. Methods of completing a well in perforated cemented casing completions are: a) Standard Perforated Cemented Casing See Figure 1.5a for a multiple pay zone completion. b) Internal Gravel Packs This is where the production casing is cemented. Perforation of the producing interval(s) is then performed and the perforations cleaned out. A screen is run and gravel is pumped into the casing/screen annulus and the perforation tunnels; See Figure 1.5b. NOTE:. Cased and perforated completions are the most common types of completions performed today since they offer selective pay zone (or pay section) perforating and enable selective stimulation.. Advantages of Perforated Casing or Liner Completions are: • • • • • • •. Is safer during well completion operations. Effect of formation damage is minimal. Excessive water or gas production may be controlled or eliminated. The zones can be selectively stimulated. The liner impedes sand influx. The well can be easily deepened. Is easier to plan for completing.. Disadvantages of Perforated Casing or Liner Completions are: • • • •. The wellbore diameter through the pay zone(s) is restricted. Log interpretation is critical. Liner cementation is more difficult to obtain than casing cementation. Perforating, cementing and rig time incurs additional costs.. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. RD. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-9. G.

(22) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. Cement Liner Hanger Perforations. Production Casing Screened Liner Graded Gravel. Formation. Formation. Formation. Formation. Formation. a) Standard. b) Internal Gravel Pack. Figure 1.5- Perforated Cemented Casing Schematics. 1.2.2 Classification-by Mode Of Production When the hydrocarbon reservoir can sustain flow due to its natural pressure, flow may be up the production casing string, up the tubing string, or both. Tubingless Completions Casing flow completions are a particularly low-cost method in marginal flow conditions such as low rate gas wells; See Figure 1.6a. NOTE:. 1-10. Casing flow completions are not normally used by most operators, primarily because the production casing is exposed to well pressure and/or corrosive fluids. Tubingless completions are potentially hazardous especially in offshore installations. As there is an increased risk of collision damage offshore and there is no facility to install downhole safety valves. The use of casing flow production methods are discouraged both offshore and onshore.. © ABERDEEN DRILLING SCHOOLS 2002.

(23) RD. NTRE. CE. ON. TROL TRAININ. Tubing Flow Completions Tubing flow completions utilise the tubing to convey well fluids to surface. Flow rate potential is much lower in tubing flow than in unrestricted casing flow completions. As well as for production, the tubing string can be utilised as a kill string or for the injection of chemicals. Tubing strings may also accommodate gas lift valves which essentially ‘gas assist’ well liquids to surface; these valves would be installed if formation pressure diminished considerably and natural drive ceased. By far the most common methods of completing a well is to use a single tubing string/packer system where the packer is installed in the production casing to offer casing protection, subsurface well control, and an anchor for the tubing. Examples of such completions methods are: • •. Simple low cost (temporary); See Figure 1.6b High pressure; See Figure 1.6c.. Other equipment commonly installed in the tubing string to facilitate a safer production system may be: •. Wireline Nipples. -. Permits The Installation Of Flow Controls Or Plugs.. •. Tubing Retrievable Safety Valve. -. For Emergency Well Shut-In.. •. Safety Valve Landing Nipple. Permits The Installation Of A Surface Controlled Sub-Surface Safety Valve (SCSSV) For Emergency Shut-In.. •. Flow couplings. -. Absorbs Erosion Caused By Turbulence And Abrasion.. •. Circulating Device. -. Fitted Above The Packer For Circulating Purposes. •. Tubing Seal Device. -. To Allow Tubing Movement.. A polished bore receptacle (PBR) in a liner hanger is often used in place of a packer, e.g. in a high rate liner or monobore completion; See Figure 1.6d. Refer to Section 1.3 for completion equipment.. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-11. G.

(24) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. High Rate Liner or Monobore These are utilised in deep wells where tubing/casing clearances are small and for high productivity wells where the use of a packer would restrict the flow of well fluids; See Figure 1.6d. In general, tubing and packer installations depend on the completion requirements and economic considerations.The completion engineer should consider the following factors for tubing/packer type completion installations: • Simplification of the completion for future well servicing operations (i.e. wireline, coiled tubing, snubbing etc.). • Optimum tubing size for maximum long term flow rate. • Future artificial lift needs. • Bottom hole pressure and temperature gauge survey hang off system. • Seal movement device to accommodate tubing elongation or contraction. • Availability of downhole circulating device. • Requirements for downhole corrosion inhibitor injection. • Requirements for downhole hydrate inhibitors. • Tubing-conveyed perforating (TCP) guns and/or through tubing guns for underbalanced perforating. • Fluids to be used i.e. drilling muds, completion fluid, wellbore fluid. • Well killing. The monobore completion was developed primarily for the North Sea area by operators to reduce the high cost of well servicing operations.The monobore, termed from the production liner and tubing having the same or similar size bores, allows much improved servicing capability by the use of ‘through tubing’ tools and services to conduct many operations which had previously required the tubing to be pulled from the well. A liner packer and PBR is used in place of the conventional type packer to maintain the fullest bore size. Some versions are ‘full bore’ completions to retain maximum bore size which are serviced with retrievable through tubing bridge plugs or nippleless wireline locks (such as the Halliburton Monolock system) that can be set in the tubing or liner bore.. 1-12. © ABERDEEN DRILLING SCHOOLS 2002.

(25) RD. NTRE. CE. ON. TROL TRAININ. Production Tubing Production Casing Gas Lift Valve Cement. Small Diameter Casing or Large Diameter Tubing. Retrievable Packer. Cement. No Go Wireline Seating Nipple. Perforations. Formation. b) Temporary Tubing. a) Tubingless. Chemical Injection Valve Permanent Packer Sliding Sleeve. Polished Bore Receptacle. Large Diameter Tubing. Millout Extension Perforated Joint. Sliding Sleeve Liner Hanger. No Go Nipple. Cement Liner. c) High Pressure. d) High Rate Liner. Figure 1.6 - Flowing Wells (Single String) Schematics. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-13. G.

(26) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. Artificial Lift When a reservoir’s natural pressure is insufficient to deliver liquids to surface production facilities, artificial lift methods are necessary to enhance recovery. Various artificial lift completions methods, See Figure 1.7, and their key completion considerations are: a) Rod Pump Lift These pumps consist of a cylinder and piston with an intake and discharge valve. Vertical reciprocation of the rod will displace well fluid into the tubing; See Figure 1.7a. These are utilised in low to moderate wells which deliver less than 2,000 BPD (318 m3/day). Key considerations are: • • • •. The annulus is open. A tubing anchor may be required. The pump diameter must be adequate. The rods must be properly sized.. b) Hydraulic Pump Lift Hydraulic pump lift is utilised in crooked holes, for heavy oils and variable production conditions that cause problems for conventional rod pumping. Three types of hydraulic pump exist to lift liquid: Piston. Consists of a set of coupled pistons, one driven by a power fluid and the other pumping the well fluid; systems exist for production up the annulus, See Figure 1.7b, or up the tubing.. Jet. Converts power fluid to a high velocity jet which pulls the well fluid up into the flow stream.. Turbine. Power fluid rotates a shaft on which a centrifugal or axial pump is mounted; See Figure 1.7c.. Key considerations are: • • • • • • •. 1-14. The number of flow conduits (production and power). Pressure losses in the power and return lines. Whether produced liquid can return up the casing. Lubricator access to pump-in jet or piston units. The large casing size required for turbine units. The power fluid/oil separation facilities required. The higher initial costs.. © ABERDEEN DRILLING SCHOOLS 2002.

(27) RD. NTRE. CE. ON. TROL TRAININ. c) Plunger Lift The plunger lift system, See Figure 1.7d, is a low rate lift system in which annulus gas energy is used to drive a plunger carrying a small slug of liquid up the tubing when the well is opened at surface. Subsequent closing of the well allows the plunger to fall back to bottom. Plunger lift is useful for de-watering low rate gas wells. Key considerations are: • • •. The tubing must be drifted prior to installation. The annulus is open to store lift gas. A nipple/collar stop must be installed to support a catcher and shock absorber.. d) Electric Submersible Pump (ESP) An ESP is used for moving large liquid volumes of low gas/liquid ratio from reservoirs with temperatures below 250˚F, e.g. water supply wells, high water cut producers and high deliverability undersaturated oil wells; See Figure 1.7e. Key considerations are: • • • • •. The annulus is open to atmosphere for gas venting (but not offshore). A special wellhead is required for cable sealing. Some cable protection is needed. Motor cooling must be adequate. The tubing size must be adequate to handle large volumes with minimum back pressure on the pump.. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-15. G.

(28) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. Rod Tubing. Plunger. Tubing Anchor / Packer. Pump Housing. Travelling Valve Fluid Level. Standing Valve. Standing Valve. a) Rod Pump. Pump Seat Nipple. b) Piston Pump. Turbine. Electric Cable. Liquid Load Pump. Standing Valve Bumper Spring. Pump. Tubing Stop. Intake Protector. Packer. Motor. c) Turbine. d) Plunger Lift. e) Electric Submersible Pump. Figure 1.7 - Pump and Plunger Artificial Lift Methods. 1-16. © ABERDEEN DRILLING SCHOOLS 2002.

(29) RD. NTRE. CE. ON. TROL TRAININ. e) Gas Lift Gas lift supplements the flow process by the addition of compressed gas which lightens the liquid head, reduces the liquid viscosity, reduces friction and supplies potential energy in the form of gas expansion; See Figure 1.8. Continuous gas lift is used to lift liquid from reservoirs that have a high productivity index (PI) and a high bottom hole pressure BHP. Intermittent lift is used in reservoirs that exhibit low PI/low BHP, low PI/high BHP, or high PI/low BHP. Liquid production can range from 300 - 4,000 bbls/day (48 - 636 m3/day) through normal size tubing strings. Casing flow can lift up to 25,000 bbls/day (3,975 m3/day). Key considerations are: • • •. Tubing size. The need for a packer. Setting depths for gas-lift valves.. Gas In Gas Lift Valves. Packer. b) Piston Pump. Figure 1.8 - Gas Lift. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-17. G.

(30) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. 1.2.3 Classification-by Number of Zones Completed Single Zone Completions Flowing wells that are equipped with a single tubing string are usually completed with a packer. Single zone completions include the downhole co-mingling of production from several intervals within a pay zone. Examples of single zone completions are shown in Figure 1.9, i.e.: a) Standard See Figure 1.9a. b) Interval Co-mingling See Figure 1.9b. At the design stage, the following options should be considered and possibly built into the completion: • • •. The optimum tubing size for maximum long term flow rate. Future artificial lift needs. Future well servicing operations.. Tubing. Packer. a) Standard. b) Interval Co-mingling. Figure 1.9 - Single Zone Completion Schematics. 1-18. © ABERDEEN DRILLING SCHOOLS 2002.

(31) RD. NTRE. CE. ON. TROL TRAININ. Multiple Zone Completions When a well encounters multiple pay zones a decision must be made either to: •. Produce the zones individually, one after the other, through a single tubing string and the annulus.. •. Complete the well with multiple tubing strings and produce several zones simultaneously.. •. Co-mingle several zones in a single completion.. •. Produce only one zone from that well and drill additional wells to produce from the other pay zones.. Examples of multiple zone completions are shown in Figure 1.10. a) Single String Dual Completion This is the most basic dual completion where production of the lower zone is up the tubing and production of the upper zone is up the casing/tubing annulus; See Figure 1.10a. b) Twin String Dual Completion Separate flow from each zone is maintained by the use of two tubing strings and two packers; See Figure 1.10b. NOTE:. With the installation of gas lift valves in the two tubing strings, artificial lift can be initiated at a later date.. c) Multiple String Completions Separate flow from each zone can be maintained by the use of three tubing strings and three packers; See Figure 1.10c. Such completions provide a method of individual zone production and can improve some field economics. However, in general, such completions are difficult to install and are usually too restrictive in regard to total well production, due to the small tubing sizes, to be economically attractive in most cases. Furthermore, the difficulty of carrying out future remedial well operations of such wells prevent their widespread use.. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-19. G.

(32) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. d) Concentric String Completions Concentric strings require less clearance and can often achieve a higher overall flow capability; See Figure 1.10d . The advantages of Multiple Zone Completions: • •. Some individual zone production. Reduced well cost.. Disadvantages of Multiple Zone Completions are: • • • •. Production casing is exposed to well pressure and corrosive fluids. Tubing can be stuck in place due to solids settling from the upper zone. The lower zone must be killed or plugged off before servicing can be done on the upper zone. The lower zone must be plugged off to measure any flowing bottomhole temperature associated with the upper zone.. NOTE:. Multi-zone completions not only provide the separation of various zones but also the separation of individual pay sections within a thick pay zone.. e) Annulus Configurations It is normal practice to identify an annulus configuration by an alphabetic progression from internal to external casing strings. The ‘A’ annulus is defined as the annulus within the production/liner casing. An active annulus refers to any annulus being used for circulation purposes. An inactive annulus refers a non-circulatable annulus e.g. any annulus formed between two strings of cemented casings. In the case of a well having an extra annulus between the production casing and the tubing, this annulus is identified separately e.g. a well on artificial lift using hydraulic pumping will have a ‘drive’ annulus.. 1-20. © ABERDEEN DRILLING SCHOOLS 2002.

(33) OL S • NTRE. ON. CE. LC. OVERVIEW OF COMPLETIONS. TROL TRAININ. Dual Packer. Packer. b) Twin String Dual. Concentric Tubing Strings Triple Packer. Single Packers. Blast Joint. c) Multiple String. d) Concentric String. Figure 1.10 - Multiple Zone Completion Schematics. © ABERDEEN DRILLING SCHOOLS 2002. C HO. RD. ILLIN G S. • ABE. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. a) Single String Dual. EE. 1-21. G.

(34) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. 1.2.4 Horizontal Completions In a vertical wellbore, the state of technology is such that it can be successfully cased, cemented, completed, producing zone or zones perforated and cleaned up, produced and, if the level of production is not economical, various means of stimulation (hydraulic fracturing, acidisation) used on the formation to increase productivity. By contrast, the drilling of horizontal wells and their subsequent study has indicated substantial increases in production rates as compared to unfractured vertical wells. As a result, there is now great incentive to investigate the technology required to drill, complete, test, stimulate and properly produce horizontal wells which, due to increased production, can lead to significant improvements in field economics. From the drilling point of view, horizontal wells are classified as having ultra-short, short, medium or long turning radii into a horizontal plane.The geometrical characteristics of such horizontal wells are given in Table 1.1. NOTE:. ‘Multi-zonal’ wells are prime candidates for horizontal completions as are formations that have naturally fractured networks from which large production increases can be expected; See Figure 1.11.. Figure 1.12 shows some of the methods used to complete horizontal wells. A classification of completions for horizontal wells is shown in Figure 1.13.. Type. Drilling Method. Turning Radius (Build-Up Radius). Horizontal Length. Ultrashort (drainhole). Waterjet. 1-2f (-). 100 - 200 ft.. Short. Whipstock. Curved drilling entry guide flexible drilling collars. 20 - 40 ft (-). 200 - 700 ft.. Medium. Downhole mud motor. Flexibleheavy weight drill pipe. 300 - 500 ft. (19 - 11 deg./100 ft.). 700 - 2,000 ft.. Long. Conventional drilling tools. 600 - 2,000 ft (10 - 3 deg./100 ft.). > 2,000 ft.. Table 1.1 - Geometrical Characteristics of Horizontal Well Completions. 1-22. © ABERDEEN DRILLING SCHOOLS 2002.

(35) RD. NTRE. CE. ON. TROL TRAININ. Oil Accumulations Wellbore. Figure 1.11 - Naturally Fractured Formations. Open Hole This is the most economical type of completion where removal of mud and debris from the horizontal section is the primary stimulation performed. If additional stimulation is required, tubing or coiled tubing can be run to TD, stimulation fluid spotted into the horizontal section and then pumped into the formation; See Figure 1.12a. Slotted Liner This type of completion is used in the possible event of hole collapse. It is used in reservoirs that will flow naturally and where no stimulation treatments are necessary; See Figure 1.12b. External Casing Packers These are used for control of a single interval in the whole horizontal section of a reservoir that has different zones producing hydrocarbons. They also control water production from selective zones. External casing packers and closeable ported subs are useful in controlling unwanted production from formations along the horizontal section; See Figure 1.12c. Packers of this type are commonly used to separate productive zones, either with or without cement. Similarly, because of the difficulty in cementing horizontal liners, many horizontal production strings are run without cementing. For uncemented liner completions, the application of rotation can be utilised to deflate the packer for retrieval.. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-23. G.

(36) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. a) Open Hole. c) Uncemented Liner. b) Slotted Liner. d) Cement Liner. Figure 1.12 - Some Methods of Completing Horizontal Wells. Fracture Stimulation In this type of completion production casing or liner is cemented into the horizontal section. After perforating, controlled stimulation treatments (matrix and fracture) can be performed efficiently; See Figure 1.12d. In a horizontal hole, the completion problems are more complex than in vertical wells. For example, any debris in the horizontal well bore will remain in situ and create an obstacle for moving tools or instruments. Similarly, gravity will have a profound effect on various tools in the horizontal section of the wellbore and effective centralisation and friction reduction is necessary by using roller stem. Completion equipment currently available is capable of working satisfactorily in a horizontal well with little or no modification. The main area requiring development is in coiled tubing conveyed tools (equivalent to wireline tools). Some advance has been made with the development of sliding sleeves, mounted in the horizontal section of wells, which can be opened and closed using a coiled tubing conveyed shifting tool. Similarly, coiled tubing manipulation tools exist for packer setting in horizontal sections. 1-24. © ABERDEEN DRILLING SCHOOLS 2002.

(37) RD. NTRE. CE. ON. TROL TRAININ. Interface Between Wellbore and Reservoir. Vertical / Deviated Wells. Horizontal Wells. See Figure 1.1. (l,m,s). (l,m) Uncemented Liner. Open Hole. External Casing Plaster. (l) Cemented Casing or Liner. l - long m - medium s - short. Slotted (l,m,s). Pre-packed (l,m). Gravel Packed (l,m). Figure 1.13 - Classification of Completions for Horizontal Wells. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-25. G.

(38) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. 1.2.5 Subsea Completions Offshore fields are increasingly being developed with subsea wells. In the early days subsea wells were extensively used as satellite wells only, usually located a distance away from the main production platform outside the normal reach limitations for deviated wells. Today entire fields can be produced through subsea wells to floating production systems or to nearby platforms on other fields. Subsea well top hole locations are generally clustered together (sometimes in a subsea manifold) to share production and control line facilities although single satellites are still occasionally used. Developing an offshore field with subsea wells is a very economic method but has a drawback from the completions point of view in that vertical access requirements for well servicing intervention will inevitably be high with the need to use a MODU (Mobile Offshore Drilling Unit) or other type of well servicing vessel. Some wells have been clustered under the floating production facilities to allow vertical re-entry from the vessel, thereby reducing servicing costs. Nowadays, the availability of long-service life tubing retrievable sub-surface safety valves (TRSVs) with all metal-to-metal technology minimise the need for mechanical servicing. 'Through flowline' (TFL) servicing (see Figures 1.14 &1.15) also reduces servicing costs and is especially useful on highly deviated wells. However, no matter the attractiveness of utilising TFL systems in completion design the operational complexity, rate restriction and cost, should not be underestimated and through experience most users of TFL have now abandoned it's use due to its associated problems. In a completed subsea well, high pressure losses can occur in the flowlines connected to surface production facilities and it is common to minimise this by incorporating gas lift valves or hydraulic pumping equipment in the completion. Subsea flowlines are also subject to substantial cooling which may result in poor oil flow properties and the requirement to install methanol injection systems in subsea components to minimise the risk of hydrate formation . Figure 1.16 shows a typical subsea wellhead arrangement.. 1-26. © ABERDEEN DRILLING SCHOOLS 2002.

(39) RD. NTRE. CE. ON. TROL TRAININ. Fig. 1.14 - Dual String, Driver-Assist Flowlines, TFL, Satellite Tree. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-27. G.

(40) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. Fig. 1.15 - TFL Pumpdown Components. 1-28. © ABERDEEN DRILLING SCHOOLS 2002.

(41) RD. OL S •. 14. NTRE. CE. ON. TROL TRAININ. Scrap view of corrosion cap running tool / corrosion cap stinger interface. 4 (Scale 1:2). 12. Corrosion Cap Running Tool P.No. 541081-A. 128.4" (3.3m) 114.3" (2.9m). 3. 8. 2. 6. 4 Injection Tree Assy P.No. 541010-A. 1. 1. 2. 3. I.L.M.. 2. 0 Feet Datum Top Of Wellhead. 0 Meter Datum. -2. -1 Permanent Guide Base P.No. 540869. -4. -6. Fig. 1.16 Typical Subsea Wellhead System. © ABERDEEN DRILLING SCHOOLS 2002. C HO. • ABE. ILLIN G S. 128.4" (3.3m). Alternative Arrangement Running Corrosion Cap On Drill Pipe. 10. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-29. G.

(42) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. 1.2.6 Subsea Well Interventions Subsea wells can be serviced by means of subsea workover systems. There are two systems in current use, one for conventional subsea trees (Figure 1.17) and the other for the newer generation of spool trees (horizontal tree, Figure 1.18). Each of these is described below : Conventional Subsea Well Interventions Conventional subsea well interventions are conducted through a subsea workover riser systems which are deployed from floating vessels or from jack-up rigs in shallower waters. Riser systems are attached to the top of subsea Xmas trees and, after completing the appropriate test procedures, allow live well servicing by wireline or coiled tubing methods. Pressure control is provided at surface by a Xmas tree fitted with a lift frame which accommodates the pressure control equipment installed on the top of the tree. Other than this, pressure control is exactly the same as that described in the previous sections except that vessel movement gives additional rigging up and operational problems. However, the workover riser system must also have subsea pressure control capabilities in the event of a emergency disconnection or a riser failure. Subsea pressure control is provided by a subsea lower riser assembly (LRA) and an emergency disconnect package (EDP) which can safely close in the well and disconnect the riser, with or without wireline or coiled tubing through the subsea tree, in the event of an emergency. These systems maintain the well in a safe condition until the problems arisen are overcome and the riser can be re-attached. Operations can then be recommenced and fishing operations initiated, if required. A typical subsea workover riser system is shown in Figure 1.19. Spool Subsea Tree Interventions Due to the capital costs of conventional workover riser systems, and the incompatibility between the various manufacturer's designs, this drove the industry to develop the spool tree and associated intervention systems utilising standard drilling rig subsea BOP riser systems. The subsea BOPs were utilised for connection to the tree and to provide pressure control in conjunction with a subsea test tree which latches onto the spool tree tubing hanger. Pressure is contained within the subsea tree and it's riser to the surface which is terminated with a surface test tree in the conventional well test fashion. The BOP rams are closed on the subsea test tree slick joint to provide a barrier to any well pressure below the BOPs. In the event of an emergency, the subsea tree can be closed, the subsea riser disconnected before the BOP shear/ blind rams are closed above the tree valve section and the drilling riser disconnected. The main problem thrown up by this method of well intervention was the lack of bore size in standard subsea test tree riser systems initially available which has driven the design of systems with bores sizes now up to 7 inches in diameter. Subsea test tree systems must have a cutting capability to sever any wireline or coiled tubing run through the BOPs. See Figure 1.20 for typical spool tree workover system. 1-30. © ABERDEEN DRILLING SCHOOLS 2002.

(43) • ABE. RD. Annulus Wing Valve. C OL S •. Annulus Swab Valve. ILLIN G S. HO. High Pressure Cap. NTRE. ON. CE. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. TROL TRAININ. G. Production Swab Valve Crossover Valve. Production Wing Valve Production Upper Master Valve. Annulus Master Valve. Production Lower Master Valve. Wire Line Plug Profiles. Fig. 1.17 - Classic Conventional Tree Configuration. © ABERDEEN DRILLING SCHOOLS 2002. 1-31.

(44) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. DEBRIS CAP WIRELINE PLUGS INTERNAL ISOLATION CAP WORKOVER VALVE CROSSOVER VALVE PRODUCTION MASTER VALVE. PRODUCTION ISOLATION VALVE ANNULUS ISOLATION VALVE. ANNULUS MASTER VALVE. Fig. 1.18 - Typical Horizontal tree Configuration. 1-32. © ABERDEEN DRILLING SCHOOLS 2002.

(45) RD. NTRE. CE. ON. TROL TRAININ. Fig. 1.19 - Typical Subsea Workover Riser System. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-33. G.

(46) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. Figure 1.20 - Typical Subsea Spool Tree Workover System. 1-34. © ABERDEEN DRILLING SCHOOLS 2002.

(47) RD. C OL S •. • ABE. ILLIN G S. NTRE. CE. ON. TROL TRAININ. 1.3 COMPLETION EQUIPMENT In general, a well completion should provide a production conduit which: • •. Maximises the safe recovery of hydrocarbons from a gas or oil well throughout its producing life. Gives an effective means of pressurising selected zones in water injection wells.. Downhole accessories used should be designed to provide the safe installation and retrieval of the completion, and flexibility for sub-surface maintenance of the well using wireline, coiled tubing or other methods. Even though different types of wells present distinct design and installation problems for engineers, most completions are just variations on a few basic designs types and, therefore, the equipment used is fairly standard. An overview of the equipment commonly used in single and dual string completions is given in the following sections. The detailed operation of some the items such as sliding side doors (SSDs), side pocket mandrels (SPMs) and packers will not be covered in this manual. However, the relative location of these tools in a completion and their functions in intervention work or workovers will be addressed. Figure 1.21 shows a schematic drawing illustrating the location of equipment in a typical oil well completion. Each common item in the completion string is described in the following sections.. © ABERDEEN DRILLING SCHOOLS 2002. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-35. G.

(48) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. Tubing Hanger Tubing SCSSV Control Line Production Casing. Flow Coupling SCSSV Landing Nipple Flow Coupling. Side Pocket Mandrel (SPM). SPM. SPM. SPM. SPM. Flow Coupling Sliding Side Door (SSD) Flow Coupling. Landing Nipple Pup Joint. Packer. Cross-Over Landing Nipple Perforated Joint Landing Nipple Pup Joint. Wireline Re-Entry Guide. Figure 1.21 - Typical Oilwell Completion. 1-36. © ABERDEEN DRILLING SCHOOLS 2002.

(49) RD. NTRE. CE. ON. TROL TRAININ. 1.3.1 Wireline Re-entry Guide A wireline entry guide is used for the safe re-entry of wireline tools from the casing or liner back into the tubing string. It attaches to the end of the production string or packer tailpipe assembly and has a chamfered lead in with a full inside diameter. Wireline re-entry guides are generally available in two forms: Bell Guide This guide has a 45 degree lead in taper to allow re-entry into the tubing of wireline tools. This type of guide, See Figure 1.22a, is used in completions where the end of the tubing does not need to pass through any casing obstacles such as liner laps. Mule-Shoe Re-entry Guide This type of guide is essentially the same as the Bell Guide but incorporates a large 45 degree angle cut on one side of the guide; See Figure 1.22b. Should the guide hang up on any casing item such as a liner lip while being run, rotation of the tubing will cause the 45 degree shoulder to slide past the liner lip and enter the liner.. 45 Chamfer. 45 Taper. a) Bell Guide. b) Mule Shoe Guide. Figure 1.22 - Wireline Re-entry Guide. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-37. G.

(50) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. 1.3.2 Tubing Protection Joint This is a normally a single joint of tubing installed for the particular purpose of providing protection for wireline installed bottomhole pressure and temperature gauges from buffeting in the flow stream. This protection joint is installed directly below the gauge hanger landing nipple in the tailpipe below the packer and must be long enough to accommodate the longest BHP toolstring which may be run. 1.3.3 Wireline Landing Nipples Landing nipples, See Figure 1.23, are short profiled tubulars installed in strategic positions in the tubing string into which various wireline retrievable flow controls can be set and locked. These can seal within the nipple bore, if required dependent upon the tools function. The most common tools run are plugs, chokes, and pressure and temperature gauges. The main features of a landing nipple are: • • •. Locking groove or profile. Polished seal bore. No-Go shoulder (only on non-selective nipples).. Landing nipples are supplied in ranges to suit most tubing sizes and weights with API or premium connections and are available in two basic types: • •. No-Go or Non-Selective. Selective.. No-Go or Non-Selective The non-selective nipple receives a locking device which uses a No-Go principle for the purposes of location.This requires that the OD of the locking device is slightly larger than the No-Go diameter of the nipple.The No-Go diameter is usually a small shoulder located below the packing bore (bottom No-Go) but in some designs, the top of the packing bore itself is used as the No-Go. Only one No-Go landing nipple of a particular size should be used in a completion string. In most completions other than monobores, it is common practice to use a bottom No-Go nipple as the last nipple in the packer tailpipe to prevent dropped tools falling into the sump. As the No-Go provides a positive location, they are widely used in high angle wells where wireline tool manipulation is difficult and weight indicator sensitivity reduced.. 1-38. © ABERDEEN DRILLING SCHOOLS 2002.

(51) RD. NTRE. CE. ON. TROL TRAININ. Selective In the selective system, the locking devices are designed with the same key profile as the nipples and the means of nipple selection is determined by operation of the running tool and the setting procedure. The selective design is full bore and allows the installation of several nipples of the same size. Uses of landing nipples: •. Well plugging from above, below or from both directions.. •. Pressure testing the tubing, leak finding.. •. Safety valves, chokes and other flow control devices.. •. Installation of bottomhole pressure and temperature gauges.. Orientation Groove Key Profile. Orientation Groove Key Profile. Seal Bore. Seal Bore Trash Groove No-Go Shoulder. 'X' Selective Landing Nipple. 'XN' No Go Landing Nipple. Figure 1.23- Halliburton Wireline Landing Nipples. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-39. G.

(52) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. 1.3.4 Perforated Joints In wells where flowing velocities are high, a restriction in the tubing, such as a gauge hanger, can cause false pressure and temperature readings.Also, vibrations in the tool can cause extensive damage to delicate instruments. To provide an alternative flow path, a perforated joint is installed above the gauge hanger nipple which allows unrestricted flow around the gauge toolstring eliminating these hazards.The perforated joint is normally a full tubing joint which is drilled with sufficient holes to provide a flow area greater than that in the tubing above. 1.3.5 Blast Joints Blast joints are installed opposite perforations (non gravel packed) where external cutting or abrasive action occurs caused by produced well fluids or sand.They are heavy-walled tubulars available usually in 10, 15, and 20 ft. lengths . They should be long enough to extend at least 4 ft. on either side of a perforated interval. 1.3.6 Packers A packer is a device used to provide a seal between the tubing and the casing. With a suitable completion string, this seal allows the flow of reservoir fluids from the producing formation to be contained within the tubing up to the surface. This protects the casing from being exposed to well pressure and to corrosion from well or injection fluids. A packer is tubular in construction and consists basically of: • •. Case hardened slips to bite into the casing wall and hold the packer in position against pressure and tubing forces. Packing elements which seal against the casing.. Figure 1.24 gives examples of typical packer installations and Figure 1.19 shows common types of packer. In general, packers are classified in three groups: • • •. Retrievable. Permanent. Permanent/Retrievable.. Packers may be further classified according to the number of bores required for production i.e. Single Dual Triple. 1-40. One concentric bore through the packer for use with a single tubing string. Two parallel bores through the packer for use with two tubing strings. Three parallel bores through the packer for use with three tubing strings.. © ABERDEEN DRILLING SCHOOLS 2002.

(53) RD. NTRE. CE. ON. TROL TRAININ. A typical packer description, therefore, might be: 95/8 ins. Dual 31/2 ins. x 31/2 ins. Hydraulicset Retrievable Packer. Retrievable Packers These are generally run into the wellbore on the production tubing string. As the name implies, retrievable packers can be recovered from the well after setting by pulling it with the tubing. Permanent Packers These are installed in the wellbore usually independent of the production tubing string. A permanent packer may be considered as an integral part of the casing. Permanent packers can only be removed from the well by milling operations. Permanent/Retrievable Packers As their name may suggest, these packers have the same characteristics as permanent packers but can be released and recovered from the well without milling. They will generally have a smaller bore than a permanent packer to accommodate the addition of some type of releasing mechanism. Packers, both retrievable and permanent versions, are installed in the production casing by one of the following methods: Mechanically ; Run on a workstring, is set by manipulation of the tubing i.e. by applying compression or tension in combination with rotation depending on the particular setting mechanism of the packer. NOTE:. Packers having rotation set/release mechanisms should not be used in highly deviated wells since the application of tubing torque may not be transferred downhole.. Hydraulically ; Can be run on a workstring or on the tubing string. When the desired setting depth is reached the tubing is plugged below the packer with a check valve, standing valve or a wireline plug and hydraulic pressure applied to the tubing to set the packer. Generally, a predetermined upward pull on the tubing string will release the seal unit from the packer with a Hydraulic Permanent packer system. On Electric Wireline ; This is generally restricted to permanent packers. The packer is attached to a wireline setting adapter, connected to a setting gun on the end of the wireline and run in the wellbore. On reaching the desired depth an electrical signal transmitted to the gun activates an explosive charge and, through a hydraulic chamber, provides the mechanical forces to set the packer.. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-41. G.

(54) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. Casing. Annulus Production Tubing. Packer. Producing Formation. Production Casing. Single Zone Completion Dual Packer. Short Tubing String. Long Tubing String Upper Formation. Single Packer. Lower Formation. Packer 1. Dual Completion. Zone 1. Packer 2. Zone 2. Packer 3. Zone 3 Single String Multi Zone Completion. Figure 1.24 - Examples Of Packer Installations. 1-42. © ABERDEEN DRILLING SCHOOLS 2002.

(55) RD • ABE. NTRE. CE. ON. TROL TRAININ. c) Permanent Packer. Figure 1.25 - Examples Of Common Types of Packers. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. b) 'RH' Single Bore Retrievable Packer. ILLIN G S. HO. a) 'RDH' Dual Bore Retrievable Packer. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-43. G.

(56) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. 1.3.7 Permanent Packer Accessories An important aspect in a completion with a permanent packer is the tubing/packer seal. As the packer in effect becomes part of the casing after it is set, the tubing must connect to the packer in a fashion so that it can be released.This connection whether it be a straight stab in, latched or otherwise, must have a seal to isolate the annulus from well fluids and pressures. This seal usually consists of a number of seal elements to cater for some wear and tear. These seal elements are classified into two groups; premium and non-premium.The premium group are those used in severe or sour well conditions i.e. H2S, CO2 etc. and are normally ‘V’ type packing stacks containing various packing materials resistant to the particular environment. The non-premium seals are for sweet service and can be either ‘V’ type packing stacks or moulded rubber elements. Locator Tubing Seal Assemblies Locator tubing seal assemblies, See Figure 1.26a and Figure 1.26b, are fitted with a series of external seals providing an effective seal between the tubing and packer bore. They also have a No-Go type locator for position determination within the packer. Locator seal assemblies are normally space out so that they can accommodate both upward and downward tubing movement induced by changes in temperature and pressure. Seal Bore Extensions A seal bore extension is used to provide additional sealing bore length when a longer seal assembly is run to accommodate greater tubing movement. The seal bore extension is run below the packer and has the same ID as the packer. Anchor Tubing Seal Assemblies Anchor tubing seal assemblies, See Figure 1.26c and Figure 1.26d, are used where it is necessary to anchor the tubing to a permanent packer while retaining the option to unlatch when required. Anchor latches are normally used where well conditions require the tubing to be landed in tension or where insufficient weight is available to prevent seal movement. Polished Bore Receptacles (PBRs) A PBR is simply a seal receptacle attached to the top of a permanent packer or liner hanger packer in which the seal assembly lands instead of the packer bore. As the PBR bore can be made larger than the packer, this provides a larger flow area through the seal assembly. See Figure 1.23 Tubing Seal Receptacles A TSR is an inverted version of a PBR where by a polished OD male member is attached to the top of the packer and the female (or overshot) is attached tubing. The seals are contained in the female member so that they are recovered when pulling the tubing. See Figure 1.24. 1-44. © ABERDEEN DRILLING SCHOOLS 2002.

(57) RD. NTRE. CE. ON. TROL TRAININ. No-Go Shoulder. "E" Spacer Seal Sub. "E" Spacer Seal Sub. b) Seal Extension. a) Locator Tubing Seal Assembly. "E" Anchor Seal Sub. Anchor Latch. Anchor Latch. "E" Spacer Seal Sub. c) “K-22” Anchor Seal Nipple. d) “EBH-22” Anchor Seal Assembly. Figure 1.26 - Permanent Packer Seal Accessories © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. "G" Locator Seal Sub. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-45. G.

(58) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. Connection. Debris Barrier Unit Shear Ring (Closed Position). Seal Units. Debris Barrier Unit. Debris Barrier Unit. Debris Barrier Unit. Connection. Figure 1.27 - Polished Bore Receptacle. 1-46. © ABERDEEN DRILLING SCHOOLS 2002.

(59) RD. NTRE. CE. ON. TROL TRAININ. Figure 1.28 - Tubing Seal Receptacle. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-47. G.

(60) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. 1.3.8 Sliding Side Doors (SSDs) Sliding Side Doors (SSDs) or Sliding Sleeves are installed in the tubing during well completion to provide a means of communication between the tubing and the annulus when opened; See Figure 1.29. SSDs are used to: • • •. Bring a well into production after drilling or workover by circulating the completion fluid out of the tubing and replacing it with a lighter underbalanced fluid. Kill a well prior to pulling the tubing in a workover operation. Provide selective zone production in a multiple zone well completion.. SSDs are available in versions which open by shifting an inner sleeve either upwards or downwards. A number of SSDs can be installed in a completion string and selectively opened or closed by the use of the appropriate wireline shifting tool. CAUTION:. Tubing and annulus pressures must be equalised before an SSD sleeve is opened to prevent wireline tools being blown up or down the tubing.. A common fault of sliding sleeves is that the seal failure usually leads to a workover although a pack-off can be installed as a temporary solution.. 1-48. © ABERDEEN DRILLING SCHOOLS 2002.

(61) Nipple O-Ring. 7. Split Ring O-Ring. NTRE. CE. TROL TRAININ. 1. Closing Sleeve. Female Adapter. • ABE. RD. 6. 2. 3 4. 5. 8 Female Adapter. 9. Female Adapter. 10. O-Ring. 7. Packing. 6. O-Ring. 4. Bottom Sub. 5. 11. Figure 1.29 - Sliding Side Door (SSD). © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. O-Ring. ON. 5. Female Adapter Packing. ILLIN G S. HO. Top Sub. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-49. G.

(62) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. 1.3.9 Flow Couplings Flow couplings, which are heavy-walled tubulars, are installed above and below any completion component which may cause flow turbulence such as wireline nipples, SSDs, SCSSV landing nipples etc., to cater for internal erosion.Although the same amount of erosion is experienced, the added thickness of the flow coupling provides enough material to prevent weakening over the projected life of the well. In lower velocity wells, such as low GOR oil wells, a flow coupling may only be needed to be placed above restrictions.. 1.3.10 Side Pocket Mandrels Side Pocket Mandrels (SPMs) were originally designed for gas lift completions to provide a means of injecting gas from the casing-tubing annulus to the tubing via a gas lift valve. However in recent times, they have also been commonly used in place of an SSD as a circulating device because seal failure can be rectified by pulling the dummy gas lift valve (or kill valve) with wireline and replacing the seals. SPMs are installed in the completion string to act as receptacles for the following range of devices: • • • • • •. Gas lift valves Dummy valves Chemical injection valves Circulation valves Differential dump kill valves Equalising valves.. It is essential to understand the operation of the device installed in an SPM before conducting any well intervention as it may affect well control. See Figure 1.24 for a typical SPM and Figure 1.31 for types of valves. Gas Lift Valves There are many different designs for gas lift valves for various applications. They range from being simple orifice valves to pressure operated bellows type valves. However, they all contain check valves to prevent tubing to annulus flow. These check valves may leak after a period of use and they should never be relied on as barriers in a well control situation.These should be replaced with dummy valves and the tubing pressure tested to confirm integrity. Dummy Valves These are tubing/annulus isolation valves. They are installed in place of the valves in order that the completion tubing string can be pressure tested from both sides during installation or when well service operations are required.. 1-50. © ABERDEEN DRILLING SCHOOLS 2002.

(63) RD. NTRE. CE. ON. TROL TRAININ. Chemical Injection Valves The injection valve is designed to control the flow of chemicals injected into the production fluid at the depth of the valve. A spring provides the force necessary to maintain the valve in the fail-safe closed position. Reverse flow check valves, which prevent backflow and circulation from the tubing to the casing, are included as an integral part of the valve assembly. Injection chemicals enter the valve from the annulus in an open injection system. (This requires the annulus to be full of the desired chemical. An alternative method is to run an injection line from surface to the SPM.) When the hydraulic pressure of the injected chemicals overcomes the pre-set tension in the valve spring plus the pressure in the tubing, the valve opens. Chemicals then flow through the crossover seat in the valve and into the tubing. Circulating Valves These are recommended to be installed in the SPM whenever any circulating is to carried out.The circulating valve is designed to enable circulation of fluid through the SPM without damaging the pocket.The valve allows fluid to be dispersed from both ends allowing circulation of fluid at a minimal pressure drop. Some valves permit circulation from the casing into the tubing only and others to circulate fluid from the tubing into the casing only. If a circulating valve is not used and the pocket is flow cut a workover would be necessary to replace the SPM. Differential Dump Kill Valves Differential dump/kill valves are designed to provide a means of communication between the casing annulus and the tubing when an appropriate differential pressure occurs. Below a preset differential pressure, the valve acts as a dummy valve since it uses a moveable piston to block off the circulating ports in the valve and the side pocket mandrel. The differential pressure necessary to open the valve will depend on the type and number of shear screws installed.The valve will only open when the casing annulus pressure is increased by the differential (of the shear screw rating) above the tubing pressure. An increase in tubing pressure above the casing annulus pressure will not open the valve. After opening, the piston is locked in the up position and fluids can flow freely in either direction.The hydrostatic pressure from the column of annulus fluid will kill the well and remedial operations can be planned. Equalising Valves The equalisation valve is designed to equalise pressure between tubing and casing and/or to circulate fluid before pulling the valve from the SPM. The valve has two sets of packing which straddle and pack off the casing ports in the SPM. The tubing and annulus are isolated from each other until the equalising device is operated by a pulling tool. Pressures equalise through a port before the valve and latch are retrieved.. © ABERDEEN DRILLING SCHOOLS 2002. C OL S •. • ABE. ILLIN G S. HO. LC. OVERVIEW OF COMPLETIONS. N DR. & WEL. IWCF WELL INTERVENTION PRESSURE CONTROL. EE. 1-51. G.

(64) ILLIN G S. C. C. ON. CE. L & WEL. NTRE. OL S •. • ABE. RD. N DR. HO. EE. TROL TRAININ. G. IWCF WELL INTERVENTION PRESSURE CONTROL OVERVIEW OF COMPLETIONS. "KBUG". Orienting Sleeve. Tool Discriminator. Latch Lug Upper Packing Bore. Pocket Lower Packing Bore. Section A - A Figure 1.30- Side Pocket Mandrel (SPM). 1-52. © ABERDEEN DRILLING SCHOOLS 2002.

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