RLWI – Riserless Well Intervention – The equipment
RLWI – Riserless Well Intervention – The equipment
Riser less well intervention refers to any intervention performed without high pressure tubings AKA Riser during interventions on subsea wells. The unit is installed from an intervention boat or vessel. It does not require rig mobilization.
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The system can be used on both shallow and deepwater operations ( m max. water depth), which means that it can be installed and/or retrieved by using both guidewires or guidelineless systems (normally for water depth > 500 mTVD).
The vessels are slightly longer than 100 m (ca. 115 m average) x 25 m at its widest area. They have a deck area of m2 along with a load capacity of ton. Figure (1) shows an example of an intervention vessel
In the drawing, it is possible to identify where the WCP (Well Control Packager) is normally skidded into parking position, the location of the PCH (yellow) the two WL units, the chemical injection unit (CIU ' pink/magenta) and the red rectangle is the well intervention area where operations take place. On both onshore and platform facilities it is known as 'Well Intervention Tower' (WIT) however, for RLWI operations the unit is simply called moonpool or well intervention area.
The RWLI packages are picked up and made up one by one at the moonpool area. The equipment is run in the following order:
1.- Well control package
2.- Lower lubricator package + Lubricator tubulars + Upper lubricator package, all in one run. The Umbilical Terminal Head (UTH) is also connected to the LLP during this step.
3.- Pressure Control Head + WL tool/WL cable.
The RLWI system is divided in two stacks:
1) Upper
2) Lower
Upper Stack
Lower Stack
Pressure Control Head (PCH)
The Lower Intervention Package (LIP) or Well Control Package (WCP)
The Upper lubricator package (ULP)
The XT connector
Lubricator tubulars (LUB)
Tool trap*
The Lower lubricator package (LLP)
*Applies only for the Mark I system
The following drawing illustrates both the deploying of the unit and its main components.
Equipment and design
FMC technologies was the first company to develop the prototype. Today other companies such as EXPRO, PGS, Helix Group have their own versions of riserless light intervention units.
Currently, there are two design versions of the RLWI system:
1.- RLWI Mark I (MI)
2.- RLWI Mark II (MII)
Some of the differences, advantages and disadvantages between both systems are addressed in the table below:
Mark I
Mark II
Advantage
+The system is controlled from the vessel. A WOCS and HPU unit is installed on the topside deck.+The tool trap is installed and used to colect the WL tool in case of an emergency disconnect/closing the shear ram.+Grease is being pumped directly into the ULP from surface through the umbilicals.+If equipment fails it can be evaluated if needed to retrieve the stack back to surface since part of the equipment is controlled from the topside. +Improved stuffing box to provide with better grease capacity.+Increased lubricator length to hold longer WL strings (up to 25 m long).+Lighter equipment (approx. 8 ton)+Can be deployed guidelinelessly.+Includes an upper lubricator package with a wireshear cutting ball valve to shear up to 7/16' braided lines and sealing.
+Electrohydraulic control system. Reducing the amount and size of umbilicals.
+ Uses less grease injection and it is automatized.
+Upgraded to kill/bullhead wells through the killing hose. It does not allow for circulation.
Disadvantage
-Heavier equipment. It has to be guided and supported on a separate lift line to maintain stability as the lubricator is deployed and operated on the seafloor.-Not viable to be used on deepwater or depths > 500 mTVD.-All fully direct hydraulic control systems plus, grease and chemical injection units leading to heavy use of umbilicals. Fatigue problems for the umbilicals due to prolonged heave compensation. Replacement of umbilicals is both expensive and time consuming.-Requires more topside/deck space.-Cannot kill/bullhead wells.
-Using same control power system as ROV on board can lead to double downtime in case of failure.-Self-monitoring, electrically controlled grease systems do not allow for manual operation in case of failure.-The use of lubricator reservoirs on the LUB tubulars depends on small valves and pump technology posing new challenges to sudden failure. System is known for currently having problems and end up being retrieving equipment back to surface, and changing LUB valves and pumps, increasing downtime.-Increasing water depths pose greater challenges for heave compensating measures and umbilical sizes plus, equipment power.-In case of sytem failure the equipment needs to be retrieved to surface since everything is underwater.
Weight: 70 tonHeight: 30 m Weight: 50 tonHeight: 25 mThe main difference in terms of subsea equipment between these two is the tool trap. On topside equipment the main difference is that the Mark I uses an Electro-hydraulic WOCS (Workover and Control System) and a High Pressure Unit (HPU).
Subsea Equipment Description
Pressure Control Head (PCH)
Located on top of the RLWI lubricator it provides means for pressure barrier and seal towards the wellbore during WL operations. The seal is created around a moving WL, allowing intervention access to wells under pressure.
Prior to installation, the PCH shall be assembled with WL inside the surface thereafter, lowered down to the seabed by means of an external lifting wire. Two (for this case) guidewires shall secure the deployment. At seabed the PCH shall be connected to the ULP by means of a re-entry hub.
It is 1-one of the primary well barriers when the WL enters the well. The seal is achieved by pumping viscous grease between the limited free space in the WL and the narrow tubes inside the PCH, as shown in figure (4).
Height: 3,9 m (4m) Diameter: 1 m Max pressure: 690 bar.
The combination of a viscous enough grease, which corresponds to the proper size of the wireline on use, is what guarantees the integrity of the seal barrier. The line wipe wiper cleans off the excess of grease from the WL to minimize grease spill to sea. The grease pressure is supplied by a grease injection system located in the LLP and the pressure must always be higher than the wellhead pressure.
The type of grease to be injected on the PCH must be chosen accordingly to the size or kind of cable and wireline used. In a few words:
Wireline A <-> Grease A
Where A= 7/32', 5/16', etc..
The main characteristic of any grease is its viscosity therefore what matters about the cable is its diameter size not the type, most of the time. Slicklines might not need too much grease since they offer less friction when running in and pulling out of hole.
Additionally, there are a couple of stuffing boxes installed, which allow a static seal around the WL if the grease injection fails.
The upper stuffing box (USB) works as a static seal on a stationary WL (e.g. Slickline). A back-up barrier is needed during braided/electric line operations. It seals fluid or gas pressures to the wellbore. During operations, the USB also works as a MEG injector.
A dual stuffing box is installed and it is located between the flow tubes and the tool catcher. The dual stuffing box (DSB) is equipped with a grease injection point between each rubber element, working as a back-up barrier element. Its main purpose is to seal fluid or gas pressures to the wellbore. In operations, the DSB also works as a grease and MEG injector and a connection point for hoses. The DSB has the function for MEG injection but it is not normally used for this purpose. The boxes and their connection to the Upper Lubricator Package (ULP) can be observed in the drawing below.
The tool catcher literally catches the fishing neck of the rope socket if the WL is accidentally pulled from the rope socket, preventing the loss of the tool string. The mechanism consists of claws that automatically grip around the top of the fishing neck. When the tool is caught, the catcher must be hydraulically released to free the tool.
During braided wire operations, the pressure barrier is created by adding or injecting viscous grease into the grease housing, building a pressure higher than the current well pressure. Additionally, an upper stuffing box works as a static seal on a stationary WL. A back-up barrier is needed during braided line operations. A dual stuffing box is installed and is located between the flow tubes and the tool catcher. The dual stuffing box is equipped with a grease injection point between each rubber element, working as a back-up barrier element. The PCH works as a final interface between the subsea installation and the seawater column.
Upper Lubricator Package (ULP)
The ULP comprises the Lubricator tubulars and lubricant reservoirs. It provides one of the barrier elements required in order to be able to secure the well at all stages of the intervention. The WL shear seal valve (WSSR ' CBV; cutting ball valve) in the ULP is capable of cutting WL or slickline only and sealing the wellbore afterwards. However, it cannot cut tools.
It has a 10' connector towards the PCH. It can be considered as a mechanical barrier element and it is the connection between the PCH and the lubricator, see figures (7) and (8)below
Lubricator Tubulars (LUB):
Lubricator Tubulars. The LUB has two lubricator reservoirs (on Mark II). Each reservoir has the capacity for 185 lts.
To get the toolstring into the pressurized well there has to be an intermediate storage facility, capable of holding the length of the entire toolstring. The LUB acts as such device. It is an intermediate storage facility capable of holding toolstrings up to 25 meters in length. The toolstring is installed inside the lubricator. The lubricator is then sealed off and pressure tested. The valves isolating the toolstring and the LUB from the well are then opened, and the toolstring can enter the well.
The lubricator section is the parking space for the wireline toolsting on its way in or out of the well, while pressurizing the system before opening the well or depressurizing the system after the well is closed in. If excessive forces are applied to the stack in an emergency situation, the lower part of the lubricator section will bend and act as a weak link in the system located in the safety head above the LLP. This will ensure that excessive bending forces are not transferred from the well intervention system to the permanent installation system. The lubricator assembly is hydraulically connected and locked on to the LIP assembly.
When the toolstring is installed inside the lubricator. The lubricator is then sealed off and pressure tested. The valves isolating the toolstring and the LUB from the well are then opened, and the toolstring can enter the well.
Lower Lubricator Package (LLP)
The Lower Lubricator Package is the connection between the LIP/WCP and the LUB. It acts as a running tool for the Well Control Package and it is here, where the connection between the control umbilical, well kill hose and control module is achieved by means of the Umbilical Terminal Head (UTH). A tank filled with Oceanic 443 fluid is used to operate the valves inside the LLP.
The umbilical is connected to the LLP, and from there the EQD system can be activated to free the vessel in case of a drift off/drive off situation. Additionally, it contains a well kill hub and a subsea grease injection system for the WL. The EQD sequence takes max. 2 minutes.
On Mark I designs, at the bottom part of the assembly is a subsea tool trap, which prevents unintentional dropping of the toolstring into the well with the lubricator section at its top.
LLP functions and features:
' Well kill connection
' Mounting base for control module and umbilical termination (UTH).
' EQD facility of umbilical connection
Well Control Package (WCP):
In some books or presentations, you might find this part of the equipment under the name Lower Intervention Package (LIP ' Especially when referred to the Mark I design). It is the equivalent to the BOP used for regular drilling and completion operations. It is the main mechanical barrier against the reservoir. It contains a shear ram, which is qualified for cutting WL, CT, DP (yes, drillpipe, the one and only), and even some tools. Then, it closes the well and shuts it in. The WCP can be connected to both HXT and VXT. An adapter is installed and provides connection function. There are several adapters for both types of trees depending on the tree brand (FMC, Aker, Vetco).
HXT ' FMC, Aker, Vetco
VXT ' Cameron, FMC, Aker (?), Vetco (?) (Not really sure about these two last ones)
It contains two tanks for well equipment operation fluid, 1-one with a capacity for lts and the second one for 500 lts. The biggest tank contains Transaqua fluid, which is used to operate the XT valves. The second and smallest tank contains other type of fluid (most likely Oceanic 443) and it is used to operate the WCP itself. Both fluids have a density of 1,07 sg. The Umbilical Terminal Head (UTH) is connected on top of the WCP as shown in figure 2.
The connector on the WCP for the XT is hydraulically operated. At the same time, the LLP is hydraulically connected to the WCP and the PCH to the LLP. Everything on the RWLI system is hydraulically connected, even you. It is called to connect hydraulically to connect devices by using pressure lines filled with liquid fluids. The devices are either closed or open when pressure is applied.
The LIP main features are:
' Main barrier element
' Has 18 ¾' connector towards HXT and 13 5/8' towards VXT
' Two 7/16' gate valves in main bore
' One 7/16' shear seal ram with high cutting capacity.
These are better shown in the figure below
Other relevant equipment that are part of the main stack include:
Grease Housing Assembly
The GHA provides a leak free entry for WL into high-pressure oil or gas well without undue hazard and with protection of the environment. Injected grease can seal over irregular forms such as standed cable, even large diameter wireline can be sealed over lengthy operations. The grease house assembly consists of one flow tube grease housing stabs. The grease housing also leads hydraulic pressure between the dual stuffing box and the flowtube housing.
Flowtube assembly
The flow tube house assembly provides a calibrated passage for each wire size. There are two flow tubes in each flow tube housing and two flow tube housing in each PCH. The flow tube housing also leads hydraulic pressure between the grease housing and the upper stuffing box.
Umbilical system
The main umbilical connects to the LLP with a remote operated multi-bore connector called Umbilical Terminal Head (UTH) to allow for an EQD function. The UTH is lowered to the seabed along with the LLP/LIP assembly
Control System
Only the original RLWI design had control system on the topside. The Mark II RLWI design does not have any topside control system. Currently, the control system is connected subsea and it has a fail safe close function. Valves in the main bore are programmed to close in case of an emergency.
Tool Trap
Installed on the Mark I design, its main purpose is to protect in particular the SCSSV and prevent unintentional dropping of the tool string into the wellbore. It is positioned between the 10' compact connector (of the LLP) and Lubricator tubulars and has bores through, which enables distribution of hydraulic control functions to ULP and PCH and circulation of well fluids/lubricator contents.
The UPIV in the WCP (see fig. 9) is used as a tool trap today on the Mark II RLWI system.
The tool trap currently does not hold any trap function but it acts as a mechanical connection between the LUB and the LLP
Surface or Topside Equipment Description
The RLWI is controlled from the operations room at the BIT, along with the WL equipment (which is controlled by the service provider ' e.g. Aker Well Services).
The topside equipment consists on the following:
' Main umbilical
' CIU (Chemical Injection Unit) w/ Pump and Tote tank skids
' Service Umbilical
' GIU (Grease Injection Unit) 3rd party
' WOCS & HPU (Mark I design)
Chemical Injection Unit (CIU)
It is used for several purposes:
' Injection of MEG or Methanol in the lubricator section subsea during RLWI operations to avoid hydrates in the system.
' Injection of friction reducing chemicals in the well.
' Pressure testing of barrier valves when entering and leaving a well. It provides the pumping capability to the RLWI system.
' Flushing and replacing of hydrocarbons in the well during RLWI operations. Subsea flushing is just to inject constantly MEG or other substances through the umbilicals from the CIU
Additional reading:How Does China 3 Way Ball Valve Supplier Work?
The CIP (Clean-in-Place) Buyers Guide
For more Wireline Pressure Control Equipmentinformation, please contact us. We will provide professional answers.
' High volume pressure testing of RWLI components.
To inject MEG into the well, the tanks are on surface at the CIU and the MEG is pumped through the umbilical and through the CIV/LCIV into the WCP and thereafter into the well.
The boat / Vessel
The Active heave compensator system on the winch tower or so-called well intervention tower (BIT ' Brønnintervensjonstårnet). There are two things to be mainly compensated:
1) The WL winches. This winch is attached to a piston, which compensates for the movement of the boat. It has a maximum heave for 8 meters however only 4 meters compensation is acceptable for operations and thereafter operations should be suspended. The pulling capacity of the winch is estimated on 100 ton.
2) The Umbilicals. The umbilicals come from the ground floor at the boat. Then, they are run all the way up to the tower (to the roof top) then down into the first winch (which is not compensated) and then into the compensated winch. The umbilicals can be compensated for 6 meters maximum but only 4 are acceptable.
Something useful to know about the intervention vessels is that the ships are autonomous for uploading and downloading equipment. Everytime they need new equipment from land they close the intervention hatch and go to land. They park at the harbor or deck and upload all the equipment they need. Thereafter they come back to the field where the intervention is going on and re-latch to the RLWI which is still placed underwater. The only part of equipment of the RLWI, which is recovered before going to shore is the PCH.
Everytime, the boat is going to shore and operations are set on stand by then, the well's DHSV has to be closed and inflow tested to verify its integrity. Afterwards, to inform to the production facility that the well is ready for handover in. Efectuate the handover to the production facility and then go to land.
References used:
http://www.islandoffshore.com/?cid=37&mid=1#cid=37&mid=1
http://www.fmctechnologies.com/SubseaSystems/Technologies/AdvancingTechnologies/Intervention/LWI.aspx
http://www.helixesg.com/Energy-Services/WELL-OPS/Assets/
OTC ' Riserless Well Intervention System
SPE Riserless Well Intervention for Subsea Workover
SPE Monohull vessel for subsea intervention
Offshore magazine Sept
Offshore magazine Vol. 72 #7
Tornes Birkeland, S. 'Well Integrity of Subsea Wells during Light Well Interventions' ' Master Thesis, NTNU, Trondheim, Norway .
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Wireline steering techniques
Wireline steering techniques
This technique has the advantage of real time readings from down hole, but the disadvantage of the wireline and associated handling problems.
Although technically wireline steering tools are also MWD systems, the term MWD is commonly used in the industry to mean systems with non-wireline data transmission systems.
The disadvantage of the mud pulse MWD systems is their relatively slow data rate and hence update of the downhole measurements. In a number of applications, e.g. with deep kick-offs or high torque motors, the MWD data rate is insufficient for obtaining a consistent orientation, and a wireline system has to be used.
Magnetic and gyroscopic survey tools are used for wireline steering. Magnetic steering tools are influenced by magnetic interference, both from the drillstring and from adjacent wells, and the gyro steering tool has been developed to overcome this problem.
Wireline steering tools
Wireline steering tools can only be used when the drillstring is not being rotated. Wireline steering tools are applied when:
·kicking-off;
·side-tracking;
·making correction runs.
Wireline steering tools save substantial rig time and are cost effective in comparison with single-shot surveys, despite higher direct survey cost.
The time savings result from:
they allow the reactive torque of the mud motor to be taken into account;
they provide a continuous real time read-out; and so allow an early response on problems of assembly orientation, hole direction, tool failure, etc.
Wireline steering tool surveys taken in kick-off assemblies are usually sufficiently accurate for controlling and monitoring the kick-off interval, but for an accurate survey a magnetic or gyroscopic survey should be taken through the kick-off section.
Principle of operation
Wireline steering tools comprise a downhole probe, conductor wireline and surface equipment. The downhole probe can be a solid state magnetic tool, a conventional gyro tool or a North Seeking gyro tool. Magnetic tools are most frequently used, but have an application restriction due to magnetic interference, which does not exist for the gyroscopic tools.
For wireline steering in vertical wells gravity toolface can not be used. Magnetic toolface is also not applicable due the magnetic interference of the casing. For these events a gyroscopic survey using gyro toolface should be used.
Solid state magnetic wireline steering tools
The most common steering tools:
·DOT (Directional Orientation Tool) - Baker Hughes Inteq;
·SST (Sperry Steering Tool) - Sperry-Sun;
·EYE (Electronic Yaw Equipment) - Scientific Drilling International;
·Bob Fournet Company (BFC/Tensor) Steering Tool;
·Servco.
Quality assurance
Quality assurance for solid state magnetic wireline tools is identical to that of solid state single and multi-shot tools.
Pre-survey checklist
On arrival the survey engineer should obtain the following information from the well site drilling engineer:
Wellhead co-ordinates
Depth reference (e.g. rotary table or wellhead)
Kick-off depth and outline of proposed well plan
Target azimuth (proposal)
Tie in data
Survey depths and interval
BHA/drillpipe size, weight, ID, restrictions, connections
Maximum bottom hole temperature and mud properties
Depths of any severe dog legs or expected problems
Magnetic field strength, dip angle and declination (for magnetic wireline steering tools).
The Wellsite Engineer should ensure that the following checks have been carried out.
- Check that the proper equipment for the job is available, e.g.:
1.sufficient length of NMDCs if required;
2.crossover as required;
3.orientation sub;
4.full flow mule shoe, telescopic joint, etc.;
5.circulating head;
6.wireline unit, steering tool probe and surface equipment;
7.side entry sub with split kelly bushing (if required).
Before making up the bottom hole assembly check that the key seat (mule shoe seating) in the orientation sub is aligned with the high-side of the bent sub.
- Check that the mule shoe is full flow type.
- Space out the instrument with spacer bars to land sensor at the optimum position within the NMDCs if required.
- Circulate hole clean before running in the instrument, also after making a connection.
- Consider use of side entry sub to save wireline tripping time.
Quality control
Wireline steering tools are run by the Survey Engineer. For use of full length of NMDC or correction programme to reduce/correct for magnetic interference. Quality control of solid state magnetic wireline steering tools is governed by the correction programme.
Uncertainties of solid state magnetic wireline steering tools
Uncertainties of solid state magnetic wireline steering tools comprises tool uncertainties, geomagnetic uncertainties correction programme correction uncertainties and system uncertainties. System uncertainties are wireline depth, toolface dependent misalignment, and BHA deflection. Misalignment and BHA deflection are mainly in the vertical plane affecting mostly inclination readings. Toolface dependent misalignment can be corrected by using correction programme (rotational shot or toolface offset centre correction technique).
Gyroscopic orientation tools
Where there is magnetic interference from adjacent wells or fish or in the event of a sidetrack from a vertical casing, a magnetic steering tool cannot be used for orienting a drillstring during a kick-off. In these situations, gyro single-shots can be used. The gyro cannot be left in the drillstring while drilling, so the string is oriented with the gyro, including an estimate for the reactive torque from the downhole motor. After drilling a single, a further single-shot survey is made to confirm the orientation and direction of the well.
Initially, film-type gyro single-shots were run on wireline, however these have a limitation of about 15 minutes survey time, beyond which the accuracy can degrade. This gives a practical depth limitation of about ft AHD.
Surface read-out gyro tools have tended to replace the film-type tools. The surface read-out gyro tools are run on conductor wireline and can give provisional data for the azimuth, inclination and toolface in real time. The provisional data will change when the drift curve is closed at the end of the survey.
North Seeking gyro tools can also be used for this application. The North Seeking gyro tools have the advantage that they do not require orienting to a foresight and hence requires less time to take a survey. However, as with the film-type instruments, the conventional surface read-out gyro and North seeking gyro cannot be left in the drillstring while drilling. The exception to this is the North Seeking Finder from Scientific Drilling International, which in its ruggedised form, can be used as a wireline steering tool.
Finder GWD tool (SDI)
Currently the Finder GWD, (Gyro-While-Drilling) is the only gyro tool that can remain in the drillstring while drilling in non-rotary mode only. It is a ruggedised version of the Scientific Drilling International (SDI) 'Finder' North Seeking gyro. The Finder GWD can be used for kick-offs and sidetracking, especially where magnetic interference is likely to affect magnetic tools. Applications include sidetracking past fish or through a window milled in casing.
Initialisation
Prior to the start of the job, the survey engineer will make up the Finder in the appropriate running gear for the well to be surveyed. A locking (latch down) stinger and sliding sinker bar should be used in all Finder steering jobs. It is recommended to centralise the tool if the drillstring inner diameter allows.
If the well temperature is less than 72°C the Finder can be run inside a 1.75" OD pressure barrel. If the well temperature is greater than 72°C the Finder must be run inside a thermoshield. This will limit downhole time due to the gyro temperature build-up inside the thermoshield.
Quality assurance
A field calibration should be performed to check the spin and input axis mass unbalance and accelerometer scale factor offsets. The differences between office and field offsets obtained should be within the acceptable values specified. If the differences are not within this range, it is recommended that a back-up tool is run. If this is not possible, the Finder should be returned to base for checking as soon as possible after the job.
Pre-survey checklist
In addition to the pre-survey checklist given above, the Wellsite Drilling Engineer should supply the survey engineer with the latitude and the depth where inclination is approximately 15°.
Gyrocompassing mode
Below 15° inclination the Finder GWD tool should be used in gyrocompassing mode taking toolface data with pumps on. Accurate inclination and azimuth readings can only be taken with the pumps down.
Continuous mode
Above 15° inclination the Finder GWD tool should be used in continuous mode. After drilling a single the tool is pulled up to the previous depth and run down in continuous mode taking surveys. At the start of the continuous mode a North seek initialisation should be performed.
Quality control
During surveys quality control checks should be performed. These control checks should be specified on the quality control sheet and should be checked by the well site drilling engineer. Whenever rig operations and time allow, a post-job field calibration is done as soon as possible after the survey is completed, before leaving the location. The pre- and post-job calibration differences should be checked by the well site drilling engineer against the acceptable values.
Uncertainties of Finder GWD tool
The uncertainties of the Finder GWD tool comprises tool uncertainties and system error.
Steering the mud motor
Wireline steering tools are nearly always used with a bent sub and mud motor. The scribe line on the bent sub (which indicates the direction the bit will try to drill) on the probe is aligned by a mule shoe orienting sub. From this the toolface offset is determined.
A magnetic or gyroscopic steering tool can read the orientation of the scribe line. For magnetic steering tools this direction can be read:
·relative to the high-side of the hole (toolface angle) (inclination > 5°);
·relative to Magnetic or True North (azimuth) (inclination < 5°).
For the Finder GWD tool the orientation of the scribe line can be read:
·relative to the high-side of the hole (toolface angle) (inclination > 3°);
·relative to True North (azimuth) (inclination < 3°).
Wireline inside drillpipe
There are three ways of getting the wireline inside the drillstring while being able to circulate. They involve the use of:
·a circulating head;
·a side entry sub;
·a wet connector.
A side entry sub is always used with a lockdown type mule shoe. A circulating head can be used with or without a locking device. Locking devices should always be used at high flow rates.
Circulating head
The basic system comprises a swivel and a hydraulic pack-off. The circulating head is mounted on the drillpipe which has been hung off the hook. The top of the circulating head is provided with a sealing arrangement (pack-off) through which the cable is fed into the drillpipe. If another stand or single has to be added, the tool probe has to be pulled out of hole to remove the wire from the drillpipe. The kelly is not connected when the system is in use.
In case of a top drive the hose of the top drive or of the standpipe manifold is attached to the circulating head. The drillpipe is hung-off in the slips.
To save rig time try to use a double or a triple drillpipe joint as a working stand. However, the use of drillpipe as a working stand precludes the use of high torque mud motors.
Side entry sub
Under normal circumstances with a circulating head, the probe will be tripped in the hole at the beginning of the drilling operation and will remain seated downhole until it is tripped out on wireline after drilling the working stand.
Side entry subs are used to avoid pulling the steering tool when adding pipe. Their use thus saves rig time. With a side entry sub arrangement, the cable is clamped on to the outside of the drillpipe and enters the drillstring via a side entry sub which is provided with a sealing arrangement (stuffing box).
There are several disadvantages associated with the use of side entry subs:
pressure control problems; problems can occur when closing the drillpipe BOP rams (because the cable lies outside the drillpipe). Also annulus-drillpipe communication can occur if there is stuffing box packing failure.
wireline damage; to reduce the possibility of wireline damage, it is recommended that free wireline is only run inside the casing otherwise it will be damaged by the casing shoe.
Side entry sub seal integrity and running speed
The wireline seal is expandable on a run-by-run basis. The seal is degraded by friction and heat as the wireline passes through it when the probe is run into the hole and retrieved. Seal wear is normal and expected. Seal wear occurs faster, however, when the wireline is run at high speeds, generating more heat. To preserve seal integrity and avoid round trips, a new seal should be inserted into the seal spacer before each run; and running speeds should not exceed 30-50 m/min (100 to 150 ft/min) especially when running in. A slower speed is advisable if the wireline is rough, dirty or frayed.
Safety precautions when using side entry subs
The wireline operator of the side entry sub system must work closely with the Driller since a wireline tension of 50-150 kg (100-300 pounds) is being used. An intercom is vital. The wireline is liable to damage at the rotary table and if severed will lash up, endangering workers on the rig floor.
operate this equipment with great care;
use a split kelly bushing. This permits normal operation of the kelly while allowing the wireline to pass through the rotary bushing to the upper sleeve without obstruction and greatly reduces the danger of severing the wireline at the rotary;
if a split kelly bushing is not available use a circulating head;
do not try to run the wireline side entry sub system with a standard kelly and kelly bushing;
use a wireline unit with a constant tension facility and ensure that the operator remains alert throughout the job;
ensure that the wireline does not get pinched between the drillpipe and the kelly bushing;
after making up the side entry sub to the drillstring (with wireline threaded through) and seating the steering tool, pick up kelly and circulate briefly to check seal integrity.
Wireline wet connector and running procedure
In slim hole drilling, the small clearances make the use of a side entry sub for a wireline steering tool difficult. In some applications, the wireline on the outside of the drillstring is unacceptable from a well control point of view, where the wire could cause problems with BOPs making an effective seal on the pipe.
To overcome this, a rotating wet connector can be used. The system uses a similar rotating wet connector as used in coiled tubing directional drilling operations. It allows the wireline to be pulled for adding drillpipe and orienting, without pulling the steering tool, with the kelly still in place. The disadvantage is that the wireline requires cutting.
The running procedure for use of a wet connector is as follows:
Run the BHA and drillstring to the depth required for the start of oriented drilling.
Run in and seat the steering tool.
Cut and make up the wireline head. Hang off in the bottom of the wet connector which rests in a drillstring landing sub.
Thread the wireline through the pack-off attached above the swivel on the gooseneck or non-rotating upper connection of the swivel. Make up the loose end of the wireline to the overshot that connects with the top of the wet connector.
Connect the overshot to the wet connector. Check the wireline continuity and the function of the steering tool.
Disconnect the overshot and continue running the drillpipe in the hole.
Prior to starting drilling, the overshot can be run in and connected to the wet connector.
Whenever pipe rotation is needed, or drillpipe has to be added, the overshot can be pulled into the kelly. When the overshot is connected, the operation is similar to a conventional steering tool.
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