Once properly commissioned and tested the Mud Cap Drilling system, drilling can be done the conventional mode until actual circulation losses conditions dictate to switch to Mud Cap Drilling mode. At first, decision could be taken to attempt to control losses with conventional methods. Typically Mud Cap Drilling (MPD, Managed Presure Drilling) mode will start as soon as the last Gunk pill has positively plugged the hole, the mud in hole conditioned and the Mud Cap Drilling (MPD, Managed Presure Drilling) system ready.
1. Prepare for Mud Cap Drilling operations
1. POOH with string (or core barrel) if it is in hole. If POOH can be avoided and the Mud Cap Drilling (MPD, Managed Presure Drilling) system is fully operational, proceed as per step 11 below.
2. Once out of hole, static check well and close the blind/shear rams. Continue control of well on choke line.
3. If not previously installed, install RCD’s Sealing Elements and the Bearing section as per RCD (Rotating Control Device, Rotating Head, Rotating BOP) procedures. Test the RCD with a test plug as per applicable procedure.
4. If required perform a full test of BOPs and other rig well control equipment.
5. Ensure that all safety equipment for H2S and other gases is operational, as well as the required PPAs.
6. Reinstall the RCD (Rotating Control Device, Rotating Head, Rotating BOP) drilling adapter. Keep the sealing/bearing element in the first drilling stand ready to be installed in the RCD.
7. Run Mud Cap Drilling (MPD, Managed Presure Drilling) BHA to casing shoe. The drill pipe will be exposed to a pressure higher than for normal drilling during the Mud Cap Drilling (MPD, Managed Presure Drilling) operations. Furthermore, water (or similar) shall be pumped, which is more difficult than mud to contain. Apply an extra amount of pipe dope and tightening connections appropriately to reduce risk of leakage wash/out.
8. Ensure that the stands of drill pipe that will be used during Mud Cap Drilling (MPD, Managed Presure Drilling) have a kelly-cock safety valve and the wear subs to protect threads pre-installed. Ensure each one has been pressure tested and is ready for use in the derrick. Note that the safety valve on top of each drilled down stand will be closed while making connections. This shall provide an additional safety barrier in the event of drill pipe float failure or a leak in the drill string while the Top Drive is removed. Verify if with the DP top drive links available there is enough room between elevator and pipe handler to lift a stand with a kelly-cock and saver-sub on the top tool joint. An adequate number (say ten) of such drilling stands shall be prepared and set back in derrick. At connection the kelly-cock will be just above the rotary table. The valve shall be closed before unscrewing the TDS and performing connection.
9. Circulate bottoms up (uniform mud weight will greatly help in determining the bottom hole pressure in case of circulation loss) and ream to the top of plug.
Mill out and commence for CHC
10. Mill plug (conventional drilling mode) until total loss of returns. Observe well to estimate the bottom hole pressure.
11. Estimating Bottom Hole Pressure from Fluid Level Drop
The formation pressure and gradient in the zone of total losses should be calculated and verified with the following procedure:
a. Fill the hole with water until the hole level stabilizes just below flow-line. Measure the volume and density as accurately as possible.
b. As soon as the hole stops taking fluid, calculate the BHP and record all data. (Previous experience shows that this technique may under-evaluate the pressure in the lost returns zone due to mud gellation. Consequently, make the above steps with the string in rotation at 50 rpm).
12. Determine the Light Annualr Mud (LAM) weight. Mix the mud consequently and check weight as accurately as possible.
13. Close the BOP and monitor well through choke line. Disconnect the drilling nipple from the RCD (Rotating Control Device, Rotating Head, Rotating BOP). Pick up the pre-installed sealing/bearing element and install in the RCD. Engage the hydraulic clamp and close the manual safety lock on the RCD as per RCD procedures.
14. Open BOP and close the choke line.
15.Line up the pumps for injecting LAM down the annulus and sacrificial fluid down the drill pipe.
Displace well-bore with Mud Cap Drilling fluids
16. Check the casing pressure.
17. Reset the pump stroke counter.
18. Displace (bullhead) the annular drilling fluid in well with the LAM. Record and plot casing pressure versus cumulative volume injected. Displace the new mud at a rate of 2-5 bbls/min to improve displacement efficiency. Progressing with the pumping, the casing pressure should stabilize to a value close to the calculated Pmin csg.
19. Check the pressure and volume pumped against the calculated volumes.
20. Displace the drilling mud in the DP with SACRIFICIAL Fluid (water, treated with scavenger if need be). Check and record DP pressure.
Prepare to drill ahead in Mud Cap Drilling mode
21. Lower DP to bottom.
22. Check and record Torque and Drag.
23. Begin pumping (injecting) the SACRIFICIAL Fluid down the drillstring. Shut the pumps down. Wait a minimum of 30 seconds and observe static casing pressure. Slowly increase pump rate to just enough to open floats. Shut down the pump. Record the Static *DP pressure. Conduct connection drill.
*(This value is directly linked with the annulus pressure outside the bit. Verify this data with the result obtained from calculations).
2. Drilling
Before injecting into the annulus always confirm that the kill line is open on the annulus and connected to pump discharge.
Start Drilling and Drilling ahead
1. Lower drill string to bottom and begin drilling.
Note: Annular displacement does not have to be complete prior to beginning drilling. The annulus can be displaced simultaneously with drilling ahead.
2. Inject sacrificial fluid at a rate sufficient for optimum bit performance and hole cleaning. Suggested drilling Sacrificial Fluid injection rate is 900 l/min in the 8 ½” hole. Flush open hole with 5m3 of high viscosity pill every stand to improve hole cleaning. Check torque & drag carefully and increase viscous pills as required. Ream carefully before connection.
3. Drill ahead injecting Sacrificial Fluid, allowing casing pressure to increase to the maximum planned casing pressure. Bit selection should be based on the optimum bit to drill the formation. While smaller cuttings will be easier to remove and carry up hole in the annulus, to be eventually injected in fractures, small cuttings are not a necessary requirement of Mud Cap Drilling (MPD, Managed Presure Drilling). Experience has shown that all bit types can be used in Mud Cap Drilling (MPD, Managed Presure Drilling).
4. Monitor at all times the standpipe pressure (SPP). Any change in pressure indicates a change in the down-hole environment, unless it is accompanied by a corresponding change in the SACRIFICIAL Fluid flow rate.
5. While continuing to drill, if the Pmax csg increases, inject Light Annular Mud into the casing to squeeze contaminated bottom hole fluids back into the formation. Record and plot casing pressure and volume. The casing pressure shall stabilize back at the calculated Pmin csg after the “lightened” contaminated mud is squeezed back from the well-bore into the formation.
6. Continue drilling, maintaining the casing pressure between Pmin csg and Pmax csg or until a connection is required.
Logging while drilling
Note: The reservoir bore-hole condition developed during Mud Cap Drilling (MPD, Managed Presure Drilling) makes a wire-line logging operations extremely dangerous for the equipment.
Required petrophysical/formation evaluation information shall be possibly obtained with Logging While Drilling.
Running radioactive sources should be possibly avoided. If absolutely necessary, running of these sources shall be performed only after having evaluated the actual down hole conditions (corrosion from H2S attack, risk of differential sticking, etc.) from previous runs performed with conventional equipment.
If required, a full logging suite will be recorded while the last bit run, or, if reduced time of exposure is preferred, with a dedicated reaming/logging session at TD.
Making connections
1. At pipe connection pick up off bottom and record torque and drag. If excess torque and/or drag is detected, continue to inject water down the drill pipe and flush with high viscosity pills prior to making connections. Back ream and ream down as required. Pump a minimum 5m3 high viscosity sweep every stand and before pipe connection for hole cleaning.
2. Record dynamic DP pressure and rate. Shut off pumps.
3. Bleed off trapped pressure on DP slowly to 0 bar by opening the bleed off valve or low torque manual valve on standpipe manifold. Check to confirm that the floats are holding and that there is no Back Pressure in the drill pipes. If the floats are not holding, see Para. 11.3.5.3, “Floats Not Holding”.
4. Before removing the top-drive, again check standpipe pressure gauge for trapped pressure. This is any injection pressure that has not bled off.
5. Make pipe connection. This requires some slightly different procedure from normal as there is an additional Surface Safety Barrier on the drill pipes side. Prior to breaking off the top-drive, close the kelly cock on top of the drill pipe stand in the rotary. Pick up the next stand having a kelly-cock in open position pre-installed on it. Make up the new stand of drill pipe. Open the lower Kelly-cock and run to bottom.
6 Bring pumps on slowly and resume drilling.
7. Record torque and drag on every connection and watch for increasing trend. It could mean that the hole is not being cleaned by the injected SACRIFICIAL fluid.
Trip out of the hole
Never POOH with the string full of water.
Before injecting into the annulus always confirm that the kill line is open on the annulus and connected to pump discharge.
1. Prior to pulling out of the hole, pump a viscous sweep. Inject SACRIFICIAL Fluid as required and reciprocate pipe to ensure the hole is clean of cuttings.
Note: Erratic torque and drag can indicate potential hole cleaning problems.
2. Replace the freshwater in the drill string with Light Annular Mud. At the end of displacement, pump a Heavy Trip Mud pill for drill string slug.
3. Observe the drill string pressure and strip out of hole. Stripping out of the hole will avoid swabbing of the formation. While pulling out, record incremental pressure against RCD seal.
4. Continue stripping out of hole. Inject proper fill up volume of LAM in annulus while maintaining pressures between the established Pmin csg and Pmax csg. POOH to the last stand of DPs. Inject Heavy Trip Mud in the annulus until the pressure reduces to zero. DO NOT OVER DISPLACE. To ensure that over-displacement does not occur, pump at slow rate the calculated volume required to balance the well before injection. Calculations should be based on balancing the BHP at the top fracture encountered. Check for pressure on annulus. Ensure that there is no pressure on the annulus or choke. Well must be dead before continuing this procedure. If there is pressure, inject heavy mud in annulus to bring casing pressure to zero. Record all volumes with their respective mud weights in and out of hole. Wait until gels develop for the mud in hole (typically ½-1 hour). Mud gels fully developed in an undisturbed mud column below the BHA will require few hundred psi to be sheared.
5. Release safety locks on RCD (Rotating Control Device, Rotating Head, Rotating BOP) and hydraulic clamps. Slowly pull the 5” DP out of the hole, pulling bearing assembly out of RCD bowl. Stand back bearing assembly and 5” DP offside of derrick as per RCD procedure.
Note: Bearing Assembly should always be on the bottom joint of a stand and readily available if needed.
6. To regain control of Well level, the Drilling Nipple should be reinstalled (have arrangement ready to perform this operation with drilling string in hole).
7. POOH with HWDP and BHA. Fill the hole with LAM using the trip tank. Observe hole, and maintain balance using Heavy Trip Mud and LAM as required.
8. With the bit above the rotary, close the blind/shear rams and continuously monitor annulus pressure on the choke manifold or returns on the mini trip tank.
Trip In The Hole
After the bit is above the rotary and the blind rams have been shut, the following procedure may be used to trip in the hole. RCD (Rotating Control Device, Rotating Head, Rotating BOP) rubber elements and bearing assembly will be on a stand of pipe standing back in the derrick. The sealing element of the RCD will be re-installed when the BHA is below the rotary.
Before injecting into the annulus always confirm that the kill line is open on the annulus and connected to pump discharge.
1. Make up the bit on BHA. Keep the choke closed and continue monitoring the annulus with the trip tank.
2. If the well flows or if casing pressure increases, inject Heavy Trip Mud to reduce the casing pressure to zero. Do not over-displace and put the well on a vacuum (i.e. the well slightly taking mud).
3. Check for pressure on the annulus. Ensure that there is no pressure on the annulus or choke. Well must be dead before continuing this procedure.
4. Open blind rams and RIH with BHA, filling the BHA with Heavy Trip Mud. (Check displacement volume).
5. After BHA is below the BOP stack, remove Drilling Nipple & Flow-line Adapter and install 5” rubber elements in the RCD (Rotating Control Device, Rotating Head, Rotating BOP) as per RCD procedure. (The bearing assembly was left on the last DP stand pulled out of the hole).
6. Strip in the hole, filling the drill pipe with Light Annular Mud and recover the string displacement mud volume through the choke and into the trip tank. While recovering the Heavy Trip Mud that was pumped to balance the annulus pressure, the well may begin to flow. Recover only the volume of Heavy Trip Mud that was originally pumped and monitor it through the trip tank. Close the choke and continue stripping in the hole. The casing pressure should stabilize at Pmin csg. When lighter fluids start returning, displace only the calculated displacement of pipe being tripped into hole.
3. Problem Solving in Mud Cap Drilling
With reference to HAZID/HAZOP analyses performed, the following points are those highly ranked for consideration.
Leaking RCD Rubber Packing Element
Should the RCD rubber packing-element begin to leak while in use, or because a decision is made to change the rubber elements in the RCD (Rotating Control Device, Rotating Head, Rotating BOP), change them in accordance with equipment specification and procedures and under the guidance of the RCD representative.
AVOID LOOKING DOWN THE ROTARY HOLE WHILE CASING UNDER PRESSURE (Mud Cap Drilling (MPD, Managed Presure Drilling) OPERATIONS ON-GOING). THE RCD (Rotating Control Device, Rotating Head, Rotating BOP) RUBBERS ARE RELIABLE, BUT ARE ALSO EXPENDABLE; THEIR CONDITION AT ANY GIVEN MOMENT IS UNKNOWN.
Shutting-In Pipe Rams (Pressure Too High On RCD)
It should be avoided to rotate or pull tool joints through the rotating head when the pressure limit on the RCD (Rotating Control Device, Rotating Head, Rotating BOP) has been reached. The pressure limits for static pressure and for rotating/stripping pressure is set forth by the equipment Manufacturer specifications and shall be acknowledged by all the concerned users. Typically, the RCD static pressure rating is 211 bar (3,000 psi) and the rotating/stripping pressure is 176 bar (2,500 psi).
In the unlikely event that the choke or annular pressure approaches the pressure limit of the RCD (Rotating Control Device, Rotating Head, Rotating BOP), the upper pipe rams on BOP should be closed.
There are two reasons why the upper rams are preferred over the annular preventer to isolate the RCD from excessive wellhead pressures.
a. As the annular preventer closes, the annular rubber first seals against the drill pipe and then continues to extrude into the trapped space between the annular and lower RCD (Rotating Control Device, Rotating Head, Rotating BOP) rubber. This increases the trapped pressure and may approach the failure limit of the RCD. The problem is aggravated when the trapped fluid has no gas in it. The rams do not compress the isolated fluid trapped between the rams and RCD (Rotating Control Device, Rotating Head, Rotating BOP).
b. Secondly, the rams generally have a higher pressure containment rating than the annular preventer. It should be noted that rams require a differential pressure across them to actuate the top seal. If the required amount of differential pressure does not exist, the rams will appear closed, but will allow pressure transmission to the RCD. Ensure that RCD (Rotating Control Device, Rotating Head, Rotating BOP) allows enough differential pressure for proper BOP rams closing.
Floats Not Holding
The following paragraphs address to how to recognize when the floats are not holding and ways to clear floats when they are stuck open, or they have trash in them.
Note: using a ball and seat type float will greatly reduce the probability of this occurring.
Recognizing the Floats Are Leaking
1. Shut down the pumps.
2. Before removing the top drive, kelly or pump-in sub, check the standpipe pressure gauge for trapped pressure. This means any injection pressure that has not been bled off. Note and record standpipe pressure. Compare to standpipe pressures recorded on previous connections.
3. Bleed the pressure off slowly on the DP to 0 psi by opening the air actuated bleed off valve (if rigged up for Mud Cap Drilling (MPD, Managed Presure Drilling)). If an air actuated bleed valve is not installed, bleed off trapped pressure using the standpipe manifold. Check to confirm that the floats are holding and that there is no flow from the drill pipe.
4. FLOATS NOT HOLDING SHALL BE EVIDENT IF THE STANDPIPE PRESSURE DOES NOT ZERO AND FLOW DOES NOT STOP.
Clearing the Floats
A leaking float may not be a problem if trash is obstructing their ability to close and the trash can be cleared. The following actions should be attempted in order to clear the floats before a decision to make a trip with the floats not holding is taken.
1. Wash and ream drill string back to bottom.
2. Vary flow injection rate within parameter limits. Change parameters to attempt dislodge debris that may be caught in the floats.
3. Attempt to induce a pressure surge on the floats allowing pressure to bleed off fast.
4. Pump viscous pill(s) or a lubricant. Sometimes this works with stuck or debris affected floats. Try this.
Floats Fail During a Connection
Firstly, DO NOT PANIC! THE RIG CREW MUST BE FULLY TRAINED FOR THESE CASES AND MUST WORK QUICKLY, PURPOSELY AND WITH DETERMINATION!
Rigs with top drives
While drilling in Mud Cap Drilling (MPD, Managed Presure Drilling) mode, all stands shall be provided with one kelly cock safety valve on top of each stand. During a connection this valve shall be at rotary table level and shall be closed until the top drive is made up on string.
Tripping will always be performed with the string full of mud. The potential flow in case of float failure is therefore reduced. If flow occurs while tripping, bring top of stand back to floor. Set slips, and slack off on block engaging top drive safety valve, tighten top drive and close safety valve either manually or using remote closing feature if so equipped. Kill well using adequate mud.
Washout in Drill String
A washout in the drill string while in Mud Cap Drilling (MPD, Managed Presure Drilling) mode will behave in the same manner as with conventional drilling: the drill pipe pressure will decrease and annulus pressure may increase if leak is above the top losing zone. If a washout has occurred, torque and drag may increase due to poorer hole cleaning, and the penetration rate may decrease due to inadequate hydraulics at the bit face.
If it is believed that a washout has occurred, displace the SACRIFICIAL Fluid in the DP with LAM down the DP observing the casing pressure. If the casing pressure remains constant and DP pressure reduces to Pmin csg, then slug the DP with Trip Mud and pull out of the hole to check for washout.
Drill String Failure
If drill string parts or twists off during the Mud Cap Drilling (MPD, Managed Presure Drilling) operation, fishing operations can be carried out in conventional manner AS LONG AS THE WELL IS DEAD.
1. Inject the annulus and drill string total displacement with Heavy Annular Mud prior to POOH.
2. Trip out of hole as per conventional tripping or according to Mud Cap Drilling (MPD, Managed Presure Drilling), depending upon actual well conditions.
Mind that a failure of the drilling string above the back-pressure valves may result in a high drill pipe pressure because of the mud vs. water “U” tube. Annular mud pressure may exceed by 352 bar (5,000 psi) the drillstring pressure when the drill pipe are full of water.
Increasing Standpipe Pressure
Increasing standpipe pressure means that flow has been restricted in the drill string somewhere between the bit nozzles and pump discharge or that injectivity of the formation has decreased. The most likely places where restrictions/plugging may occur are the bit nozzles or floats. If attempting to surge the pipe to clear the obstruction does not work, then a decision shall be made to pull the drill string out.
If vice-versa the stand pipe pressure increase is due to the in-taking formations being plugged, this should be reflected by an un-justified increment of the annulus pressure (mind that annulus pressure may increase also because of migration of formation fluids).
Corrosion and/or H2S Attach to the LWD Tools
The reservoir borehole condition developed during Mud Cap Drilling (MPD, Managed Presure Drilling) makes the bore environment potentially damaging for the costly LWD equipment. As a preliminary assessment of the risk for running LWD tools may result from the evaluation of the conditions of the MWD (or minimum suite of LWD such as G.R./Resistivity). Acknowledging the actual condition of these tools (i.e. working performance, reliability, presence of corrosion and recognition of H2S attack), will dictate the best way to use the LWD. A suitable alternative could be running the required suite of the LWD in the last bit run, or, even better, in a dedicated reaming/logging session after have reached TD in order to minimize the exposure time of the logging tools to the corrosive environment.
Stuck Pipes
Well shall be kept dead while working on stuck pipe.
Specific procedures shall be worked out in case acid jobs are to be carried out in order to attempt un-freezing pipes in carbonate formations. Detailed work programmes shall be issued in coordination with the Mud Cap Drilling (MPD, Managed Presure Drilling) engineer, rig Toolpusher and other concerned Parties, depending upon the actual case.
Acid formulation and safety issues related to work with acid shall be issued as the occasion call making reference to the applicable KPO and Service Contractors procedures.
Drilling String Plugged While Drilling
Plugging of drilling string may occur during drilling and string should be pulled out to correct.
Mind that high differential pressure, which may exceed 352 bar (5,000psi) from the annulus side, exists between the drillstring water and the annulus mud.
To displace a plugged string with mud, a hole need to be punched as deep as possible considering the pressure rating of the wireline pressure control equipment in use, to be installed on the drillstring over a Kelly-Cock safety valve. Once punched, the drillstring water shall be squeezed to formation to ensure Mud-Cap integrity.
4. Mud Cap Drilling well control equipment
Due to the peculiar situation of the well when applying the Mud Cap Drilling (MPD, Managed Presure Drilling) mode, the kick control procedures in place during normal U-tube drilling do not apply. The well is basically controlled in a bull heading-like mode.
Casing and Wellhead
Ensure that casing and wellhead equipment are properly dimensioned to withstand the worst-case pressures during drilling, well control and Mud Cap Drilling (MPD, Managed Presure Drilling) operations. This should ensure adequacy of the BOP and all the well/pressure control equipment for Mud Cap Drilling (MPD, Managed Presure Drilling) operations.
Rig BOP
The rig BOP stack shall be suitable for the drilling operations planned on the specific well. Pressure rating for the BOP its configuration and testing procedures are defined in KPO WOPM, Para. 2.7.4. BOPs and all the well control equipment, shall be for Sour Service - H2S trim.
BOP Stack Clearance for RCD Installation
The BOP stack must allow adequate room needed between the top of the annular preventer and the rotary beams to rig up a Rotating Control Device and associated equipment.
These features shall be checked among KPO, the Mud Cap Drilling (MPD, Managed Presure Drilling) Contractor, the Supplier of the RCD and The Rig Superintendent/Toolpusher during the planning stage for Mud Cap Drilling (MPD, Managed Presure Drilling) operations.
Choke Manifold, Choke And Kill Line Equipment
Type and characteristics of the choke manifold will be in accordance with the KPO Policies, Manuals and Procedures and shall be suitable for well control in the worst foreseeable well conditions. Choke manifold, lines and associated equipment shall be for sour service use. This should ensure adequacy of the choke manifold, choke and kill line and other associated equipment for Mud Cap Drilling (MPD, Managed Presure Drilling) operations.
Gas Removal Equipment
Expected well conditions require a mud gas removal system that can remove H2S gas from the drilling fluid if it is circulated out of the hole. During Mud Cap Drilling (MPD, Managed Presure Drilling) operations there is no circulation and the H2S gas removal system shall be used as required, when Mud Cap Drilling (MPD, Managed Presure Drilling) operations are terminated and the well is circulated with returns to the surface.
Gas Buster
Prior to initiating Mud Cap Drilling (MPD, Managed Presure Drilling), ensure that mud is gas free. If required, use a pressurized mud-gas separator to discharge effluent straight into a vacuum degasser, available with the rig.
H2S Gas Flare System
All H2S Gas Flare System elements are specified in the drilling contract as approved by KPO.
Rotating Control Device (RCD)
After the running of the production casing at top of the reservoirs, should it be required by the expectation of heavy circulation losses during the next hole phase drilling, the RCD (Rotating Control Device, Rotating Head, Rotating BOP) will be installed above the BOP stack Annular Preventer and tested according to the RCD Supplier procedures. The Flow line nipple will be installed and connected to Bell-Nipple/Mud-box to allow circulation at the beginning of drilling the actual hole phase. If Mud Cap Drilling (MPD, Managed Presure Drilling) operations are not required because on the reservoir conditions allow for normal drilling, then the RCD (Rotating Control Device, Rotating Head, Rotating BOP) will act as an extra safety equipment with normal mud return.
Rig Monitoring Equipment
The monitoring equipment that should be provided for control of Mud Cap Drilling (MPD, Managed Presure Drilling) parameters is:
1. CASING PRESSURE – A digital casing pressure gauges that reads up to 703 bar (10,000psi) and is accurate and readable to the nearest +/- 2 psi shall be available (sensor to be calibrated before to begin Mud Cap Drilling (MPD, Managed Presure Drilling)). A back up low range pressure gauge to monitor annulus pressure should be on location. The data should be captured on the time log and depth log.
2. DRILL PIPE PRESSURE – A gauge to precisely measure the pumping pressure of the sacrificial fluid shall be available.
3. PVT (Pit Volume Totalizer) – A PVT shall be available and will be used prior to converting to Mud Cap Drilling (MPD, Managed Presure Drilling). After Mud Cap Drilling (MPD, Managed Presure Drilling) is initiated, it can be used to monitor annular injection fluid volumes.
4. % FLOW - % Flow shall be available and will be used prior to converting to Mud Cap Drilling (MPD, Managed Presure Drilling). After Mud Cap Drilling (MPD, Managed Presure Drilling) is initiated, it will not be necessary to monitor it since the annulus will be shut in.
5. PUMP RATE - The ability to monitor flow rates both down the annulus and down the drill pipe is essential to conducting Mud Cap Drilling (MPD, Managed Presure Drilling) operations.
6. TRIP TANK – Two 50 bbl trip tanks should be available. The trip tanks will be used to accurately determine the bottom hole pressure and to control volumes during tripping and injection operations.
7. Corrosion Rings/Coupons – If required, place corrosion rings in the drill string in two locations, one near the surface (Kelly saver sub, if so equipped) and one as near the bit as possible.
5. Mud Cap Drilling hydraulics and planning of operations
Hydraulics plays a fundamental role in the application of the Mud Cap Drilling (MPD, Managed Presure Drilling) and must be fully acknowledged and understood by all key personnel at the rig site.
The formation pressure regime must be known.
Accurate monitoring and control of the hydraulic (pressures and flow rates) parameters are essential. In particular the following indicators shall be closely controlled:
- casing pressure
- drill pipe pressure
- PVT (Pit Volume Totalizer)
- % flow
- pump rate
- trip tank.
Planning for Mud Cap Drilling (MPD, Managed Presure Drilling) must consider the estimated material consumption vs. the supply and mixing capabilities (logistic limitation to be duly considered as far as supplies are concerned).