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World Oilfield Forum

API Standard RP 53 Recommended Practice For Blowout Equipment

 

 

Contents of substraction from API Recommended Practice 53 Recommended Practice for Blow-Out Prevention Equipment.      
         
7.1.1 Surface BOP Arrangements      
7.4.1 Choke Manifold and Choke Lines Surface BOP Installations      
7.4.3 Kill Lines Surface BOP Installations      
7.9.9 Control System for surface BOP stacks.      
7.5.4 Trip tank Surface BOPs      
7.11.1 Testing and maintenance - surface BOP stacks and well control equipment.      
7.11.2 Surface BOP stack equipment.      
7.4.6 Chokes and choke manifolds for Surface BOP installations.      
7.11.2 Accumulator system for Surface BOP installations      
7.11.5 Blow-out preventers for hydrogen sulphide service.      
         
No. Instructions Comments and recorded values Standards and instructions
7.1.1 Surface BOP Arrangements      
7.1.1.1 Every installed ram BOP should have, as a minimum, a working pressure equal to the maximum anticipated surface pressure to be encountered.   API RP 53 chapter 6.2  
7.1.1.2 Ram type preventers should be equipped with extension hand wheels or hydraulically operated locks.   API RP 53 chapter 6.3  
7.1.1.3 Drilling spools for BOP stacks should meet the following minimum qualifications: a. 3K and 5K arrangements should have two side outlets no smaller than a 2-inch (5.08 cm) nominal diameter and be flanged, studded, or hubbed. 10K, 15K and 20K arrangements should have two side outlets, one 3-inch (7.62 cm) and one 2-inch (5.08 cm) nominal diameter as a minimum, and be flanged, studded, or hubbed. b. Have a vertical bore diameter the same internal diameter as the mating BOPs and at least equal to the maximum bore of the uppermost casing/tubing head. c.Have a rated working pressure equal to the rated working pressure of the installed ram BOP.   API RP 53 chapter 6.6.1 a,b and c  
7.1.1.4 For drilling operations, wellhead outlets should not be employed for choke or kill lines.   API RP 53 chapter 6.6.2  
7.4.1 Choke Manifold and Choke Lines Surface BOP Installations      
7.4.1.1 Manifold equipment subject to well and/or pump pressure (normally upstream of and including the chokes) should have a working pressure equal to or greater than the rated working pressure of the ram BOPs in use. This equipment should be tested when installed in accordance with provisions of Section 17 of API RP 53   API RP 53 chapter 8.2.a  
7.4.1.2 For working pressures of 3,000 psi (20.7 MPa) and above, flanged, welded, clamped, or other end connections that are in accordance with API Specification 6A, should be employed on components subjected to well pressure.   API RP 53 chapter 8.2.b  
7.4.1.3 The choke manifold should be placed in a readily accessible location, preferably outside the rig substructure.   API RP 53 chapter 8.2.c  
7.4.1.4 When buffer tanks are employed, provision should be made to isolate a failure or malfunction.   API RP 53 chapter 8.2.d  
7.4.1.5 All choke manifold valves should be full bore. Two valves are recommended between the BOP stack and the choke manifold for installations with rated working pressures of 5,000 psi (34,5 MPa) and above, One of these two valves should be remotely controlled. During operations, all valves should be fully opened or fully closed.   API RP 53 chapter 8.2.e  
7.4.1.6 A minimum of one remotely operated choke should be installed on 10,000 psi (69.0 MPa), 15,000 psi (103.5 MPa), and 20,000 psi (138.0 MPa) rated working pressure manifolds.   API RP 53 chapter 8.2.f  
7.4.1.7 Choke manifold configurations should allow for re-routing of flow (in the event of eroded, plugged, or malfunctioning parts) without interrupting flow control.   API RP 53 chapter 8.2.g  
7.4.1.8 Consideration should be given to the low temperature properties of the materials used in installations to be exposed to unusually low temperatures and should be protected from freezing by heating, draining, filling with appropriate fluid, or other appropriate means.   API RP 53 chapter 8.2.h  
7.4.1.9 Pressure gauges suitable for operating pressure and drilling fluid service should be installed so that drill pipe and annulus pressures may be accurately monitored and readily observed at the station where well control operations are to be conducted.   API RP 53 chapter 8.2.I  
7.4.1.10 The choke control station, whether at the choke manifold or remote from the rig floor, should be as convenient as possible and should include all monitors necessary to furnish an overview of the well control situation. The ability to monitor and control from the same location such items as standpipe pressure, casing pressure, pump strokes, etc., greatly increases well control efficiency.   API RP 53 chapter 8.2.j  
7.4.1.11 Rig air systems should be checked to assure their adequacy to provide the necessary pressure and volume requirements for controls and chokes. The remotely operated choke should be equipped with an emergency backup system such as a manual pump or nitrogen for use in the event rig air becomes unavailable.   API RP 53 chapter 8.2.k  
  Installation guide lines-Choke lines      
7.4.1.12 The choke lines should be as straight as possible, because erosion at bends is possible during operations, consideration should be given to using flow targets at bends and on block ells and tees.   API RP 53 chapter 8.3.1.a.1  
7.4.1.13 In general, short radius pipe bends (R/d<10) should be targeted in the direction of expected flow. For large radius pipe bends (R/d>10), targets are generally unnecessary. Bends sometime have a wall thickness greater than the straight pipe in the choke system (such as the next higher schedule) to further compensate for the effect of erosion. 90° block ells and tees should be targeted in the direction of flow. Where: R= Radius of pipe bend measured at the centreline. d= Nominal diameter of the pipe.   API RP 53 chapter 8.3.1.a.1  
7.4.1.14 For flexible lines, consult the manufacturer's guidelines on working minimum bend radius to ensure proper length determination and safe working configuration.   API RP 53 chapter 8.3.1.a.2  
7.4.1.15 For articulated line assemblies, consult with the manufacturer's written specifications to determine the degree of relative movement allowable between end points.   API RP 53 chapter 8.3.1.a.3  
7.4.1.16 The lines and the lines down stream the choke should be firmly anchored to prevent excessive ship or vibration.   API RP 53 chapter 8.3.1.b  
7.4.1.17 The choke line and the lines downstream the choke should have a bore of sufficient size to prevent excessive erosion or fluid friction: 1.Minimum recommended size for choke lines is 2-inch (5.08 cm) nominal diameter for 3K and 5K arrangements and 3-inch (7.62 cm) nominal diameter for 10K, 15K and 20K arrangements.   API RP 53 chapter 8.3.1.c.1  
7.4.1.18 The choke line and the lines down stream the choke should have a minimum recommended nominal inside diameter for lines downstream of the chokes should be equal to or greater than the nominal connection size of the chokes.   API RP 53 chapter 8.3.1.c.2  
7.4.1.19 The choke line and the lines down stream the chokes lines downstream of the choke manifold are not normally required to contain pressure.   API RP 53 chapter 8.3.1.c.3  
7.4.1.20 The choke line and the lines down stream the choke should have for air or gas drilling operations, minimum 4-inch (10.16 cm) nominal diameter lines installed.   API RP 53 chapter 8.3.1.c.4  
7.4.1.21 The bleed line (the line that bypasses the chokes) should be at least equal in diameter to the choke line. This line allows circulation of the well with the preventers closed while maintaining a minimum back pressure. It also permits high volume bleed off of well fluids to relieve casing pressure with the preventers closed.   API RP 53 chapter 8.3.1.c.5  
7.4.3 Kill Lines Surface BOP Installations      
7.4.3.1 All lines, valves, check valves and flow fittings should have a working pressure at least equal to the rated working pressure of the ram BOPs in use. This equipment should be tested when installed in accordance with provisions of Section 17 of API RP 53   API RP 53 chapter 10.2.1.a  
7.4.3.2 For working pressures of 3,000 psi (20.7 MPa) and above, flanged, welded, hubbed, or other end connections that are in accordance with API Specification 6A, should be employed.   API RP 53 chapter 10.2.1.b  
7.4.3.3. Component should be of sufficient diameter to permit reasonable pumping rates without excessive friction. The minimum recommended size is 2-inch (5.08mm) nominal diameter.   API RP 53 chapter 10.2.1.c  
7.4.3.4 Two full bore manual valves plus a check valve or two full bore valves (one of which is remotely operated) between the stack outlet and the kill line are recommended for installations with rated working pressure of 5,000 psi (34.5 MPa) or greater. Refer to Figures 11 and 12 of API RP 53   API RP 53 chapter 10.2.1.d  
7.4.3.5 Periodic operation, inspection, testing and maintenance should be performed on the same schedule as employed for the BOP Stack in use (Refer to API RP 53 section 17.10)   API RP 53 chapter 10.2.1.e  
7.4.3.6 All components of the kill line system should be protected from freezing by heating, draining, filling with proper fluid, or other appropriate means.   API RP 53 chapter 10.2.1.f  
7.4.3.7 Consideration should be given to the low temperature properties of the materials used in installations to be exposed to unusually low temperatures and should be protected from freezing by heating, draining, filling with appropriate fluid, or other appropriate means.   API RP 53 chapter 10.2.1.g  
7.4.3.8 Lines should be as straight as possible. When bends are required to accommodate either dimensional variation(s) on sequential rig ups or to facilitate hook-up to the BOP, the largest bend radius allowable under the hook-up restraints should be provided.   API RP 53 chapter 10.2.1.h  
7.4.3.9 For rigid pipe, the bend radius should be maximized. Because erosion at bends is possible during operation, consideration should be given to using flow targets at bends and on block ells and tees. The degree to which pipe bends are susceptible to erosion depends on the bend radius, flow rate, flow medium, pipe wall thickness, and pipe material. However, in general, short radius pipe bends (R/d<10) should be targeted in the direction of expected flow. For large radius pipe bends (R/d>10), targets are generally unnecessary. Bends sometime have a wall thickness greater than the straight pipe in the kill system (such as the next higher schedule) to further compensate for the effect of erosion. 90° block ells and tees should be targeted in the direction of flow. Where: R=Radius of pipe bend measured at the centreline. d=Nominal diameter of the pipe.   API RP 53 chapter 10.2.1.h.1  
7.4.3.10 For flexible lines, consult the manufacturer's guidelines on working minimum bend radius to ensure proper length determination and safe working configuration.   API RP 53 chapter 10.2.1.h.2  
7.4.3.11 For articulated line assemblies, consult with the manufacturer's written specifications to determine the degree of relative movement allowable between end points.   API RP 53 chapter 10.2.1.h.3  
7.4.3.12 All lines should be firmly anchored to prevent excessive whip or vibration.   API RP 53 chapter 10.2.1.I  
7.4.3.13 The kill line should not be used as a fill-up line during normal drilling operations.   API RP 53 chapter 10.2.2  
7.9.9 Control System for surface BOP stacks.      
7.9.9.1 The elements of the BOP control system normally include: a. Storage (reservoir) equipment for supplying ample control fluid to the pumping system. b. Pumping systems for pressurizing the control fluid. c. Accumulator bottles for storing pressurized the control fluid. d. Hydraulic control manifold for regulating the control fluid pressure and directing the power fluid flow to operate the system functions (BOPs and choke and kill valves). e. Remote control panels for operating the hydraulic control manifold from remote locations. f. Hydraulic control fluid.   API RP 53 chapter 12.1.a-f  
Accumulator Volumetric Capacity      
7.9.9.2 Stored hydraulic fluid. The fluid volume recoverable from the accumulator system between the maximum designed accumulator operating pressure and the precharge pressure. definition API RP 53 chapter 12.3.1.a  
7.9.9.3 Usable hydraulic fluid. The hydraulic fluid recoverable from the accumulator system between the maximum accumulator operating pressure and 200 psi (1.38 MPa) above precharge pressure. definition API RP 53 chapter 12.3.1.b  
7.9.9.4 Minimum calculated operating pressure. The minimum calculated pressure to effectively close and seal a ram-type BOP against a wellbore pressure equal to the maximum rated working pressure of the BOP divided by the closing ratio specified for that BOP. definition API RP 53 chapter 12.3.1.c  
7.9.9.5 Component minimum operating pressure recommended by the manufacturer. The minimum operating pressure to effectively close and seal ram-type or annular-type preventers under normal operating conditions, as prescribed by the manufacturer. definition API RP 53 chapter 12.3.1.d  
7.9.9.6 BOP systems should have sufficient usable hydraulic fluid volume (with pumps inoperative) to close one annular-type preventer, all ram-type preventers from a full-open position, and open one HCR valve against zero wellbore pressure. After closing one annular preventer, all ram-type preventers, and opening one HCR valve, the remaining pressure shall be 200 psi (1.38 MPa) or more above the minimum recommended precharge pressure.   API RP 53 chapter 12.3.2  
7.9.9.7 Accumulator response time. Response time between activation and complete operation of a function is based on BOP or valve closure and seal off. For surface installations, the BOP control system should be capable of closing each ram BOP within 30 seconds. Closing time should not exceed 30 seconds for annular BOPs smaller than 18 ¾ inches (47.63 cm) nominal bore and 45 seconds for annular preventers of 18¾ inches (47.63 cm) nominal bore and larger. Response time for choke and kill valves (either open or close) should not exceed the minimum observed ram close response time.   API RP 53 chapter 12.3.3  
7.9.9.8 Operating pressure. No accumulator bottle should be operated at a pressure greater than its rated working pressure.   API RP 53 chapter 12.3.4  
7.9.9.9 Accumulator precharge. The precharge pressure on each accumulator bottle should be measured prior to each BOP stack installation on each well and adjusted if necessary.   API RP 53 chapter 12.3.5  
7.9.9.10 The minimum precharge pressure for a 3,000 psi (20.7 MPa) working pressure accumulator should be 1,000 psi (6.9 MPa). The minimum precharge pressure for a 5,000 psi (34.5 MPa) working pressure accumulator should be 1,500 psi (10.3 MPa).   API RP 53 chapter 12.3.5  
7.9.9.11 Only nitrogen gas should be used for accumulator precharge. The precharge pressure should be checked and adjusted to within 100 psi (0.69 MPa) of the selected precharge pressure at the start of drilling each well.   API RP 53 chapter 12.3.5  
7.9.9.12 Multi-bottle accumulator banks should have valving for bank isolation.   API RP 53 chapter 12.3.6  
7.9.9.13 An isolation valve should have a rated working pressure at least equivalent to the designed working pressure of the system to which it is attached and must be in the open position except when accumulators are isolated for servicing, testing, or transporting.   API RP 53 chapter 12.3.6  
7.9.9.14 A pressure gauge for measuring the accumulator precharge pressure should be readily available for installation at any time. Pressure gauges should be calibrated to 1 percent of full scale at least every three (3) years.   API RP 53 chapter 12.3.6  
  Pump Systems      
7.9.9.15 A pump system consists of one or more pumps. Each pump system ( primary and secondary) should have independent power sources, such as electric or air.   API RP 53 chapter 12.4.1  
7.9.9.16 With the accumulators isolated from service, the pump system should be capable of closing the annular BOP (excluding the diverter) on the minimum size drill pipe being used, open the hydraulically operated choke valve(s), and provide the operating pressure level recommended by the annular BOP manufacturer to effect a seal on the annulus within two minutes.   API RP 53 chapter 12.4.1  
7.9.9.17 The same pump system(s) may be used to provide power fluid to control both the BOP stack and the diverter system.   API RP 53 chapter 12.4.2  
7.9.9.18 Each pump system should provide a discharge pressure at least equivalent to the BOP control system working pressure. Air pumps should be capable of charging the accumulators to the system working pressure with 75 psi (0.52 MPa) minimum air pressure supply.   API RP 53 chapter 12.4.3  
7.9.9.19 Each pump system should be protected from over pressurization by a minimum of two devices to limit the pump discharge pressure. One device, normally a pressure limit switch, should limit the pump discharge pressure so that it will not exceed the working pressure of the BOP control system. The second device, normally a relief valve, should be sized to relieve at a flow rate at least equal to the design flow rate of the pump systems and should be set to relieve at not more than ten percent over the control unit pressure. API RP 53 chapter 12.4.4  
7.9.9.20 Devices used to prevent pump system over pressurization should be installed directly in the control system supply line to the accumulators and should not have isolation valves or any other means that could defeat their intended purpose. Rupture disc(s) or relief valve(s) that do no automatically reset are not recommended.   API RP 53 chapter 12.4.4  
7.9.9.21 Electrical and/or (pneumatic) supply for powering pumps should be available at all times such that the pumps will automatically start when the system pressure has decreased to approximately 90 percent of the system working pressure and automatically stop within plus zero or minus 100 psi (0.69 MPa) of the BOP control system working pressure.   API RP 53 chapter 12.4.5  
7.9.9.22 All valves, fittings, and other components, such as pressure switches, transducers, transmitters, etc., should have a working pressure at least equal to the rated working pressure of the control system. BOP control system rated working pressure is usually 3,000 psi (20.7 MPa).   API RP 53 chapter 12.5.1  
7.9.9.23 All piping components and all threaded pipe connections installed on the BOP control system should conform to the design and tolerance specifications for American National Standards Taper Pipe Threads as specified in ANSI B1.20.1. Pipe and pipe fittings should conform to specifications of ANSI B31.3.   API RP 53 chapter 12.5.2  
7.9.9.24 If weld fittings are used, the welder shall be certified for the applicable procedure required. Welding should be performed in accordance with a written weld procedure specification (WPS), written and qualified in accordance with Article II of ASME Boiler and Pressure Vessel Code, Section IX.   API RP 53 chapter 12.5.2  
7.9.9.25 All rigid or flexible lines between the control system and BOP stack should be flame retardant, including end connections, and should have a working pressure equal to the working pressure of the BOP control system.   API RP 53 chapter 12.5.2  
7.9.9.26 All control system interconnect piping, tubing, hose, linkages, etc., should be protected from damage during drilling operations, or day-to-day equipment movement.   API RP 53 chapter 12.5.2  
7.9.9.27 The manifold should be equipped with a full-bore valve to which a separate operating fluid pump can be easily connected.   API RP 53 chapter 12.5.3.a  
7.9.9.28 The control system should be equipped to allow isolation of both the pumps and the accumulators from the manifold and annular control circuits, thus allowing maintenance and repair work.   API RP 53 chapter 12.5.3.b  
7.9.9.29 The control system should be equipped with accurate pressure gauges to indicate: (1) accumulator pressure, (2) regulated manifold pressure, (3) annular pressure, and (4) air supply pressure.   API RP 53 chapter 12.5.3.c  
7.9.9.30 The control system should be equipped with a pressure regulating valve to permit manual control of the annular preventer operating pressure.   API RP 53 chapter 12.5.3.d  
7.9.9.31 The control system should be equipped with a regulating valve to control the operating pressure on the ram BOPs. The control unit should be equipped with a bypass line and valve to allow full accumulator pressure to be applied on the manifold, if desired.   API RP 53 chapter 12.5.3.e  
7.9.9.32 Control valves must be clearly marked to indicate (1) which preventer or choke line valve each control valve operates, and (2) the position of the valves (i.e., open, closed, neutral). Each BOP control valve should be in the open position (not the neutral position) during drilling operations.   API RP 53 chapter 12.5.3.f  
7.9.9.33 The choke line hydraulic valve should be in the closed position during normal operations. The control valve handle that operates the blind rams should be protected to avoid unintentional operation, but allow full operation from the remote panel without interference.   API RP 53 chapter 12.5.3.f  
7.9.9.34 All pressure gauges on the BOP control system should be calibrated to an accuracy of 1 percent of full scale at least every 3 years.   API RP 53 chapter 12.5.3.g  
7.9.9.35 The use of diesel oil, kerosene, motor oil, chain oil, or any other similar fluid is not recommended because of the possibility of explosions or resilient seal damage.   API RP 53 chapter 12.6.1  
7.9.9.36 Each closing unit should have a fluid reservoir with a capacity equal to at least twice the usable fluid capacity of the accumulator system.   API RP 53 chapter 12.6.2  
7.9.9.37 Air breather outlets, of sufficient size, should be installed to avoid pressurization of the tank during hydraulic transfers or nitrogen transfers if a nitrogen backup system is installed.   API RP 53 chapter 12.6.2  
7.9.9.38 The hydraulic control unit should be located in a safe place that is easily accessible to rig personnel in an emergency.   API RP 53 chapter 12.7  
7.9.9.39 The hydraulic control unit should also be located to prevent excessive drainage or flow back from the operating lines to the reservoir. Should the accumulator banks be located a substantial distance from or below the BOP stack, additional reservoir volume or alternative means should be provided to compensate for flow back in the closing lines.   API RP 53 chapter 12.7  
7.9.9.40 The installation should be equipped with a driller remote control panel such that the operation of each BOP and control valve can be controlled from a position readily accessible to the driller. Consideration should be given to the need for and additional remote control station(s) at a safe distance from the rig floor.   API RP 53 chapter 12.8  
7.4.5 Trip tank Surface BOPs      
7.4.5.1 A trip tank is a low-volume, [100 barrels(15.9 m³) or less] calibrated tank that can be isolated from the remainder of the surface drilling fluid system and used to accurately monitor the amount of fluid going into or coming from the well. A volume change of half a barrel should be easily detected.   API RP 53 chapter 15.6  
7.4.5.2 A trip tank may be of any shape provided the capability exists for reading the volume contained in the tank at any liquid level. The readout may be direct to remote, preferably both.   API RP 53 chapter 15.6  
7.4.5.3 The size and configuration of the tank should be such that volume changes on the order of one-half barrel can be easily detected by the readout arrangement.   API RP 53 chapter 15.6  
7.4.5.4 Tanks containing two compartments with monitoring arrangements in each compartment are preferred as this facilitates removing or adding drilling fluid without interrupting rig operations.   API RP 53 chapter 15.6  
7.4.5.5 Other uses of the trip tank include measuring drilling fluid or water volume into the annulus when returns are lost, monitoring the hole while logging or following a cement job, calibrating drilling fluid pumps, etc.   API RP 53 chapter 15.6  
7.4.5.6 The trip tank is also used to measure the volume of drilling fluid bled from or pumped into the well as pipe is stripped into or out of the well.   API RP 53 chapter 15.6  
7.11.1 Testing and maintenance - surface BOP stacks and well control equipment.      
7.11.1.1 The purposes for various field test programs on drilling well control equipment are to verify: a. That specific functions are operationally ready. b. The pressure integrity of the installed equipment. c. The control system and BOP compatibility.   API RP 53 chapter 17.1.a-c  
7.11.1.2 Test programs incorporate visual inspections, functional operations, pressure tests, maintenance practices, and drills. For purposes of this document, the following definitions are used for the basic types of tests.   API RP 53 chapter 17.2  
7.11.1.3 The inspection test. The common collective term used to state the various procedural examination of flaws that may influence equipment performance. These inspection tests may include, but are not limited to visual, dimensional, audible, hardness, functional, and pressure tests. Inspection practices and procedures vary and are outside the scope of this document. An example of some inspection guidelines can be found in IADC/SPE paper 23900. A field guide for surface BOP Equipment Inspections, W.J Kandel and D.J. Streu, February 1992. definition. API RP 53 chapter 17.2.1  
7.11.1.4 The function test. The operation of a piece of equipment or a system to verify its intended operation. Function testing typically does not include pressure testing. Actuation test, operating test, and readiness test are other terms commonly used synonymously for function test. definition. API RP 53 chapter 17.2.2  
7.11.1.5 The pressure test. Periodic application of pressure to a piece of equipment or a system to verify the pressure containment capability for the equipment or system. "Wellbore test" is another descriptive term frequently used synonymously for pressure test. definition. API RP 53 chapter 17.2.3  
7.11.1.6 The hydraulic operator test. The application of a pressure test to any hydraulic operated component of hydraulic-actuated equipment. Hydraulic operator tests are typically specified by the manufacturer for such items as: BOP operator cylinders and bonnet assemblies, hydraulic valve actuators, hydraulic connectors, etc. Operating chamber test is frequently used synonymously for hydraulic operator test. (Note: The definitions of test pressure, design pressure, operational characteristic tests, etc., as used in other API documents, may have meaning/intent more appropriate to manufacturing processes and the intended description may differ with field usage.) definition. API RP 53 chapter 17.2.4  
7.11.1.7 Site-specific applications of the different types of tests on well control equipment should be incorporated during field acceptance tests, initial rig-up tests, drills, periodic operating tests, maintenance practices, and drilling operations. (Note: Techniques and step-by-step or how-to-test procedures should be developed for each rig because of the varying equipment, different installation arrangements and well-specific drilling programs. The procedure for testing the BOP stack, drill string safety valves, choke/kill lines, and manifold upstream of the buffer chamber are usually similar for most rigs. Pressure test programs for the wellhead and casing should be prescribed by the operator on an individual well bases. Manufacturer operating and maintenance documents, contractor maintenance programs, and operating experiences should be incorporated into the specific test procedures. definition. API RP 53 chapter 17.2.4  
7.11.1.8 Function tests. Function tests may or may not include pressure tests. Function tests should be alternated from the driller's panel and from mini-remote panels, if on location. (Refer to worksheets in API RP 53 Appendix A). Actuation times should be recorded as a data base for evaluating trends. (Refer to worksheets in API RP 53 Appendix A). definition. API RP 53 chapter 17.3.1  
  Pressure tests      
7.11.1.9 All blow-out prevention components that may be exposed to well pressure should be tested first to a low pressure of 200 to 300 psi (1.38 to 2.1 MPa) and then to a high pressure.   API RP 53 chapter 17.3.2.1  
7.11.1.10 When performing the low pressure test, do not apply a higher pressure and bleed down to the low test pressure. The higher pressure could initiate a seal that may continue to seal after the pressure is lowered and therefore misrepresenting a low pressure condition.   API RP 53 chapter 17.3.2.1  
7.11.1.11 A stable low test pressure should be maintained for at least 5 minutes.   API RP 53 chapter 17.3.2.1  
7.11.1.12 The initial high pressure test on components that could be exposed to well pressure (BOP stack, choke manifold, and coke/kill lines) should be to the rated working pressure of the ram BOPs or to the rated working pressure of the wellhead that the stack is installed on, whichever is lower.   API RP 53 chapter 17.3.2.2  
7.11.1.13 Initial pressure tests are defined as those tests that should be performed on location before the well is spudded or before the equipment is put into operational service.   API RP 53 chapter 17.3.2.2  
7.11.1.14 Diverter systems are typically pressure tested to a low pressure only (refer to API Recommended Practice 64).   API RP 53 chapter 17.3.2.2  
7.11.1.15 Annular BOPs, with a joint of drill pipe installed, may be tested to the test pressure applied to the ram BOPs or to a minimum of 70 percent of the annular preventer working pressure, whichever is the lesser.   API RP 53 chapter 17.3.2.2  
7.11.1.16 The lower kelly valves, kelly, kelly cock, drill pipe safety valves, inside BOPs and top drive safety valves, should be tested with water pressure applied from below to a low pressure of 200-300 psi (1.38 to 2.1 MPa) then to the rated working pressure.   API RP 53 chapter 17.3.2.2  
7.11.1.17 There may be instances when the available BOP stack and/or the wellhead have higher working pressures than are required for the specific wellbore conditions due to equipment availability. Special conditions such as these should be covered in the site-specific well control pressure test program.   API RP 53 chapter 17.3.2.2  
7.11.1.18 Subsequent high pressure tests on the well control components should be to a pressure greater than the maximum anticipated surface pressure, but not to exceed the working pressure of the ram BOPs. The maximum anticipated surface pressure should be determined by the operator based on specific anticipated well conditions.   API RP 53 chapter 17.3.2.3  
7.11.1.19 Annular BOPs, with a joint of drill pipe installed, should be tested to a minimum of 70 percent of their working pressure or to the test pressure of the ram BOPs, whichever is less. Subsequent pressure tests are tests that should be performed at identified periods during drilling and completion activity on a well.   API RP 53 chapter 17.3.2.3  
7.11.1.20 A stable high test pressure should be maintained for at least 5 minutes. With larger size annular BOPs some small movement typically continues within the large rubber mass for prolonged periods after pressure is applied. This packer creep movement should be considered when monitoring the pressure test of the annular.   API RP 53 chapter 17.3.2.3  
7.11.1.21 Pressure test operations should be alternately controlled from the various control stations.   API RP 53 chapter 17.3.2.3  
7.11.1.22 The pressure test performed on hydraulic chambers of annular BOPs should be to at least 1,500 psi (10.3 MPa).   API RP 53 chapter 17.3.2.4  
7.11.1.23 Initial pressure tests on hydraulic chambers of ram BOPs and hydraulically operated valves should be to the maximum operating pressure recommended by the manufacturer.   API RP 53 chapter 17.3.2.4  
7.11.1.24 The test should be run on both the opening and the closing chambers.   API RP 53 chapter 17.3.2.4  
7.11.1.25 Pressure should be stabilized for at least 5 minutes.   API RP 53 chapter 17.3.2.4  
7.11.1.26 Subsequent pressure tests are typically performed on hydraulic chambers only between wells or when the equipment is reassembled.   API RP 53 chapter 17.3.2.4  
7.11.1.27 The initial pressure test on the closing unit valves, manifolds, gauges, and BOP hydraulic control lines should be to the rated working pressure of the control unit.   API RP 53 chapter 17.3.2.5  
7.11.1.28 Subsequent pressure tests of closing unit systems are typically performed following the disconnection or repair of any operating pressure containment seal in the closing unit system, but limited to the affected component.   API RP 53 chapter 17.3.2.5  
7.11.1.29 Pressure tests on the well control equipment should be conducted at least: a. Prior to spud or upon installation. b. After the disconnection or repair of any pressure containment seal in the BOP stack, choke line, or choke manifold, but limited to the affected component. c. Not to exceed 21 days.   API RP 53 chapter 17.3.3  
7.11.1.30 Well control equipment should be pressure tested with water. Air should be removed from the system before test pressure is applied. Control systems and hydraulic chambers should be tested using clean control system fluids with lubricate and corrosion additives for the intended service and operating temperatures.   API RP 53 chapter 17.3.5  
7.11.1.31 Pressure gauges and chart recorders should be used and all testing results recorded. Pressure measurements should be made at not less than 25 percent nor more than 75 percent of the full pressure span of the gauge.   API RP 53 chapter 17.3.6  
7.11.1.32 The results of all BOP equipment pressure and function tests shall be documented and include, as a minimum, the testing sequence, the low and high test pressures, the duration of each test, and the results of the respective component tests.   API RP 53 chapter 17.3.7  
7.11.1.33 Pressure tests shall be performed with a pressure chart recorder or equivalent data acquisition system and signed by pump operator, contractor's tool pusher, and operating company representative.   API RP 53 chapter 17.3.7  
7.11.1.34 Problems observed during testing and any actions taken to remedy the problems should be documented.   API RP 53 chapter 17.3.7  
7.11.1.35 Manufacturers should be informed of well control equipment that fails to perform in the field. (Refer to API Specification 16A).   API RP 53 chapter 17.3.7  
  General Testing Considerations      
7.11.1.36 Rig crews should be alerted when pressure test operations are to be conducted and when testing operations are underway. Only necessary personnel should remain in the test area.   API RP 53 chapter 17.3.8  
7.11.1.37 Only personnel authorized by the well site supervisor should go into the test area to inspect for leaks when the equipment involved is under pressure.   API RP 53 chapter 17.3.8  
7.11.1.38 Tightening, repair, or any other work is to be done only after pressure has been released and all parties have agreed that there is no possibility of pressure being trapped.   API RP 53 chapter 17.3.8  
7.11.1.39 Pressure should be released only through pressure-release lines.   API RP 53 chapter 17.3.8  
7.11.1.40 All lines and connections that are used in the test procedures should be adequately secured.   API RP 53 chapter 17.3.8  
7.11.1.41 All fitting, connections and piping used in pressure testing operations shall have pressure ratings greater than the maximum anticipated test pressure.   API RP 53 chapter 17.3.8  
7.11.1.42 Verify the type, pressure rating, size, and end connections for each piece of equipment to be tested, as documented by permanent markings on the equipment or by records that are traceable to the equipment.   API RP 53 chapter 17.3.8  
7.11.1.43 When a BOP stack is tested on the wellhead, a procedure should be available to monitor pressure on the casing should the test plug leak.   API RP 53 chapter 17.3.8  
7.11.1.44 If the control system regulator circuit is equipped with hydro-pneumatic regulators, a backup supply is recommended to pilot the regulators in case the rig air supply is lost.   API RP 53 chapter 17.3.8  
7.11.1.45 Functional tests of the control system should include a simulated loss of power to the control unit and to the control panel.   API RP 53 chapter 17.3.8  
7.11.1.46 Vertical stack alignment should be checked and flange bolt make-up should be torqued to prescribed ratings established in API Specification 6A.   API RP 53 chapter 17.3.8  
7.11.1.47 If hydrogen sulphide bearing formations are anticipated, manufacturer's certification for compliance with NACE Standard MR0175 should be available and reviewed for well control equipment, as described in API RP 53 Section 20.   API RP 53 chapter 17.3.8  
7.8.3 Diverter System Surface BOP Installations      
7.8.3.1 All diverter system components shall be inspected and tested to ascertain proper installation and functioning. Simulate loss of rig air supply to the diverter control system and determine, effects, if any, on the diverter system, vent line valves, and backup supply systems.   API RP 53 chapter 17.4.1  
7.8.3.2 Check and verify the proper structural mounting of the annular sealing device assembly, and, if applicable, that the insert packing element is secured in place.   API RP 53 chapter 17.4.1.a  
7.8.3.3 For installations using remote operators, record hydraulic pressure and air supply pressure with the accumulator fully charged and the controls in the normal drilling position.   API RP 53 chapter 17.4.1.b  
7.8.3.4 Actuate the diverter close and open sequence with drill pipe or test mandrel in the diverter to verify control functions, proper equipment operating sequence and interlock, if applicable, and record response time(s).   API RP 53 chapter 17.4.1.c  
7.8.3.5 A pressure integrity test [200 psi (1.38 MPa) minimum] should be made on the diverter system after each installation. The tests may be made on parts of the system or on individual components of the system should certain components of the casing string or riser components not support a complete system test.   API RP 53 chapter 17.4.1.d  
7.8.3.6 Pump water or drilling fluid through the diverter system at low pressure and high flow rates and check vent line(s) for returns. Examine the entire system for leaks, excessive vibrations, and proper tie down while pumping fluid at high rates.   API RP 53 chapter 17.4.1.e  
7.8.3.7 In cold climates, the diverter vent lines shall be protected from freezing. Possible methods include flushing with anti-freeze solution, draining, insulation, and heat tracing.   API RP 53 chapter 17.4.1.f  
7.11.2 Surface BOP stack equipment.      
7.11.2.1 Unless restricted by height, the entire stack should be pressure tested as a unit.   API RP 53 chapter 17.5.2  
7.11.2.2 Annular BOPs should be tested with the smallest OD pipe to be used.   API RP 53 chapter 17.5.3  
7.11.2.3 Fixed bore pipe rams should be tested only on the pipe OD size that matches the installed pipe ram blocks.   API RP 53 chapter 17.5.4  
7.11.2.4 Variable bore rams should be initially pressure tested on the largest and smallest OD pipe sizes that may be used during the well operations.   API RP 53 chapter 17.5.5  
7.11.2.5 Blind ram BOPs and blind shear ram BOPs should not be tested when pipe is in the stack.   API RP 53 chapter 17.5.6  
7.11.2.6 The capability of the shear ram and ram operator should be verified with the BOP manufacturer for the planned drill string.   API RP 53 chapter 17.5.6  
7.11.2.7 The shear ram and preventer design and/or metallurgical differences among drill pipe manufacturers may require high closing pressures for shear operations.   API RP 53 chapter 17.5.6  
7.11.2.8 Prior to testing each ram BOP, the secondary rod seals (emergency packoff assemblies) should be checked to ensure the seals have not been energized.   API RP 53 chapter 17.5.7  
7.11.1.9 Should the ram shaft seal leak during the test, the seal shall be repaired rather than energizing the secondary packing.   API RP 53 chapter 17.5.7  
7.11.1.10 Ram BOPs equipped with ram locks should be pressure tested with ram locks in the closed position and closing pressure bled to zero.   API RP 53 chapter 17.5.8  
7.11.1.11 Manual locks either screw clockwise or counter-clockwise, to hold the rams closed.   API RP 53 chapter 17.5.8  
7.11.1.12 Hand wheels should be in place and the threads on the ram locking shaft should be in a condition that allows the locks to be easily operated.   API RP 53 chapter 17.5.8  
7.11.1.13 The BOP elastomeric components that may be exposed to well fluids should be verified by the BOP manufacturer as appropriate for the drilling fluids to be used and for the anticipated temperatures to which exposed.   API RP 53 chapter 17.5.9  
7.11.1.14 Consideration should be given to the temperature and fluid conditions during well testing and completion operations.   API RP 53 chapter 17.5.9  
7.11.1.15 Manufacturers' markings for BOP elastomeric components should include the durometer hardness, generic type of compound, date of manufacture, part number, and operating temperature range of the component.   API RP 53 chapter 17.5.9.1  
7.11.1.16 Consider replacing critical BOP elastomeric components on well control equipment that has been out of service for six (6) months or longer.   API RP 53 chapter 17.5.9.2  
7.11.1.17 Flexible choke and kill lines should be tested to the same pressure, frequency, and duration as the ram BOPs.   API RP 53 chapter 17.5.10  
7.11.1.18 Verify that a properly precharged surge bottle is or can be installed adjacent to the annular preventer if contingency well control procedures include stripping operations.   API RP 53 chapter 17.5.12  
7.11.1.19 The drill pipe test joint and casing ram test sub should be constructed of pipe that can withstand the tensile, collapse, and internal pressures that will be placed on them during testing operations.   API RP 53 chapter 17.5.12  
7.4.6 Chokes and choke manifolds for Surface BOP installations.      
7.4.6.1 The choke manifold upstream of and including the lost high pressure valves (refer to API RP 53 figure 8) should be tested to the same pressure as the ram BOPs.   API RP 53 chapter 17.6.1  
7.4.6.2 The configuration of pipes and valves downstream of the last high pressure valve varies from installation to installation. Each configuration should be verified for mechanical integrity.   API RP 53 chapter 17.6.2  
7.4.6.3 The valves and adjustable chokes should be operated to verify smooth operation.   API RP 53 chapter 17.6.3  
7.4.6.4 Adjustable chokes are not required to be full sealing devices. Pressure testing against a closed choke is not required.   API RP 53 chapter 17.6.4  
7.4.6.5 The rig maintenance and inspection schedule should provide for periodic non-destructive examination of the mud/gas separator to verify pressure integrity. This examination may be performed by hydrostatic, ultrasonic, or other examination methods.   API RP 53 chapter 17.11.8  
7.11.2 Accumulator system for Surface BOP installations      
17.11.2.20 Accumulator closing test. The purpose of this test is to verify that the accumulator system is properly sized to support the fluid volume and pressure requirements of the BOPs on the rig using the following procedure; (Refer to sample worksheets and examples in API RP 53 Appendix A).   API RP 53 chapter 17.7.1  
17.11.2.21 Accumulator closing test procedure. a. Position a properly size joint of drill pipe or a test mandrel in the BOPs. b. Turn off the power supply to all accumulator charging pumps (air, electric, etc.) c. Record the initial accumulator pressure. (The initial accumulator pressure should be the designed operating pressure of the accumulator.) Manifold and annular regulators should be set at the manufacturer's recommended operating pressure for the BOP stack. d. Individually close each ram BOP (excepting blind or blind/shear ram BOPs) and record the closing time. To simulate closure of the blind or blind/shear rams, open one set of the pipe rams. Closing times shall meet the response time stipulated in API RP 53 Section 12.3.2. e. Function the hydraulic operated valve(s) and record the time and volume required f. Close the annular BOP and record the closing time. g. Record the final accumulator pressure. The final accumulator pressure shall be equal to or greater than 200 psi (1.8 MPa) above precharge pressure.   API RP 53 chapter 17.7.1 a-g  
17.11.2.22 After each well, the well control equipment should be cleaned, visually inspected, preventative maintenance performed, and pressure tested before installation on the next well.   API RP 53 chapter 17.10.1  
17.11.2.23 The manufacturer's test procedures, as prescribed in their installation, operation, and maintenance (IOM) manual, should be followed along with the test recommendations of API RP 53 Table 1. All leaks and malfunctions should be corrected prior to placing the equipment in service.   API RP 53 chapter 17.10.1  
  Visual inspection flexible choke and kill lines      
17.11.2.24 A visual external inspection of flexible choke and kill lines through the entire length of the line should include: a. Outer Jacket. Visually inspect to ensure that the outer jacket is intact to protect the polymeric sheath underneath from tearing and being punctured. Verify that the outer jacket is properly attached at both end fittings. Verify that the entire surface of the polymeric sheath is protected. If any damage is noticed on the outer jacket, verify that it will not be detrimental to the polymeric sheath.   API RP 53 chapter 17.10.2.a  
17.11.2.25 Termination. Record any damage to the coating on the end-fitting, and monitor progression of damage. Facilitate repair, if necessary.   API RP 53 chapter 17.10.2.b  
17.11.2.26 Connector. Particularly inspect the seal area of the connectors recording any damage and monitor progression of damage.   API RP 53 chapter 17.10.2.c  
  Major inspections      
17.11.2.27 After every 3-5 years of service, the BOP stack, choke manifold, and diverter components should be disassembled and inspected in accordance with the manufacturer's guidelines.   API RP 53 chapter 17.10.3  
17.11.2.28 Elastomeric components should be changed out and surface finishes should be examined for wear and corrosion. Critical dimensions should be checked against the manufacturer's allowable wear limits. Individual components can be inspected on a staggered schedule.   API RP 53 chapter 17.10.3  
17.11.2.29 A full internal and external inspection of the flexible choke and kill lines should be performed in accordance with the equipment manufacturer's guidelines.   API RP 53 chapter 17.10.3  
17.11.2.30 Manufacturer's installation, operation, and maintenance (IOM) manuals should be available on the rig for all the BOP equipment installed on the rig.   API RP 53 chapter 17.11.1  
17.11.2.31 Studs and nuts should be checked for proper size and grade. Using the appropriate lubricant, torque should be applied in a criss-cross manner to the flange studs. All bolts should then be rechecked for proper torque as prescribed in API Specification 6A. When making up connections, excessive force should not be required to bring the connections into alignment.   API RP 53 chapter 17.11.2  
17.11.2.32 Ring gaskets coated with a resilient material such as rubber or polyetrafluorethylene (PTFE) should not be used. Due to the limited amount of deformation which a groove can make in a ring as it is compressed during installation, it is not recommended to reuse ring gaskets.   API RP 53 chapter 17.11.2  
17.11.2.33 When making up proprietary clamp hubbed connections, the manufacturer's recommended procedure should be followed.   API RP 53 chapter 17.11.2  
17.11.2.34 Spare parts should be designed for their intended use by industry approved and accepted practices. After spare part installation, the affected pressure-containing equipment shall be pressure tested. Elastomeric components shall be stored in a manner recommended by the equipment manufacturer.   API RP 53 chapter 17.11.3  
17.11.2.35 The original equipment manufacturer should be consulted regarding replacement parts. If replacement parts are acquired from a non-original equipment manufacturer, the parts shall be equivalent to or superior to the original equipment and fully tested, design verified, and supported by traceable documentation.   API RP 53 chapter 17.11.3  
17.11.2.36 Manuals or bulletins containing torque specifications should be available on the rig. As stated in API RP 53 section 17.11.2, torque specifications and the lubricant's coefficient of friction should be considered when trolling fasteners. Deviating from the specified lubricant can alter the required torque.   API RP 53 chapter 17.11.4  
7.11.2.37 A planned maintenance system, with equipment identified, tasks specified, and the time intervals between tasks stated, should be employed on each rig. Records of maintenance performed and repairs made should be maintained on file at the rig site or readily available for the applicable BOP equipment.   API RP 53 chapter 17.12.1  
7.11.2.38 Copies of equipment manufacturers' product alerts or equipment bulletins should be maintained at the rig site or readily available for the applicable BOP equipment.   API RP 53 chapter 17.12.2  
7.11.2.39 Drawing showing ram space-out and bore of the BOP stack and a drawing of the choke manifold showing the pressure rating of the components should be on the rig and maintained up to date. Refer to API RP 53 figure 19 for an example drawing   API RP 53 chapter 17.13.1  
7.11.2.40 A bill of material should accompany the equipment drawings to correctly identify the equipment and allow the procurement of correct replacement parts.   API RP 53 chapter 17.13.1  
7.11.2.41 Changes to the BOP control system should be documented. A method should be established to control the drawings, ensuring that up-to-date documentation is maintained.   API RP 53 chapter 17.13.1  
7.11.2.42 Equipment records such as API manufacturing documentation, NACE certification, and factory acceptance testing reports should be retained. Where required, copies of the manufacturer's equipment data book and third party certification should be available for review.   API RP 53 chapter 17.13.2  
7.11.2.43 A maintenance and repair historical file should be maintained by serial number on each major piece of equipment. This file should follow the equipment when it is transferred. Equipment malfunctions or failures should be reported in writing to the equipment manufacturer as stated in API Specification 16A.   API RP 53 chapter 17.13.3  
7.11.2.44 Shop testing after major inspection or equipment weld repairs should be performed according to the manufacturer's written procedures.   API RP 53 chapter 17.13.4  
7.11.5 Blow-out preventers for hydrogen sulphide service.      
7.11.5.1 Where there is reasonable expectation of encountering hydrogen sulphide gas zones that could potentially result in the partial pressure of the hydrogen sulphide exceeding 0.05 Asia (0.00034 MPa) in the gas phase at the maximum anticipated pressure, BOP equipment modifications should be made. Recommended safety guidelines for conducting drilling operations in such an environment can be found in API Recommended Practice 49.   API RP 53 chapter 20.1  
7.11.5.2 Equipment modifications should be considered since many metallic materials in a hydrogen sulphide environment (sour service) are subject to a form of hydrogen embrittlement known as sulphide stress cracking (SSC).   API RP 53 chapter 20.2.1  
7.11.5.3 This type of spontaneous brittle failure is dependent on the metallurgical properties of the material, the total stress or load (either internal or applied), and the corrosive environment. A list of acceptable materials is given in NACE Standard MR0175.   API RP 53 chapter 20.2.1  
7.11.5.4 A list of specific items to be changed on annular and ram type BOPs and valves for service in a hydrogen sulphide environment should be furnished by the manufacturer.   API RP 53 chapter 20.2.2  
7.11.5.5 As a guide, all metallic materials which could be exposed to hydrogen sulphide under probable operating conditions should be highly resistant to sulphide stress cracking.   API RP 53 chapter 20.2.2  
7.11.5.6 The maximum acceptable harness for all preventer and valve bodies and spools shall be in accordance with NACE Standard MR0175.   API RP 53 chapter 20.2.3  
7.11.5.7 Ring-joint gaskets should meet the requirements of API Specification 16A and be of the material and hardness specified in API Specification 6A.   API RP 53 chapter 20.2.4  
7.11.5.8 All bolts and nuts used in connection with flanges, clamps, and hubs should be selected in accordance with provisions of API Specification 6A.   API RP 53 chapter 20.2.5  
7.11.5.9 All lines, crosses, valves, and fittings in the choke manifold system and the drill string safety valve should be constructed from materials meeting applicable requirements of API Specification 5L and API Specification 6A.   API RP 53 chapter 20.2.6  
7.11.5.10 Heat treating and other applicable requirements, as stipulated in NACE Standard MR0175 should also be reviewed and considered. Field welding upstream of the chokes should be kept to a minimum and, if performed, should meet original shop construction standards and procedures.   API RP 53 chapter 20.2.6  
7.11.5.11 Elastomeric components are also subject to hydrogen sulphide attack. Nitrile elastomeric components which meet other requirements may be suitable for hydrogen sulphide service provided drilling fluids are properly treated. Service life shortens rapidly as temperature increases from 150°F to 200°F (65.6°C to 93°C). In the event flowline temperatures in excess of 200°F (93°C) are anticipated, the equipment manufacturer should be consulted. Elastomeric components should be changed out as soon as possible after exposure to hydrogen sulphide under pressure.   API RP 53 chapter 20.2.7  
7.11.5.12 Changes prescribed by the primary equipment manufacturer to render equipment acceptable for service in a hydrogen sulphide environment should not be overlooked in providing for replacement and repair parts.   API RP 53 chapter 20.2.8

Comment by bill the drill on October 27, 2011 at 8:20am
has any one got the iwcf traning manual  on pdf need to do sum home study beffore cource in aberdeen

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