1 General
The majority of Well Testing carried out world-wide is in the 5000 psi WP regime. In recent years there has been a need to go deeper with resultant higher temperatures and pressures.
A description of equipment follows which essentially covers the 5000 psi through 15000 psi WP range. It is essential to ensure that a balance is achieved between what is available, and what is fit for purpose. The objective is to keep the completion string as simple as possible to attain objectives.
Three examples are given of possible Well Test strings in the 5000 psi, 10,000 psi and 15,000 psi WP ranges (see Section 11).
The well completion string should allow production testing at the following flow rates:
Gas/Gas condensate wells: 60 MMscf/d gas, 5000 bbl/d condensate,
Oil wells: 10,000 bbl/d with a GOR of about 1000 scf/bbl.
The well completion string should be designed to meet the following:
·flexibility and ability to meet all Petroleum Engineering objectives.
·simple design and relative ease to run.
·minimum wireline requirements.
Strings are usually designed for testing one or two, closely spaced, separate zones, in 7" OD and/or 95/8" OD casing sizes, by using a selective, wireline set permanent type, packer arrangement.
Differing tests will dictate the exact description of a test string. Some considerations will be:
1.Maximum expected pressures and temperatures. If pressures are not expected above 5000 psi, 'x' line wireline equipment will suffice as will a 5000 psi Xmas tree (e.g. on a land location).
2.Economics versus time could be a constraint that determines sophistication of data acquisition, e.g. bottom shut-off tool, amerada or bundle carrier, memory or surface read out.
In general, the well completions string would allow the following:
·Perforations with a 2 1/8" through tubing gun requiring a minimum bore of 2 1/4".
·Accurate recording of downhole temperatures and pressures.
·Wireline operations to the bottom of the well.
·Control of the well at any time through killing, use of blow-out preventers or operation of a subsurface safety valve.
A 31/2" tubing string is normally considered suitable for production testing; when higher rates are programmed a 5" tubing string is recommended. When the well is drilled in a new area it is mandatory to be prepared for H2S gas; in this case the material for the tubing should be grade L-80. All tubing accessories should be suitable for sour service.
For wells with a TD below 10,000 ft it is advisable to have the top part consisting of a stronger tubing (i.e. 31/2", 12.95 lbs/ft) On floating rigs the tubing from rig floor to BOP stack is prone to buckling and should therefore be rigid; 41/2"-19.2 lbs/ft is recommended. Hydril tubing connections are proven to give good service especially for repeated stabbing and make-up which is usually the case during testing operations. In addition, the integral tubing connection (no coupling) reduces the potential chance of a connection leak by 50%.
A detailed standard list of necessary completion equipment and completion sketches can be found in Section 11.
2 Subsurface equipment
2.1 Well completion items below the packer
The following items are used:
2.1.1
The wireline re-entry guide is chamfered on the outside as well as the inside to guide the tubing-string into the packer bore, when approaching the packer during tubing running and re-entry of wireline/Schlumberger tools.
2.1.2
A pup-joint to protect tandem pressure and temperature recorder. If sufficient space is available to the top of the perforations, a full joint may be run. Sometimes the formation pressure is very low and the well is not expected to unload easily. In this case it is important to keep the height between the packer and the perforations as short as possible and the protecting joint should be limited in length or left out completely.
2.1.3
A no-go nipple is used to hang off pressure/temperature recorders on a corresponding lock.
2.1.4
A 27/8 in. ´ 10 ft perforated nipple to provide flow-passage above the recorders.
2.1.5
Landing nipple: a plug will be set in this nipple when it is necessary to sample the tubing contents of a well which is incapable of natural flow to surface. Once the plug has been set, the tubing contents can be circulated to surface by pumping down the annulus and through the circulating device in the tubing.
2.1.6
As standard, a 20 ft long locator seal assembly will be used with an ID = 3 in. and OD = 4 in. to fit both 7 in. and 95/8 in. permanent packers.
2.1.6.1 Packer
Use of a permanent packer is mandatory for the following reasons:
There is hardly any swabbing effect while pulling the string. A retrievable packer has to be pulled slowly to avoid swabbing. The permanent packer will not release due to tubing movement caused by pressure or temperature if spacer seal-assemblies are used.
On a number of occasions retrievable packers have released after correct setting due to tubing movement during pressure testing, stimulation or normal flowing. They should be avoided, particularly on floating rigs.
2.1.6.2 Packer configurations
The following various permanent packer configurations are possible:
1.A flapper-valve can be fitted at the bottom of the Baker D or DA packer; this valve closes when the tubing-string is retrieved. Use of the flapper valve is not recommended because the mule-shoe may become damaged while stabbing the completion string into the packer and by holding up on a closed flapper which may have high pressure below it.
2.A junk-pusher can be part of the packer assembly and is fitted at the bottom to clear the casing-bore from mud or removable obstructions, and acts as a feeler. As other necessary extensions are usually fitted to the bottom of the packer the junk-pusher is not normally part of the packer and a separate scraper run, should be made prior to packer setting.
3.Where temperature differences in the well will cause appreciable changes in tubing length the seal assembly may be extended to some 20 feet to accommodate changes in tubing length.
4.If a permanent packer is to be milled-out, a packer milling tool can be used. This tool mills the outer part and slips of the packer; the packer body and any attachments below can be picked up by the catcher sleeve, which is part of the milling tool.
In the top of the packer a plug can be set, on wireline, tubing or drillpipe, converting the packer into a (semi)-permanent bridge plug.
The Company has good experience with Baker Permanent Packers for well test and permanent completions.
2.1.6.3 Well completion items above the packer
Items run above the top packer will essentially depend on the pressure rating of the surface wellhead equipment, which in turn is determined by the maximum pressure expected during the well test. The surface tree could be 5000 psi, 10,000 psi or 15,000 psi rated, and downhole accessories will therefore be chosen to suit. Besides the three examples given in Annex A, which were all done from offshore drilling vessels, it is also usual to have standard equipment as specified below, for land well testing operations.
2.1.7 Gauge carriers (above packer)
Several types of recorder carriers are in use to accommodate different string configurations. Where both mechanical and electronic gauges are used, the size varies from 37/8" OD to 51/2" O"D for standard and H2S service. There are inside/outside reading options and are rated to 15,000 psi WP.
2.1.8 Downhole shut-in tools
Again, several types of downhole shut-in tools are available on the market, such as the Schlumberger MUST (multiple Shut-in Tool) which allows up to 12 flow and shut-in cycles of pressure monitoring.
2.1.9
A 31/2 inch no-go nipple and test tool are used for pressure testing the completion string. This nipple is preferred for pressure testing the completion string due to the no-go feature being rated for very high tubing test pressures. A further advantage is that these-nipples can also be used with 31/2 inch Hydril Ph-6 tubing 12.95 lb/ft, which has a small ID.
2.1.10 Sliding Side Doors (SSD) size 31/2 inch
Under normal operating conditions during well testing, SSD's are usually closed. During testing the SSD will only be open for short periods. Generally the force required to open the SSD, after a long period of being closed, will be fairly high. This is caused by possible swelling or hardening of the elastomer packing material. By jarring-up, a larger force can generally be applied on the positioning tool than when jarring down and therefore is preferred for well testing purposes.
Another advantage of using this type of SSD is that when problems occur to close the SSD (for instance when the jar down force is small due to heavy brine), a less viscous, lighter fluid can be spotted over the SSD to increase jar down action.
2.1.11
A 31/2 inch Landing nipple is installed below the SSD. It can be used to set a plug before disconnecting the SSTT as an additional safety measure or it can be used for pressure testing the top part of the tubing string. The ball valves of the SSTT have to move downward before opening. When a plug is installed in a nipple too close to the SSTT, fluid lock can prevent its opening. Therefore this nipple should be placed a minimum 500 feet below the SSTT.
On fixed platforms (jack-up rigs) and land wells the tubing is hung-off by means of a standard tubing hanger nipple inside a tubing hanger-spool. The extended neck of the tubing hanger nipple is packed off in a seal flange with double P-seals. On top of this seal flange the production test contractor's Xmas tree is positioned by making use of a flanged X-over spool.
On floating rigs the tubing is hung-off by means of a fluted hanger inside the 95/8 inch or 7 inch wear bushing. A slick joint, positioned opposite the lower 5 inch piperams, connects the SSTT to the fluted hanger. During production testing the rams are closed around the slick joint to shut-off the annulus.
The tubing from the SSTT to the surface should be very rigid to prevent buckling. It is recommended that 41/2 inch Hydril PH-6 19.2 lbs/ft is used.
This section deals with the equipment which is run between the pipe rams and the rotary table and comprises:
2.1.12 SHORT single-shot hydrostatic overpressure reverse tool
The SHORT tool is a simple device opened by one cycle of annulus overpressure. It has few working parts, consisting of a moving mandrel inside a housing containing two atmospheric chambers. A rupture disc communicates from the annulus to the lower atmospheric chamber. It is a compact, reliable tool that fits ideally in any cased hole test string. The SHORT tool cannot be closed once it is opened and an incidental overpressure of the annulus could open the tool.
2.1.13 MCCV multi-cycle circulating valve
The MCCV tool is a reclosable valve operated by tubing pressure and used for reversing or circulating. It is similar to the MIRV tool but differs in that it is not rate sensitive for closing. To close, the tool uses changes of flow direction rather than rate changes. It has three positions:
·Closed, no communication between annulus and tubing.
·Open, annulus to tubing, to allow reverse circulation.
·Open, tubing to annulus, to allow circulation.
The MCCV tool has an inner mandrel with a set of ports that can align with either reversing or circulating ports. Each set of ports has flow restrictors that allow flow in only one direction. This can create sufficient backpressure to close the tool. The tool can be preset on 6 or 12 cycles, depending on the expected pressure tests on the string. When internal pressure exceeds annulus pressure by 500 psi, the indexing system cycles.
After a preset number of cycles, the tool opens and the string contents can be reversed out through four 1/2 in. ports. When pumping starts, the reversing port restrictors limit flow, causing a pressure difference that moves the inner mandrel into the spotting position. At the end of pumping, the applied pressure is bled off and the tool can be used for spotting nitrogen or stimulation fluids. The main benefit of the MCCV tool is that it is completely unaffected by the operation of the annular pressure-operated tools.
MCCV specifications :
ID17/8 in.21/4 in. fullbore/ OD5 in.5 in. / Length84 in.74.1 in. / ServiceH2S/acidH2S/acidª / Maximum pressure15,000 psi10,000 psi§ / Temperature350°F / Tensile strength at minimum yield530,000 lbf / Make-up torque6000 ft lbf4000 ft lbf/ Operating pressure500 psi above hydrostatic / Flow partsfour, 1/2 in. / Maximum pump rateunlimited / Weight350 lbm / Top connection31/2 in. API IF box / Bottom connection31/2 in. API IF pin / Max. number of open reversing ports6 (1/2 in. diameter) / Spotting rate3/4 bbl/minute/port¨ /
ª As per NACE MR-01-75§ Maximum working pressure differential (burst and collapse) on 67% of minimum yield¨ Recommended maximum flow volume - 3/4 bbl/port. These ratings are for 16.5 lbm/gal mud
2.1.14 PORT pressure-operated reference tool
The PORT tool is a pressure reference tool for the PCT flow control valve and is designed for use with both permanent and retrievable packers. It is run in the hole in the open position for fluid by-pass. Raising annulus pressure above hydrostatic pressure bursts the rupture disc and raises the mandrel, which seals the by-pass and traps the reference pressure for operation of the PCT valve. Using the PORT tool instead of the HRT tool, which is closed by application of string weight, allows the test string to be run in tension for stinging into a permanent packer.
The test string is greatly simplified by eliminating the drill collars, which the HRT tool requires for weight, and the ability to sting into a permanent packer eliminates the need for slip joints.
Once the PORT tool has been closed, it remains closed. The tool is balanced to inside diameter pressure and therefore is not affected by applied pressure encountered during well stimulation.
For safety, any pump overpressure and reference pressure trapped in the PORT and PCT tools is automatically bled off through the PORT relief valve as the test string is pulled out of the hole.
2.1.15 PCT pressure control tester tool
The PCT flow control test is hydraulically operated. Because no motion of the string is necessary, this tool is ideal for offshore operations or when testing in deep wells or in deviated wells. It is opened by applying pressure on the annulus. A spring and a nitrogen charge provide a positive closure. The nitrogen is compressed by hydrostatic pressure by means of a floating piston while running in the hole. This allows a low nitrogen precharge to be used at surface for improved safety. The PCT tool can be opened as many times as necessary for multiple flow and shut-in periods, for stimulation and for wireline perforating and sampling. The ball valve holds pressure from above and below; therefore, the string can be pressure tested while running in the hole.
The PCT tool can be permanently closed by using the overpressure rupture disc. This safety feature prevents the annulus pressure from increasing in an uncontrolled manner.
2.1.16 DataLatch system
The DataLatch system comprises a fullbore pressure and temperature downhole recorder system with optional surface read-out capabilities. It allows downhole recording during flow or stimulation periods. The two components of the DataLatch system are the MSRT MultiSensor Recorder/Transmitter tool and the LINC Latched Inductive Coupling tool.
The MSRT tool is a 5 in. ´ 21/4 in. fullbore, pressure and temperature, battery-operated downhole recorder. The LINC tool is designed to communicate with the MSRT tool to provide real-time surface read-out, retrieving previously recorded data and downhole recorder reprogramming.
The DataLatch system has definite advantages
·It is the only DST pressure acquisition system available with an outside diameter less than 5 in. This is the maximum OD size run in 7-in. heavy-weight casing.
·Without wireline in the pipe, the system is a true 21/4 in. ID fullbore tool, which is valuable when stimulating.
·With the LINC tool latched in place, the flow area remains equivalent to a 21/4 in. diameter fullbore.
·Its ability to monitor pressure above the flow control valve, below the valve and in the annulus ensures better quality control monitoring of the drillstem test in progress.
2.1.17 MSRT multisensor recorder/transmitter tool
The MSRT tool is the only fullbore, 21/4 in. ID electronic recorder available. It can simultaneously record three pressures; above the flow valve, below the flow valve, in the annulus or any combination of the three. One temperature measurement is also recorded. There is no obstruction to the flow of the fluid in the test string, which can be particularly valuable during the simulation phase of a test-treat-test or reperforation operation. The tool electronics are installed in a test string sub directly above the control
2.1.18 Subsea test tree (SSTT)
The purpose of this tool is to provide a means of shutting in the wells at the subsea BOP and then unlatching the upper string so that the rig can be moved in the event of a problem with the vessel.
The features of the tools are as follows: (E-Z tree used as example).
The E-Z Tree valve latch assembly consists of a valve assembly and a latch assembly, landed in the BOP stack and hydraulically controlled from the surface by a hose bundle running through the riser annulus. The valve and latch assembly is only 9 ft long, making it easy to handle and store. The valve assembly is less than 42 in. long (29 in. for 15,000 psi assemblies), making it possible to close the blind rams above the valve assembly after latch release in virtually any BOP stack. The complete hydraulic mechanism is contained in the latch, with no communication of hydraulic fluid to the valve and therefore no danger of contamination by mud or well fluids.
Pressure applied through a third hydraulic line can be used to help close the ball valve, to move or shear debris or to cut heavy wireline cables. The ball valve is capable of cutting wireline cable and coiled tubing. Features of the E-Z Tree assembly are:
·The hydraulic circuits are hydrostatically balanced, operation is unaffected by water depth.
·The valves are normally closed, and pressure is required to keep them open. The valve operators are removed with the latch when disconnected.
·The primary latch release is operated hydraulically from the control console at the surface. In addition, mechanical release is possible by rotating to the right to a predetermined torque.
·The valve can always be pumped open to kill the well.
·The design of the E-Z Tree tool allows injection of hydrate inhibitors, thus preventing possible jamming of valves when testing gas wells.
2.1.19 Lubricator valve
During offshore tests it is useful to perform wireline operations, and it may be an advantage to have a valve available that avoids the use of a lubricator above the flowhead. This special valve is called the lubricator valve, and it should be located at least 30 m below the flowhead. It enables the upper part of the test string to be used as a lubricator during wireline operations.
The lubricator valve is balanced; in case of hydraulic failure it remains in the last position (open or closed) in which it was placed before the failure occurred. An internal valve equalises the pressure across the lubricator valve prior to its opening. The equalisation is progressive to avoid the violent surge of well fluid inside the lubricator space. If the valve has been left in the closed position it is possible to open it by pumping fluid from the surface.
The lubricator valve is a ball valve that closes and seals with pressure applied either from above or below:
·To withstand well pressure when wireline tools are introduced or removed from the upper part of the test string, which is used as a lubricator.
·To test flowhead and surface wireline equipment.
2.1.20 Retainer valve
The retainer valve isolates the well fluids under pressure in the pipe above the E-Z Tree tool and prevents communication to the riser should it become necessary to disconnect. This is particularly important in deep water because it prevents pollution and eliminates dumping of high pressure gases into the riser. The retainer valve is run just above the hydraulic assembly and opens and closes in conjunction with the E-Z Tree valves.
3 Surface equipment
3.1 General
The surface equipment required to perform a well test differs considerably depending on the type of environment, the well condition and special requirements. Considerations include:
·Land: arctic, desert, jungle, etc. / ·Offshore: arctic, sea, swamp / ·High or low pressure, high or low temperature / ·H2S, CO2 or both / ·Gas, oil, water or all combined / ·Viscous or foaming oil / ·High flow rates / ·Populated or sensitive areas
On land, the surface testing layout is usually simplified. Burners are replaced by flare lines made from tubing, and compressors are not required. However, burners may be used on land in areas such as the jungle, where space is limited, or in densely inhabited areas, where any pollution is intolerable. Testing equipment and the methodology used are combined and adapted to meet various situations.
The production test equipment is normally rented from a production test contractor, the most well known being Baker, Expro, Schlumberger, Geoservices and Haliburton. A typical well test layout is shown in Section 5 and test tree layouts for floating and fixed rig installations are shown in Section 5. It is recommended to have a complete production test package on hire during the exploration drilling campaign. Although there is a chance that the equipment will not be used, the risk of waiting for production test equipment in view of the very high rental rates of drilling units is too great.
3.2 Surface test tree (STT)
The purpose of the STT is to direct and control the flow of well effluent from the tubing to the process equipment. The STT is placed above the Swivel and Hydraulically Actuated Lower Master Valve.
The STT is described in the following:.
3.2.1 Layout
·Main body containing a Master and Swab Valve placed in a monoblock assembly.
·Kill wing having a monoblock 90° elbow and gate valve. A check valve would be placed between the Gate Valve and the kill line.
·Flow wing, again a monoblock 90° elbow leading to a hydraulically actuated gate valve which is capable of opening against total differential pressure.
3.2.2 Valve data
McEvoy model "E-2" Valves would be used in the construction of the STT having the following features.
·Self sealing metal-to-metal gate valves
·Sealing groove provides secondary seal
·Pressure balance stem reduces operating torque
·Field replaceable seats
·Proven equipment
For extended use at temperatures of 300° the valve working pressure should be downrated to 14,500 psi. This limitation will have to be taken into consideration in designing the test programme.
3.2.3 Chemical injection facility
Chemical injection is provided by an injection port in the main monoblock assembly between the master and swab valve. Dual check valves are incorporated in the system and fittings are of a 9/16 " autoclave variety.
3.2.4 Variable production choke
It would be feasible to have a variable production choke placed in the flow wing elbow. This would have the dual benefit of controlling flow at the STT and producing a cooling effect in the down stream leg.
Due to the limited access to this equipment when it is rigged up it is suggested that a hydraulically operated choke (Masterflo) be used, however, it must be pointed out that an installation of this type will increase the size, weight, cost and exposure to damage.
3.2.5 Elastomers
All elastomers are of a Viton construction and are suitable for use up to 350°F.
3.2.6 Connections
The STT assembly will be fitted with the following connections:
·Kill wing: Grayloc connection
·Flow wing: Grayloc connection
·Landing string X-over: Hydrill PH-4 pin
·Top connection: Modified stub Acme box
3.3 Swivel
The swivel is placed below the Surface Test Tree and allows the string to be rotated independently of the STT so that packers can be set with the STT in place.
A typical swivel assembly comprises an upper inner mandrel rotating inside a lower outer mandrel with elastomers providing the sealing mechanism.
In very high pressure applications, two sets of seals are incorporated. These seals are located below the bearings and allow the tool to swivel under low pressure. When tension is applied to the tool during normal testing operations sealing is transferred to a metal-to-metal seal above the bearings.
Tubing pressure will also act to energise the seal so that a greater sealing force is provided when high tubing pressures are present. This will prevent the swivel turning, but will maintain metal-to-metal sealing integrity.
3.4 Hydraulically operated lower master valve
The purpose of this valve is to act as an additional master valve and is placed below the swivel. The valve is connected via an Emergency Shut Down (ESD) Panel to a number of remote manually operated shut down pilots. The lower master valve is a fail-safe valve and is capable of cutting a wire in the well.
The valve is independent of the automatic shut-down system (Surface Test Tree flow wing valve) and would be closed manually via the shut down panel as a last resort in the event of a failure in the surface system and it should be noted that the valve also protects the swivel in the event of a leak.
The valve comprises a housing, closing spring, valve operator mandrel and ball valve with metal-to-metal seals. It is a normally closed valve so that control line pressure forces the operator mandrel down compressing the spring and rotating the ball into the open position. When the control pressure is reduced the reverse occurs and the ball rotates to the closed position.
If wireline is present, the assist closure facility can be used and pressure is applied to an assist close line so that the ball cuts the wire and continues into the closed position.
A lock open facility is also present so that accidental operation of the manual shut-down system will not close the valve during operations when wire is in the well either prior to opening the well or at the conclusion of the test. In the event that emergency closure is required during these operations the lock open feature can be overridden by application of hydraulic pressure to the assist closure line.
3.5 Coflexip production hose
The purpose of the Coflexip Hose is to allow well fluids to be passed from the STT to the choke manifold. Coflexip hoses are generally used for this application on floating rigs because of the relevant movement between the STT and the rig floor. In areas of significant tidal ranges or during rough weather this motion can be considerable and a rigid pipe set-up is impractical.
3.5.1 Hose specifications
3.5.1.1 Construction
The hose is constructed of a number of concentric tubes that form a laminate that creates a pressure boundary, having the ability to withstand high temperatures and offers good resistance to external wear and tear.
Records should be kept recording use of the Coflexip hose in all applications where flowing temperatures exceed 220°F.
3.5.1.2 Chemical resistance
The hose will have resistance to the following substances throughout the temperature range: / ·Most acids and bases / ·Salts / ·Oxidising agents / ·Halogens / ·Alcohols / ·Chlorinated solvents / ·Aliphatic hydrocarbons / ·Crude oil
The hose, however, will be non-resistant at high temperatures to: ·Amins / ·Concentrated sulphuric and nitric acids / ·Sodium hydroxide / ·Ketones / ·Esters / ·Dimethylacetamide / ·Dimethylformamide / ·N-methylpyrrolidone
3.5.2 Hose connections
Grayloc metal-to-metal connections will be used on the hose. These connections are described in detail in Fig. 1937.
3.5.3 Certification, records and maintenance
Incorporation of flexible high pressure hoses in high pressure and temperature testing creates potential hazards because the production hose will be the weakest link in the pressures/temperature rating chain. It will be important to limit the flowing well temperature to less than 260°F for continuous use of the hoses.
Use of a hose of this type should not exceed the manufacturers recommendations. Stringent records will be kept detailing the use of the hose, so that exposure to temperature, pressure and corrosive fluids is monitored. In addition, for routine maintenance and testing, the hose will have to be internally inspected prior to, and after every job, detailed records of maintenance will be kept.
3.6 Data header
A data header is a length of pipe equipped with several connections for instruments that require measurements such as:
·Wellhead pressure
·Wellhead temperature
·Sand control data
3.7 Choke manifold
A choke manifold is used principally to control the flow rate. It consists of a number of valves and fittings arranged in such a way that the flow can be directed in one or two directions. This facility allows the flow through one or two choke boxes. Each box can accept different types of chokes fixed or adjustable. On the fixed side, calibrated choke beans are used. Each bean is manufactured accurately to a specific size, usually in graduations of 1/64 inch and is screwed into the choke box. This means that a specific flow rate on a specific choke size is reported. On the adjustable side, a variable choke is fitted to permit the change of the fixed choke without interrupting the flow during the change. The adjustable choke is a variable geometry orifice that can be reduced or enlarged without isolation of the choke box.
Both choke boxes utilise tungsten carbide or ceramic orifices to avoid erosion during clean-ups when sand particles may occur.
The choke manifold is also equipped with several pressure taps for recording pressures upstream and downstream of the choke and for monitoring the temperatures upstream and downstream of the choke boxes.
3.7.1 Nominal rating
Various chokes can be provided. The rating must complement the heater placed downstream as under certain conditions choking may take place at the heater. The choke at the heater is independent and different from the chokes in the choke manifold.
3.7.2 Valves
The choke manifold is a four valve assembly incorporating McEvoy "E-2" valves. It should be noted that the "E-2" valves are rated at 14,500 psi w.p. at a temperature of 300°F.
3.7.3 Connections
The inlet and outlet connections of the choke manifold of 15,000 psi w.p. shall be Grayloc type connections. Elastomers shall not be used.
3.7.4 Bleed-off valves
One bleed-off valve is provided per choke box so that pressure trapped between two closed valves can be bled down prior to attempting to remove the choke end cap. The McEvoy valves are also equipped with bleed-off valves.
3.7.5 Chemical injection
Chemical injection can be provided either in the upstream or downstream leg of the choke manifold. Injection points are also provided with a double check valve assembly in the event of failure of the injection hose or pump.
Hydraton double acting, air operated, high pressure, hydraulic pumps will be used for chemical injection. Each injection unit comprises a skid with two pump assemblies and chemical reservoir tank.
3.8 High pressure pipe work, hoses and piping
High pressure pipe work will convey the well fluids from the choke manifolds to the heater inlet. This pipe work will have the following features:
1.Pressure rating: 15,000 psi w.p.
2.Temperature rating: -28°F to 350°F
3.Nominal size: O.D. 3.5" and I.D. 2.3"
4.No chiksan, pipe work comprises straight sections or elbows
5.No threaded sections, all welded
6.Metal-to-metal seals (see below)
3.8.1 Hoses and piping
The various elements of the well testing set-up are linked together through different pipes and hoses selected according to service pressure, flow rate, and relative movement and lay-out equipment.
The service pressure of pipes and flowlines is dictated by the highest expected pressure at a particular point of the well test set-up. This will vary from as high as 15,000 psi (1034 bars) between the STT and choke manifold for a high pressure well test to 500 psi (34 bars) between the separator and burners.
The flow rate is used to determine the pipe size. Pipe diameter is usually 2 in. or 3 in. upstream of the choke and 3 in. downstream. 4-Inch piping is sometimes used downstream of the separator for high rate gas tests. Piping is referred to by its nominal size. The actual inside diameter can be considerably smaller for heavier pipe grades.
Piping routes should be kept as straight as possible to decrease pressure losses, erosion and cost. However, to accommodate relative movement of well test elements and equipment lay-out, a typical set of piping consists of a mixture of rigid (straight lengths and elbows)) and articulated (Chiksan) piping or flexible hoses. On high pressure tests, flexible hoses are normally preferred to Chiksan hoses because they are more reliable and relatively maintenance free. Piping elements and hoses are connected through "Weco" wing unions. These unions are designated by their nominal size and figure number (e.g. 3 inch 1002); the first two digits refer to the test pressure and the last two digits refer to the sealing method. For high pressure tests, a 15,000 psi "gray-loc" quick union is used. Where economically feasible dynetor (FMC product) connectors should replace Chiksans and Wecos.
3.8.2 Grayloc metal-to-metal seals
All high pressure pipe work should be equipped with Grayloc metal-to-metal seals as these are not susceptible to pressure/temperature degradation as compared to elastomers. A schematic of the parts of this seal is shown below. The Grayloc connector has three components: a metal seal ring, hubs and a clamp assembly. The seal ring resembles a "T" in cross-section. The base of the "T" is the rib that is held by abutting hub faces as the connection is made up. The top of the "T" forms the lips that seals against the inner surfaces of the hubs.
In assembly of the connection, the clamp fits over the two hubs and as it draws the hubs together, the seal ring ensures proper seal alignment. As the hubs are drawn together by the clamp assembly, the seal rig lips deflects against the inner sealing surface of the hubs. This deflection elastically loads the lips of the seal ring forming a self-energised seal.
3.9 Heat exchanger
3.9.1 Heaters and steam exchangers
These are used to raise the temperature of produced fluids for hydrate prevention, viscosity reduction and breakdown of emulsions.
Heaters can be classified as follows:
·Direct heaters, where the heating source is in contact with the fluid to be heated.
·Indirect heaters, where heat is transmitted to a heating medium, which in turn heats the fluid.
·Steam heat exchanger.
·Electrical.
Direct heaters are not recommended for use in well tests, due to the potential hazard of production coming into contact with an open flame.
Indirect heaters, fired by natural gas or diesel are the most commonly used, alongside steam heat exchangers, which are preferred where available and feasible (space). Electrical heaters require extreme care when used, and must be checked for proper zone classification (control box, etc.).
3.9.2 Hydrate prevention
Natural gases contain water vapour, and under certain choke-flow conditions the expansion is sufficient to lower the temperature of the flow so that hydrates are formed (particles of water and some of the light hydrocarbons in the natural gas become solid). This can become a serious problem if freezing occurs in the surface equipment; ice can block the chokes, the various valves and the flowmeters and apply full wellhead pressure to downstream equipment that may have a lower pressure rating. H2S and CO2 promote the formation of hydrates.
3.9.3 Viscosity reduction
High viscosity is a problem during testing because it impairs the flow of liquid through various lines and reduces separation and burning efficiency. Heating the fluid helps control the problem.
3.9.4 Breakdown of emulsions
It is necessary to separate the volume of oil from water so that it can be measured. Under certain conditions oil and water are miscible and will not separate unless the temperature of the mixture is raised. A heater helps to alleviate this problem.
3.9.5 Heater details
·Capacity: 3-4 MM btu/hr
·Pressure rating
-High pressure coil: Full well pressure
-Low pressure coil: 10,000 psi, 5,000 psi or 3,000 psi w.p.
·Connections: Grayloc hub clamp
3.9.5.1 Safety and monitoring devices
The heater will be equipped with the following safety devices:
·Heater body
-Rupture disc 110% body w.p.
-Safety relief valve @ body w.p.
·Steam lines
-Non return valve on steam inlets
-Degasser skid to monitor hydrocarbon in steam condensate line (returns).
Temperature will be controlled by a thermocouple device linked to a control valve on the steam inlet line. Inlet and outlet temperatures will also be recorded by the Surface Data Acquisition System.
Because the heater can withstand full well pressure up to and including the adjustable choke body, there is no need to provide over-pressure protection upstream of the heater. A high pressure pilot (PSH) linked to a ESD system will be placed downstream of the heater to protect the low pressure coil and separator. Additionally, a relief valve and vent line would also be present between the separator and heater in the event that pressure builds too quickly for the ESD to react. This vent line should be sized to handle full well production.
3.9.6 Valves and adjustable choke
McEvoy "E-2" valves will form the inlet manifold with the ability to by-pass the heater or shut-in the well at the inlet valve.
A Masterflo adjustable choke will be used to choke between the high pressure and low pressure coils.
SafetyDiesel shutdown valve activated by pilot light stoppage Flame arrestor on burner air inletDiesel shutdown valve activated by pilot light stoppage Flame arrestor on burner air inlet
3.10 Separator
3.10.1 Horizontal test separator
An intrinsic requirement for test separators is the capability to handle exploration wells where the nature of the effluent is not known. Consequently, test separators must be able to treat gas, gas condensate, light oil, heavy oil, foaming oil, as well as oil containing water and impurities such as mud or solid particles. A range of test separators has been designed for high content H2S service (sulphide stress cracking).
The 1440 psi, 42 in. ´ 10 ft. "elastique" separator was designed in two versions: one for temperatures above -20°F(-28°C) and the other for low temperatures to -50°F(-45°C). Separators have the following characteristics:
·A test separator should permit separation, metering and sampling of all elements or phases of the effluent.
·It should be able to separate the different types of effluent.
·It should also accept products containing quantities of impurities, such as muds and acids, when the well is cleaning up.
·The separator should be as compact as possible to facilitate transportation to the site and to be easily accommodated on offshore platforms.
·Adequate protective frames are also necessary for transportation as well as for protection against corrosion in tropical climates and marine environments.
·A test separator should have appropriate auxiliary piping for connection onsite.
Because of the versatility required, test separators are not expected to achieve a separation as perfect as production station separators. However, they must perform in such a way that the separated elements can be reliably metered.
For a station separator, the following additional conditions must be met if the gas capacities are guaranteed on the basis of liquid carry-over not to exceed 0.1 gal/MMft3:
·Liquid particle size in the moving gas stream is 150 microns or larger.
·Temperature of the gas stream is above the cloud point of the oil.
·Temperature of the gas stream is above the hydrate temperature.
·No foaming.
·Non heading flows.
3.10.2 Safety devices
The separator is equipped with the following safety devices:
·One High Pressure Pilot (PSH) linked to the ESD system and STT flow wing valve. This valve will be set at 1,300 psi and is designed to protect the vessel and upstream pipe work. In the event of the pilot being tripped the ESD System will shut the well in at the actuated wing valve.
·Two 3" ´ 4" Safety Relief Valves set at 1,440 psig. In the event that separator pressure reaches 1,440 psig these will open and vent the separator to the booms via a 4" vent line.
·One high liquid level alarm. This will alert the well testing personnel and the liquid level can then be adjusted manually to bring it back into the normal operation range.
·One low liquid level switch linked to the LCV with audible alarm. This level is more critical than the high level because if the liquid levels drops to the extent that gas is allowed to flow through the liquid lines, that may at some point during the test lead to the surge tank, there may exist a danger that the venting capacity of the surge tank is less than the amount of gas flowing into the vessel. In a situation such as this the working pressure of the vessel could easily be exceeded.
3.11 Gauge/surge tanks
3.11.1 Gauge tank
There are a number of ways to measure the liquid flow rate from the separator. These include inferential meters, positive displacement meters and gauge tanks.
The gauge tank is a non-pressurised vessel used to measure low flow rates or calibrate differential or positive displacement meters. The gauge tank is a double-compartment vessel. One compartment can be emptied by the transfer pump while the other compartment is being filled. The gauge tank is never used when H2S is present because gas released from the gauge tank is vented to atmosphere and would endanger personnel. Sight glasses with a scale allow the change in volume to be calculated since the physical dimensions of the gauge tank are known. Safety features include flame arrestors on each vent of the gauge tank and a thief hatch in the event the vessel is accidentally overpressured. A grounding strap is attached to the gauge tank to prevent a build-up of static charges. Shrinkage may be controlled by a thermowell provided on each compartment of the gauge tank.
3.11.2 Surge tank
The surge tank was originally designed as a secondary stage of separation but now serves an additional function because it can replace a gauge tank when H2S is present.
The surge tank is a pressurised vessel and is used to measure flow rates. The surge tank is a single-compartment vessel with an automatic pressure control valve on the gas outlet line to maintain a backpressure that can be set to any pressure up to 45 psi. Sight glasses allow the change in volume to be inferred with knowledge of the physical dimensions of the surge tank. A high- and low-level alarm warns when gauging will be stopped.
Safety features include a safety relief valve in the event the vessel is accidentally overpressured (the maximum working pressure is 50 psi). A grounding strap is attached to discharge the surge tank in the event of any static charges. An accurate measurement of shrinkage and meter factor can be obtained at the surge tank.
When designing the safety devices on the surge tank, the following should be addressed:
3.11.3 Safety devices
·One High Pressure Pilot (PSH) linked to a secondary ESD panel that is linked with an actuated shut-down valve on the separator oil outlet. If the pilot senses high pressure in the line from the separator to the surge tank, a condition that would exist if the liquid level was allowed to fall, allowing gas to flow to the surge tank, the shut-down valve would close and prevent any further flow into the tank before the pressure exceeded the design working pressure. Any gas that managed to get to the tank would then be vented by the normal means.
·One 3" ´ 4" Safety Relief Valve set at 50 psig. In the event that vessel pressure builds up to 50 psi the valve will open and vent overboard via the vent line.
·One high level audible alarm (LSH). This will alert the well testing crew if the liquid level approaches the top of the sight glasses.
·One low level liquid audible alarm (LSL) that will sound when the liquid falls too low.
3.12 Transfer pumps
Transfer pumps are designed with a centrifugal-type pump which use either an electrical motor or a diesel engine as the drive unit. The pumps supply oil to the burner when there is not enough pressure for the well effluent to atomise and burn cleanly through the burner or are used for re-injection of effluent into flowlines after flowing through the production test units. HRS transfer pumps come in various sizes to handle different volumes and pressures. These units have relief valves and bypasses to recirculate fluids if necessary.
The units can be controlled manually, by high/low level switches in the stock tanks, or by means of a level controller and a system of control valves. The units are designed for H2S conditions.
On electrical drive units an outside power source or independent generator which can meet supply requirements of the motor will be required.
3.12.1 Benefit of design principles
3.12.1.1 Electrical drive
·Compact, skid-mounted for handling ease and space saving
·Explosion-proof motor and control box
·Low maintenance-type pump.
3.12.1.2 Diesel engine drive
·Compact, skid-mounted for handling ease and space saving
·Air-start turbo-charged diesel engine
·Low maintenance-type pumps.
3.12.2 Guide to transfer pumps
3.13 Oil and gas manifold
The oil that comes from the separator can be directed through an oil manifold to the gauge tank, surge tank, production flowline or burner depending on the circumstances prevailing during the test. Normally, the manifold consists of 5 inch ´ 2 inch ball valves arranged in such a way that flow from the oil outlet on the separator can be directed to a gauge tank. From the gauge tank, flow is piped to the oil manifold, which is connected to a transfer pump where pressure is boosted so that it can be supplied to a burner or reinjected to a flowline. If a surge tank is used, the manifold serves the same purpose. In effect, it allows the flow from the separator to be directed without interruption to the burner or flowline. For offshore tests, two burners are normally used to allow continual testing irrespective of the prevailing wind direction. The oil manifold also allows the selection of either port or starboard burners without stopping the well test because of undesirable wind directions. The gas manifold can also provide these functions.
3.14 Relief valves and lines
The purpose of the relief valves and lines is to allow well-fluids to vent safely to atmosphere in the event abnormally high pressures are seen in any section of the process train. Abnormally high pressures could exceed the normal working pressure of the equipment and, if not vented safely, would create a catastrophic failure in the system.
Each vent line has a safety relief valve set at a preset pressure (normally equal to, or just less than the working pressure of the system it is protecting). When the line or vessel pressure exceeds this pressure, the valve will open and allow the fluid to be safely vented along the burner boom to the gas flare. It is important to have this line vented to the end of the boom because of the dangers of venting high volumes of potentially toxic gases and flammable gases near the rig. There will not be any valves installed downstream of relief valves to guard against inadvertent closing of one of these, preventing blow down.
Relief lines are proposed in the surface testing layout:
·1,440 psig relief line set between the heater and separator. This line is primarily designed to protect the low pressure coil of the heater and the separator manifold in the event that the well is shut-in at the separator bypass manifold. It will also act as a redundant relief system in the event that the two separator relief valves malfunction. From the relief valve a 4" line will lead the fluid into the HP vent line joining the vent line from the separator.
·Separator relief line designed to protect the separator if pressures exceed the design working pressure of 1,440 psig. Two relief valves are provided and pressure is vented through the 4" HP vent line to the boom.
·Surge tank relief line performs the same function in the lower pressure surge tank. The valve is set at 50 psig and will vent through a line to the boom or overboard.
4" relief lines are recommended on the basis that a reasonable degree of venting capacity is present and yet the lines are easily handled when rigging up the equipment.
Relief lines where possible should be run along the boom so that venting of fluids takes places as far as possible from the rig.
3.15 Booms and burners
Burner booms and burners are mounted on the rig in order to provide a safe means of disposing of hydrocarbons produced during a test. A complete system comprises a number of elements being boom mounting system, boom and burner.
3.15.1 Burner boom
The boom will be designed with the following parameters in mind:
·Heat radiation created by hydrocarbon burning (length).
·Load requirements created by the product lines.
·DyCompanyic requirements as determined by the type of drilling support.
Heat radiation studies can be conducted in order to determine the incidence of heat produced when burning the anticipated amount of hydrocarbons. This may influence the location of the booms and the water screens required to protect vulnerable equipment such as lifeboats, etc.
The load requirements for the booms will be based on the boom supporting the following produced lines:
·1 ´ 6" gas line
·1 ´ 3" oil line
·1 ´ 2" air line
·1 ´ 6" HP vent line
·1 ´ 4" vent line
These lines have been sized according to current well testing practice in order that excessive back pressures are not created when flowing at the design flow rate through any of the lines.
DyCompanyic loading on a boom placed on a semi-submersible rig is greater than for a jack-up rig which does not experience any of the motion associated with yaw, pitch and heave. Therefore care has to be exercised when dealing with both types of support.
The boom is slung from guy lines that are lead up to a king post set on the deck of the drilling rig. Lateral lines prevent any sideways movement of the boom in heavy seas or high winds.
3.15.2 Burners
Multiple headed burners are available that would be sufficient to dispose of the anticipated liquid flow rates. 12,000 bpd of liquid can be atomised at a discharge pressure of 200 psi. Each head is equipped with a 2" atomiser nozzle fitted with an adjustable choke type feature which allows the nozzle size to be adjusted so that optimum atomisation can be achieved. Each head can be isolated so that during periods of lower flowrate a reduced number of heads can be used with each head operating at its optimum efficiency.
The burners can also operate satisfactorily at lower discharge pressure of between 60-70 psi. 4,000 to 6,000 bpd of liquid hydrocarbon can be burnt at these lower pressures.
The burners are equipped with a dual (redundant) air driven magneto ignition system that ignites a propane pilot. The same system is utilised on the gas flare and if necessary on the HP and LP vent lines.
3.15.3 Operation
The oil flows from the separator into the atomiser where the chamber design creates a swirling motion. Then, the oil emerging though the orifice is converted into tiny oil droplets by the turbulence of the compressed air exhaust. Once ignited, the flame is rich and underoxygenated. In the burner, the multiple focused jets of sprayed water (about 6 ft from the burner head) arrive at the flame, where the water is evaporated and water-gas reaction occurs. This reaction prevents the production of carbon black, and the flame burns clear and yellow without fall-out of solid particles of unburnt oil.
When starting up a burner, direction and speed of wind has to be noted and the corresponding boom/burner selected. The sequence of events includes:
·The pilot flame is lit. Compressed air valve is opened.
·Water valve is opened and pressure checked (300 psi maximum). Check that water-spray is evenly distributed.
·Oil production is admitted to burner and ignition occurs. The flame may be 75 to 100 ft long.
Where oil flow is insufficient, the number of burning heads should be reduced until conditions are satisfactory. If, however, the backpressure at the burner is too high for the separator to operate properly, either additional burner heads should be used or the separator pressure should be raised. If neither step is effective, the well needs to be choked back accordingly.
3.15.4 Mud burner
Oil-base muds can be burned by adding diesel oil. For example, for a mud consisting of 40 per cent oil, 27 per cent solids and having a viscosity of 124 cst, it is necessary to dilute with 3 parts diesel to 1 part mud to attain proper burning. With lower viscosities and slightly more oil, the ratio of diesel to mud could be reduced to 1.2. Burning is satisfactory only where oil is the continuous phase in the mud.
In principle, no fall-out is permissible in line with environmental/pollution policies. There may be occasions where well debris, mud, sand, heavy paraffins, or high water/emulsions may cause fall out problems. Enough dispersants should be available on board to handle these unplanned incidents.
3.16 Field laboratory
A field laboratory is generally included as part of the rented test equipment. The laboratory should be located in a safe area and contain the following equipment:
1.A heated calibration bath and deadweight tester to calibrate bottom hole pressure/temperature elements.
2.A centrifuge for determination of sediment and water.
3.Hydrometers and corresponding glassware to determine the specific gravity of the produced crude/water.
4.A gas balance to determine the specific gravity of the gas produced.
5.Viscosity apparatus to determine the viscosity of the oil/condensate produced at 100 and 150 degrees F.
6.Equipment to determine the pour point of the crude/condensate of a fresh wellhead sample.
7.Desk, calculator and typewriter to assist in reporting.
8.Bottom-hole pressure/temperature recorders, clocks, tool, charts, spares, etc.
9.Two bottom hole samplers and equipment to transfer bottom hole samples to special shipping containers. This is in case the service company, owning the field laboratory, takes the bottom hole samples with a sampler run on the piano wire. Otherwise transfer equipment and samples are supplied by the perforating company.
The following equipment is also stored in the laboratory:
1.Pressure gauges, a sufficient number of various ranges.
2.Surface and subsurface temperature/pressure recorders.
3.Orifice plates.
4.Chemical injection pumps (for dehydration, anti-foam and glycol).
5.Special shipping containers for PVT - samples, sample bottles.
6.Small work bench with vice, tools, etc.
7.Spare nipples, elbows, tees, unions, hoses, etc. for hooking-up instruments and connecting flexible piping.
8.U-tube.
9.Deadweight tester for use at the wellhead or flow manifold.
3.16.1 Analysis services
Generally, the mud-logging services company on the drilling rig can supply the following, in addition to their routine services (verification of contract is required):
1.Compositional analysis, resistance and pH of produced water.
2.Approximate analysis of hydrocarbons in produced gas with a gas-chromatograph.
3.CO2 and H2S measurements of the produced gas.
3.17 Emergency shut-down (ESD) systems
ESD systems form an important part of the safety and control of the testing system. The ESD system shown in the layout drawing shows a manual system operating a fail-safe ball valve and an automatic system operating the hydraulically actuated wing valve on the STT.
This system is necessary because:
·Redundancy is built into the system with manual and automatic ESD's operating different valves.
·Automatic system closes the wing valve only, so there is no danger of cutting any wire that may be in the well.
·Simplicity, automatic pilots have been minimised in order to reduce the potential of unnecessary shut-ins through equipment malfunctions.
·Manual system is capable of cutting wire and protects the swivel in the event of failure.
3.17.1 Manual emergency shut-down system
The manual shut-down system comprises the hydraulically actuated lower master valve, a shut-down panel and a number of manually operated pilots. The pilots would be placed as follows:
·Drill floor
·ESD panel
·Separator
·Choke manifold
·Company office
·Helideck
The pilots are connected to a ESD panel by polythene hoses charged with air. Once air pressure is bled from the line the ESD panel will dump hydraulic pressure from the valve control line and the lower master valve will close sealing the ball valve.
The system will take in the order of 10 seconds to close the valve.
The ESD panel should be equipped with a non-return valve so that in the event that supply pressure is lost, the system will not close in the well. Additionally an audible alarm will alert the well testing personnel.
3.17.2 Automatic shut down system
The automatic system will operate the hydraulically actuated wing valve on the flow wing of the STT and comprises an ESD panel, hi-pressure pilot and lo-pressure pilot. The system will work as follows:
·A high pressure pilot (PSH) will be placed in the line between the heater and the separator inlet. The pilot will be set to trip at 1,430 psig and is designed to protect the separator and heater low pressure coil
·A low pressure pilot (PSL) will be placed upstream of the choke manifold and will be set when the well is stable at value consistent with the flowing wellhead pressure. In event that the pressure suddenly drops due to a leak of failure in the line, the pilot will trip.
·An ESD panel will act as the interface between the air lines and the actuator hydraulic line. Once air pressure is lost hydraulic fluid will be dumped to close the valve. Like the manual shut-down panel, the automatic panel will be fitted with a supply non-return and an audible alarm.
·Once hydraulic pressure has been lost to the actuated wing valve, the valve will begin to close. A quick exhaust feature will minimise the closure time so that the well can be shut-in at the gate valve.
Approximately 6 seconds would be required for the system to operate and close the wing valve.
As a general rule, enough time, effort and planning has to be allocated to choice of offshore mobile vessel, well-testing contractor, pre-mobilisation works/checks, etc., before commencement of a test. Pre-hook-ups and testing of rigid flowlines, burners. ESD loops, etc. can radically impact on on-site preparation time, and minimise downtime.
4 Equipment layout
4.1 Surface lay-out
General lay-out and environmental considerations for a safe lay-out of surface testing equipment include:
·Equipment lay-out according to classified area and recommended spacing
·Grounding of units
·Safe and approved electrical connections
·Anchoring of piping and connections
·Colour coding to identify working pressure (WP) and fluids
·Wind directions
·Workplace tidy, clean, not slippery
·Spark-proof hammers
·Safe pressure fittings
·Repair of vessels following standard safety regulations.
Safety standards for equipment on site
Classified zonesOnshoreOffshore
The area around:
Wellhead - Type 245 ft (15 m)30 ft (10 m)
Separators - Type 230 ft (10 m)10 ft (3 m)ª
Gauge tanks - Type 145 ft (15 m)45 ft (15 m)
Outlets of flares, safety valves and vents - Type 145 ft (15 m)45 ft (15 m)
Gas forced heaters and burners must not be used in classified zones.Wireline winches must not be used in classified zones (unless certified).
ª Provided the rupture disc is replaced by a pressure safety valve. Otherwise, the area around the separator is a Type 2 zone within a radius of 45 ft (15 m)
Recommended practices
Installation without a heater: The separator should be located 75 ft (25 m) away from the wellhead. Offshore, this distance may be reduced to 40 ft (13 m). The separator instrument control should be supplied with compressed air. The pressure relief valve must be connected to a safe area.
Tanks equipped with a flame arrestor: The sniffer pipe must be connected to the rig flare. Moreover, manhole cover should be bolted during operation.
In some instances (lack of space), all the recommended distances cannot be respected, however: equipment must never be installed in the classified zones of the wellhead (Type 2 zone) Fired heaters, burners and wireline winches must never be installed in classified zones
5 Wireline equipment
Extensive use is now made of wireline techniques and a variety of wireline equipment and tools are available to perform operations which were previously performed using a well pulling hoist or a drilling unit. Success in performing wireline operations requires personnel with thorough knowledge of equipment/tools and extensive operating experience.
A specialist wireline operator is required with at least 5 years experience, who possesses the knowledge and the ability to "think down-the-hole", while performing demanding physical work during irregular working hours. The service charges for a specialist operator are high ($950/day US). Insufficiently trained or inexperienced wireline operators may make mistakes resulting in many costly rig hours. Company approved supervision is recommended over contractor wireline operators. Wireline equipment for production testing operations is generally rented from the production test contractor.
5.1 Wireline unit
For slickline wireline work, which is normally required during production testing operations, a minimum 40 hp single drum unit with 20,000 ft, 0.092 in. wire is sufficient. The unit should be capable of generating adequate line speed and pull (say 3000 ft/min on full drum at 2000 lb pull). There are wireline packages available consisting of two units i.e. the reel unit and the hydraulic power pack. When the slickline wireline contractor provides the bottom hole pressure and temperature measurement service with surface read-out, he will use a large cabin type wireline unit with the power pack mounted on the same skid. In this case it may be advantageous to have a dual reel unit (electric cable and slickline). However, positioning the unit close to the Xmas tree is not always possible due to its size. To save space it may be more attractive to use the electric cable of the logging contractor. However, this is often much more expensive than using the electric cable from the production wireline contractor. Irrespective of wireline unit chosen, the power pack must be suitable for use in a zone 2 area.
Slickline services may be required whilst testing to assist in Tubing Conveyed Perforating, determine if DST tools are functioning, obtain bottomhole samples and bottomhole pressure information. It would, however, be advantageous in terms of complexity of operations and regard to safety, to limit as much as possible wireline operations in the well.
5.1.1 Types of wires
The types of wire available for use are indicated below. Selection will be influenced by the degree of corrosive elements existing in the well fluid.
Slickline0.092" orSuper 70H2S resistant
0.108"M 35Higher H2S resistance
Braided line3/16"Standard swabline
Monoconductor3/16"Polypropyleneup to 300°F
Tefzel300 to 500°F
It should be noted that the degree of sealing at high pressures on slickline is much greater than a braided line and use of the latter should be avoided.
5.1.2 Wireline unit
5.1.2.1 HP Power Pack Specifications
Engine type4 Cylinder For Type 272275 HP
Safety systemsZone 2 (O.C.M.A. MEC. 1 SPECIFICATION); Inlet and exhaust flame traps ; Over speed shutdown; High Exhaust or water temperature shutdown; Antistatic equipment; Air starter motors
DimensionsLength7 ft 9 ins
Width3 ft 7 in
Height4 ft 3 ins
Weight2,711 lbs
5.1.2.2 Double drum winch specifications
Drum capacitiesUpper drum0.108" slickline24,000 ft
Lower drum3/16" swabline20,000 ft
Optional3/16" Monocond.20,000 ft
Max line speedUpper drumSurface3,200 ft/min
Subsurface1,100 ft/min
Lower drumSurface860 ft/min
Subsurface440 ft/min
Line pullUpper drumSurface4,680 lbs
Subsurface8,000 lbs
Lower drumSurface8,000 lbs
Subsurface10,000 lbs
Power packHydraulic oil42.5 gals/min
DimensionsLength12 ft 4 inch
Width4 ft 7 inch
Height7 ft 4 ins
Weight9,120 lbs
5.2 Pressure control equipment
This comprises the BOP, lubricator and stuffing box and allows surface pressure to be contained when running wireline tools into the well.
When no lubricator valve is used, the lubricator consists of at least two 8 ft sections of appropriate size, a stuffing box for solid wireline ranging from 0.092 in. to 0.108 in. OD wire, and a hydraulically operated BOP. Maximum working pressure should be 5000 psi, 10,000 psi, 15,000 psi and suitable for sour service.
When an electric line is used, a flow tube with grease injection should be used below a hydraulic operating stuffing box. The BOP should be of the twin type with a grease injection port between the rams, the lower rams should be installed upside down to normal to ensure grease retention. Through this port, grease can be injected between the two pairs of closed rams to obtain a gas tight seal around an electric logging, line. Without grease injection, well flow could penetrate the spaces between the individual strands of wire.
5.3 List of wireline tools
A complete list of necessary wireline tools and equipment will be supplied by the production test contractor and will vary depending on the completion to be run. The production test contractor should always be requested to pack the wireline tools in a special tool box so that these cannot be mixed with the other production equipment.
6 Drill stem testing (DST)
6.1 General policy
The following guidelines have been laid down for DST operations. Originally the purpose of DST was to obtain representative formation fluid samples. As such, DST can be defined as the process of allowing an interval to flow into an empty or partly empty drill pipe thereby measuring the downhole pressure. Present day DST operations are often extended, to obtain reservoir data, by flowing the well at surface for prolonged periods. The following guidelines should assist the operator to carry out DST operations safely.
6.2 DST tools on floating rigs
The guidelines for use of DST tools on floating rigs are as follows:
1.Always incorporate a subsurface test-tree (SSTT) so that the well can be closed at sea-bottom level and the flow conduit disconnected. A short SSTT is preferred so that the blind rams of the BOP can be closed above it as a back-up shut-off, independent of the SSTT. A wireline cutting capability should be a design feature of the SSTT selected.
2.The use of accessories which are activated by annulus/tubing pressure has the following advantages:
a)Enables setting and spacing out on floating rigs, especially during rough weather.
b)Eliminates manipulation of the string which may damage the hydraulic lines to the SSTT.
c)Drastically reduces wireline runs, with its inherent risks.
The use of a hydraulic set permanent type packer is recommended. Swabbing in the well when pulling out retrievable packers always exists and therefore a potential danger exists during this operation.
3.The use of a packer in an open hole is not recommended for the following reasons:
a)It is often difficult to obtain a shut-off.
b)It can create all kinds of operational problems such as losses, kicks, getting stuck, caving, plugging or cutting-out of test tools.
c)The increased risk of getting stuck is especially troublesome as a result of the requirement of an SSTT.
4.The use of a tester valve which is operated by manipulating the string is not recommended for the same reasons as in (i) and (ii) of (b). The use of annular pressure operated equipment is recommended instead. There is a wide variety of these equipment and a choice must be made based on objectives.
5.It is recommended that tubing (with metal to metal seals) is used instead of drill pipe when hydrocarbons are expected.
6.3 DST On land and jack-up rigs
The guidelines for use of DST tools on land and jack-up rigs are as follows:
1.Always incorporate in the string at the surface in the vertical run a fail-safe valve so that the well can be closed-in automatically. An actuator with wireline cutting capability should be considered when wireline work is foreseen.
2.Both permanent and retrievable packers may be used. However, the potential danger of swabbing in the well when pulling out retrievable packers must be emphasized.
3.The use of a packer in openhole is not recommended for the same reasons as stated previously.
4.Both mechanically and hydraulically operated tester valves may be used.
5.When hydrocarbons are expected, use tubing (with metal to metal seals) landed in a tubing hanger spool. This restriction will have an influence on the choice of the type of DST tester valve.
In case of exploration wells, when gas composition, GOR, pressures and temperatures are not fully known, the use of tubing suitable for sour service and with metal to metal seals (e.g. Hydril) should be used.