The intent of this guideline is to assist the Drilling Engineer in his preparation of the deepwater drill stem test design and procedure.

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2 The intent of this guideline is to assist the Drilling Engineer in his preparation of the deepwater drill stem test design and procedure. This document is not intended to override any specific local rules and regulations that are set by the applicable Regulatory Authorities, or the authority of the Drilling Manager or the Operations Superintendent responsible for the well being tested. 2

3 Deepwater drill stem tests will differ from a standard drill stem test due to a multitude of factors. These will vary depending on the location of the well, however some of the most common are listed in this slide : Local conditions are very important. The conditions encountered offshore West Africa or the Gulf of Mexico will differ greatly when compared to the conditions encountered West of Shetlands and Norway. Also the conditions encountered West of Shetlands and /or Norway through the summer months will differ greatly when compared with the winter months. Hence in these areas, drill stem testing operations should be planned for the summer months when the local conditions are most favourable. 3

4 Testing in deepwater calls for new equipment and procedures to cope with the many new factors that deepwater and dynamically positioned vessels present. This lecutre offers a guide to identify the critical issues that need to be considered when performing a drill stem test from a dynamically positioned drilling vessel in deepwater. It is felt that five main issues as illustrated exist. 4

5 How a drilling vessel will react in the deepwater environment where the well is being drilled and tested is critical. E.g, station keeping over the wellhead takes on a greater significance during the testing phase. A drilling vessel with the ability to remain over the wellhead in expected weather conditions will greatly increase the chance of a successful drill stem test. The vessel should concentrate on two main issues : 1. The ability to remain over the wellhead and the reaction of the marine riser with regards to the water depth and local tides / currents Prior to test, -perform a marine riser analysis and highlight areas of concern. Remember that the landing string and the subsea equipment (except the centralisers) should not make contact with the internals of the marine riser. E.g. Centralisers would be used to minimise the relative movement between the landing string / umbilical and the drilling riser. -perform a drilling vessel positional analysis. E.g. During drilling monitor the drilling vessel s position relative to the wellhead. If necessary postpone or delay the drill stem test if risk analyses that the drilling vessel cannot remain over the wellhead to allow the operation to be completed in a safe manner. The weak link in the landing string design is the control umbilical required to operate the subsea equipment. Should the control line umbilical fail, it will be problematic to kill the well and unlatch from the subsea test tree. The cost of the drill stem test will increase with a greater likelihood of a safety and /or an environmental incident occurring. Test may even have to be suspended. 5

6 At an early stage cinfirm that the blow out preventer (BOP stack) will allow the testing contractor s subsea equipment to be installed. Modifications to the BOP stack and /or the testing contractor s subsea equipment may be expensive and considerable time may be required. In addition, it is preferable to use a production and kill standpipe during a deepwater drill stem test. This allows the flexible hose (coflexips) connecting the surface test tree to the rig pipework to remain connected whilst stabbing into and out from production packers or whilst unlatching the landing string from the subsea test tree. The production and kill standpipes need to be positioned in the derrick at the correct height above the drill floor (± 45 ft) and the flexible hose from the surface test tree needs to be the correct length (± 60 ft) to connect onto the standpipes. Modifications to the derrick, design and fabrication of standpipes (etc.) can also prove to be expensive, time consuming, e.g. sourcing or manufactureing equipment required. Identifying potential problems between vessel and the testing contractors equipment may have a bearing on the final decision to select a drilling vessel. It is possible that you may not have a choice when selecting the drilling vessel (location, availability etc.). Hence, it is better to know in advance any areas of conflict and /or equipment modifications that may be required to the drilling vessel or the testing contractor s subsea equipment 6

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8 During a deepwater drill stem test, how the subsea equipment is set up to operate and the guidelines prepared to operate the subsea equipment will be critical to the success of the drill stem test. The major differences when operating the subsea equipment on a deepwater drill stem test are illustrated in this slide Guidelines should be developed to operate the subsea equipment within a controlled envelope. I.e. It is preferable to suspend the drill stem test and secure the well before the weather dictates an emergency unlatch of the subsea test tree. These guidelines should follow the drilling vessel s operating procedures for drilling operations where, ultimately, it may be necessary to close the shear rams and unlatch the marine riser. 8

9 The above table assumes that the fluid inside the landing string is gas and does not string out as it travels up the marine riser. It also assumes that there will be no balancing out ('u' tube) of the fluids. It is designed to show that the volumes can be significant, especially when compared to the volume inside the marine riser at the same depth. Hence it is easy to visualise the marine riser being displaced to gas and liable to collapse, especially as the water depth and /or the internal pressure increases. 9

10 The control umbilical volume determines the response time for the subsea test tree and the subsea retainer valve to operate. This includes the hydraulic reservoir at surface, the volume of the control umbilical between surface and the seabed and the hydraulic volume within the subsea test tree / subsea retainer valve assembly. In a deepwater well, the overall volume will increase significantly due to the extended length of the control umbilical through which the hydraulic fluid flows. As such, if the system were to operate conventionally with the hydraulic fluids returning to surface after operation of the subsea test tree / subsea retainer valve assembly, the response time of the system may increase to an unacceptable level. To overcome this, the testing contractor will use accumulators at surface or use a booster system incorporated into the subsea equipment and positioned above the subsea test tree / subsea retainer valve assembly. On deepwater operations, the booster system negates the requirement to displace the hydraulic fluid through the control umbilical back to surface. 10

11 Used for water depths greater than 4000ft. 11

12 Green : Normal operations. Amber : Suspend operations, close the downhole tester valve, close the subsea test tree, close the subsea retainer valve and monitor the conditions. Be prepared to unlatch the landing string. Red : Unlatch the landing string at the subsea test tree. 12

13 The figure below shows a typical drift off analysis as the drilling vessel moves through the "GREEN", "AMBER" and "RED" operating zones. The "GREEN" testing phase is clearly shown, as is the time allowed for the landing string to be disconnected after the drilling vessel enters the "AMBER" operating zone. The subsea test tree must not be disconnected after the drilling vessel enters the "RED" operating zones. 13

14 The components of the landing string, specifically the subsea equipment, are critical to a successful drill stem test. The subsea equipment used during a deepwater drill stem test can be broken up into five main components. All these items can be used during a conventional drill stem test from an anchored vessel in shallow water. 14

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16 a control umbilical protective shroud (or cased wear bushing, rotary table slick joint etc.) through which the control umbilicals pass, can be placed inside the marine riser at the point where the gas diverter will close across the landing string. The control umbilical protective shroud is a segment of the landing string. Hence, the control umbilical protective shroud will have connections compatible with and will be designed to the same specifications as the landing string tubing (tensile, burst, service etc.). It should be confirmed that by closing the gas diverter around the protective shroud, the marine riser cannot be over pressurised. Remember that the marine riser is typically, only rated to ± 150 psig at the telescopic joint. There are several control umbilical protective shroud designs available. Typically, the protective shroud will use an outer sleeve that is fitted over the control umbilical. The protective shroud will be slotted to prevent damage to the control umbilical as the outer sleeve is fitted. 16

17 Slides presented refer specifically to planning and execution of a drill stem test conducted from a dynamically positioned drilling vessel operating in deepwater. However, the guidelines and recommendations may also apply to a drill stem test from an anchored vessel operating in deepwater or a dynamically positioned vessel operating in shallow water. 17

18 It is important that the subsea test tree / retainer valve assembly can only be operated in a set sequence. The figure shows the five steps to follow when operating the subsea test tree / retainer valve assembly. -It should not be possible to close the subsea retainer valve until the subsea test tree is closed. -It should not be possible open the bleed off port until the subsea retainer valve is closed -It should not be possible to unlatch the subsea test tree until the bleed off port is open and any trapped pressure between the subsea test tree and the subsea retainer valve has bled off -Before commencing the drill stem test, decide if the subsea retainer valve is to be set up in the failsafe closed or the failsafe open mode. Finally, it is important to evaluate the risk and make a decision before the drill stem test commences. If on dp, then the preferred option should be failsafe closed as there is a high risk that the shear rams will be functioned during the drill stem test. If anchored, then the preferred option should be failsafe open as it is highly unlikely that the shear rams will be functioned during the drill stem test. 18

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21 When using this arrangement, with the standpipe 48 ft above the drill floor and the surface test tree 25 ft above the drill floor, 60 ft flexible flowlines are considered the optimum length. This will ensure that the flexible flowlines can be connected easily during the rig up and still have enough length to remain connected whilst unlatching or re-latching from the subsea test tree or stabbing in to and /or out from a permanent packer with a stinger (seal assembly). The figure shows the potential problems when the surface test tree has been raised above the drill floor after unlatching from the subsea test tree. This will be when the flexible flowlines are most likely to be damaged. This problem may also occur during normal operations when the drilling vessel s movement (i.e. heave) is excessive, especially if the hook up is poorly designed. 21

22 Perhaps one of the hardest decisions to make during the planning of a deepwater drill stem test will be whether or not to perform well intervention operations. The potential problems with well intervention operations are well documented. Deepwater drill stem testing increases the possibility of these problems developing. However, as during a conventional drill stem test, the objectives will dictate whether well intervention operations should be performed. If there is no reason to perform well intervention operations, then do not perform them. If the objectives dictate the need for well intervention operations, then they should be kept to a minimum, planned correctly and reviewed at regular intervals during the drill stem test. Well intervention operations should not be started unless it can be confirmed that they can be completed without the need to perform a controlled unlatch of the landing string (i.e. a weather windows exists to allow the operation to be completed). 22

23 Drill stem test information, guidelines and recommendations will also often apply to well intervention operations that take place on subsea production wells - either newly drilled or existing wells. These may utilise the traditional "Conventional Tree" that requires a lower riser package complete with emergency disconnect package to be run on a production riser without the drilling vessel s BOP stack being used. Alternatively the newer "Horizontal Spool Tree", that requires subsea intervention tools (similar to a standard subsea test tree) to be run through the drilling vessel s BOP stack and latched onto the top of the tubing hanger may be used. 23

24 It is possible for coiled tubing operations to be performed during a deepwater drill stem test. The need to run coiled tubing will be the same as on a standard drill stem test. They include but are not limited to the following as illustrated: The above and many other similar operations are standard during a drill stem test. Potential problems include hydrate formation whilst running the coil (either from the fluid used to pressure test the injector head or a leak at the stripper), accidental cutting of the coiled tubing (valve closure in the test string) and /or hanging up in the well (fill, valve, crossover etc.). Again the potential problems are all possible during a standard drill stem test. A benefit when using coiled tubing on a deepwater well is that it may be possible to keep the coiled tubing above the subsea test tree depending on the operation being performed. For example, it is most unlikely (although possible) that wax dispersant or methanol would need to be spotted below the seabed. In addition, depending on the depth of the water, it may be possible to displace the test string to nitrogen above the subsea test tree and allow the well to flow. 24

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