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well control equipment summary
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  (1)   WELL CONTROL EQUIP.   7/15/2007 M A-Mohsen   Introduction  Well control equipment is the second and last line of defense. Although there are many factors which may contribute to a blow-out, faulty equipment and equipment control have statistically been predominant causes to these events. Selecting the appropriate equipment (capacity, pressure rating etc.) and maintaining its integrity are  prerequisites in preventing such a calamity. Drilling contractor personnel and operator personnel alike should be fully familiar with well control equipment, with respect to function, limitation, and how to operate it, should there be a kick situation. 5.1.1 FUNCTION  The function of well control equipment is to close off the well bore and stop a well flow in case of loss of  primary control, and to be able to keep the bottom hole pressure equal to the formation pressure while preparing for and restoring primary control. Well control equipment includes: the preventer stack, the last set casing string, the well headand auxiliary equipment such as the choke and kill manifoldand the control unitas well as some srill string components. Well control equipment can provide proper protection only if the pressure rating is adequate. For this reason a working pressure classification has been introduced for all well control equipment. 5.1.2 WORKING PRESSURE CLASSIFICATION  Well control equipment is divided into several working pressure (WP) classifications. The choice of equipment depends on the maximum expected surface pressure that could be encountered during drilling and workover operations. The most common pressure ratings are: 13,800 kPa (2,000 psi) WP. / 20,700 kPa (3,000 psi) WP. / 34,500 kPa (5,000 psi) WP. 69,000 kPa (10,000 psi) WP. / 103,500 kPa (15,000 psi) WP. Although the minimum requirements for each WP classification are well and area specific, some of the general considerations follow below: 5.1.3 GENERAL CONSIDERATIONS  The following considerations should be taken into account when selecting well control equipment: ·   The equipment should be selected to withstand the maximum anticipated surface pressures and meet governmental regulations. ·   On offshore wells the specifications will generally fall into the 34,500 kPa (5,000 psi) WP and higher with a trend to the 69,000 kPa (10,000 psi) WP classification.  (2)   WELL CONTROL EQUIP.   7/15/2007 M A-Mohsen   ·   The blow-out preventer stack should consist of remote controlled equipment capable of closing in the well with or without the pipe in the hole. ·   Welded, flanged or hub connections are mandatory on high pressure systems above 13,800 kPa (2,000  psi). ·   In some areas well control equipment suitable for sour service may be required; in such cases the complete high pressure BOP system should be fabricated of materials resistant to sulphide stress cracking. ·   The response time of surface BOPs should be as specified in API RP53, i.e. the closing system should  be capable of closing each ram preventer within 30 seconds; the closing time should not exceed 30 seconds for annular preventers smaller than 508 mm (20 in) and 45 seconds for annular preventers of 508 mm (20 in) and larger. Although pressure rating of the equipment is the first concern, the layout of the stack is also critical. 5.1.4 MINIMUM REQUIREMENTS  Depending on the working pressure the surface blow-out prevention equipment must also comply with minimum compositional requirements. The number and type of BOPs to be used, apart from size, depends on expected formation pressure and the  probability of these pressures (i.e. are we drilling in a known area or wild-catting). The higher the expected  pressures, the greater the precaution needs to be (i.e. more BOPs to provide redundancy). Well killing system   5.2.1 INTRODUCTION  When primary control has been lost and formation fluids enter the well bore, a hydrostatic overbalance is no longer maintained. Instead we have a pressure balance in the annulus between the formation pressure and the sum of the hydrostatic heads of the fluids in the annulus plus viscous friction losses due to flow plus the back  pressure applied at the surface. If no, or insufficient, back pressure is applied the rate of flow from formation to well will increase until the friction losses in the annulus enable equilibrium to be reached. The result is a blow out. This pressure balance is maintained in static conditions by closing off the annulus at the surface by means of the BOPs. Flow will then only continue until the well head pressure has increased to the difference between the formation pressure and the hydrostatic pressure of the fluid column in the annulus. Under dynamic conditions (i.e. during well killing operations) the balance is maintained and additional inflow is  prevented by applying a calculated back pressure which is equal to the formation pressure minus the hydrostatic head in the annulus minus the friction losses plus a safety factor. Given that the hydrostatic head in the annulus will vary as the initial volume of formation fluid flows up the well, especially if it is gas, and as kill mud is  pumped down the drill pipe and enters the annulus, it is necessary to vary the applied back pressure. This is done by passing the flow through a restriction whose size can be changed in a quantifiable manner. Such a restriction is called an adjustable choke.  (3)   WELL CONTROL EQUIP.   7/15/2007 M A-Mohsen   The well control equipment on a rig normally contains two adjustable chokes, situated in what is, logically, called a choke manifold . 5.2.2 CHOKE MANIFOLD   Figure 3.5.2 : A choke manifold   A choke manifold is an assembly of valves, as depicted in Figure 3.5.2, through which the return flow from the well is routed when the blow-out  preventers are closed, with the purpose of applying a calculated back pressure. Choke manifolds may be assembled in a variety of layouts but they will always include at least two adjustable chokes. In some cases this may be one manual choke and one remote controlled choke as shown in Figure 3.5.2. The manifold provides alternative flow paths for the fluid so that if necessary chokes can be changed and valves repaired without stopping the flow. All the high pressure parts of the manifold should have the same working pressure rating as the BOP stack. The manifold is connected to the hydraulically operated choke line valve and the B0P stack by a high-pressure flexible hose, or alternatively a high pressure steel line. The flexible hose is a specially designed steel armoured hose. Ordinary kelly hoses are not considered suitable. The manifold has to be adequately secured because it may be subjected to violent forces and vibration during certain stages of well killing. Valve settings  Of the two choke line valves on or adjacent to the stack, the inner manual valve is kept open, and the second (the remotely controlled hydraulically activated gate valve) kept closed during drilling. All other valves and chokes in the line to the mud/gas separator, are kept open with the exception of the valve immediately upstream of each of the chokes and the second valve in the bypass line after the cross (the centre flow line, the one without a choke). Wherever two valves are fitted it is standard practice that the second valve is the one operated and the first one used as backup, in case the second one fails. When two manual chokes are installed either one can be used. When a manual choke and a remote controlled choke are installed, the remote controlled choke is the one normally used, keeping the manual choke as a standby choke. Before taking over the shift the driller should make sure that all the valves on the choke manifold are set as described above. 5.2.3 VALVES  All high pressure valves used on the casing head housing, wellhead spools, drilling spools and in the choke and kill manifold, should have steel seats and full gauge opening  (4)   WELL CONTROL EQUIP.   7/15/2007 M A-Mohsen   Gate valves, e.g. Cameron and WKM, are commonly used in rig manifolds. It is however possible that in some cases plug valves, e.g. Halliburton Lo-Torc valves, have been installed. Such valves are normally prohibited for this application. CHOKE AND KILL LINE OUTLET VALVES Owing to area and contractor specific requirements, it is not feasible to specify a standard layout, but the following minimum requirements should be adhered to: ·   The choke line must have a minimum ID of 76.2 mm (3 ), the kill line may be as small as 50.8 mm (2 ), albeit that this might restrain operational flexibility should immediate substitution of a choke line be required. During normal operation, the inner (usually manual) choke and kill line valves should remain open and the outer (hydraulically operated) valves closed such as to prevent excessive solids build-up in these lines. ·   Wellhead outlets should, under normal operating conditions, not be used for a choke and kill line tie-in. ·   If the kill line is not meant to ultimately replace or augment the choke line, it is highly desirable to install a check valve upstream of the stack valves. HYDRAULICALLY OPERATED CHOKE LINE VALVE  This type of valve is an adapted gate valve, e.g. Cameron type LSF,  provided with a double acting hydraulic cylinder mounted on the bonnet cap. The stem of the valve is connected to the piston in the cylinder. When hydraulic pressure is applied to the bottom of the cylinder, the piston and gate move upwards and the valve opens. When the hydraulic pressure is on the top of the cylinder the valve will close. A handwheel and locking screw are provided to close the valve manually if required. The lower stuffing box and tail rod on the stem have a three-fold function: ·   To act as a pressure balance for the stem which connects the gate to the operating piston. ·   To keep the grease packed in the gate cavity of the valve body. ·   To serve as an indicator whether the valve is open or closed . Figure 3.5.5 : Hydraulically operated gate valv e HCR PRESSURE OPERATED GATE VALVE  On several rigs an older type remote control gate valve may be found, the HCR valve (see Figure 3.5.6). This  pressure operated gate valve is a flow line valve requiring relatively low operating pressures. The closing ratio of well pressure to hydraulic operating pressure is approximately 8 to 1. The gate is packed with elements similar to the QRC ram assembly. These valves are made to hold pressure from one side only. It is therefore of crucial importance that during installation the correct side will face the BOP stack. The flow direction is usually indicated by an arrow on the body of the valve.
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