Operational Skills & Technical Knowledge Flashcards
What is your understanding of differential sticking and what mechanisms contribute to it?
Stuck pipe caused by high differential pressures when large surface area pipe is static and adjacent to permeable formations with thick filter cake build-up. High solids and high mud density.
What would be some warning signs of over pressured formations?
Large, brittle concave shaped carvings, recently crossed a fault, absence of permeable formations, large overpulls at connections, restricted circulation due to cavings loading the annulus, torque may increase.
What are some indications that could be a result of poor hole cleaning?
Drag on connections/tripping, excessive torque, fill on bottom following logging runs or on trips, tight hole, stuck pipe, nothing coming over the shakers.
On a trip out of the hole the string is pulling very tight. What is the best way to get out of this situation?
Move the pipe in the opposite direction prior to getting stuck. If already stuck, jar in the opposite direction as soon as possible. Get circulating and rotating as soon as possible.
What would be the first thing you would do if you suspect differential sticking with the string off the bottom?
Place right hand torque into the string and slump the string to try to free it.
What does Management of Change (MOC) mean to you?
MOC relates to managing risk when changes to procedures or policy are required. After assessing the risk and proper safety controls documented, the MOC is sign-off by the Management.
What limits casing running speeds?
Wellbore condition and integrity, personnel safety and surge pressures.
What is the biggest concern when pumping a large volume of light pre-flush?
Wellbore condition and integrity, personnel safety and surge pressures.
What is the difference between magnetic and gravity (high side) tool face and how are they to be used when directional drilling with a steerable motor?
When steering bits at low inclinations, MWD tools measure the magnetic toolface (the azimuth that the string is pointed towards). When the inclination exceeds 50 (for most survey tools), the tool must be switched to measure gravity toolface and displays the highside toolface. Magnetic toolface shows the azimuth that the BHA is pointed toward. Gravity toolface shows the angle between the highside of the motor and the highside of the hole (ie. A toolface of 1800 would be pointed straight down). Failure to switch between magnetic and gravity toolface will result in gross errors in toolface and ultimately, the projection of the well.
Why are premium connections utilized on casing strings and what operational challenges can arise due to their use?
Certain premium connections have been qualified as being thermally compliant and are a more robust thread - they reduce casing failures in the life of the well Torque monitoring may be required Thread washing The potential need to use CRT’s, dependent on style of rig Premium connections for casing accessories (ie. Float equipment, packers, etc.) X/O to API connections - (ie. Cement heads, drive subs)
What outcomes are required in cementing operations and why are cement jobs important in the thermal environment?
Obtaining full density returns to surface Reciprocation and rotation of casing string (premium connections) while cementing if possible - creating turbulent flow in the annulus Adequate Cement Bond Logs that outline zonal isolation has been achieved
What is a hydrostatic controlled cement plug (HCCP)?
A cement plug utilizing a tool on the end of a drill pipe that reduces the amount of hydrostatic pressure applied upon the cement plug Utilized in severe losses where balanced plugs are inadequate
What should be considered while losing circulation?
Influxes into the wellbore - kicks Stuck pipe event - keeping the drill string moving Reason for losses will determine the best approach to healing the losses - high pump pressure prior to losses, carbonate fracture, producing thermal area
What is considered trespassing?
Drilling deeper than 15m into a formation than the operator’s mineral rights Logging formations deeper than the operator has mineral rights to Coring formations that the operator does not have mineral rights to Formation tops are very important to verify, in order to not trespass in any way
What are some issues in relation to coring? Why is the core important?
Thermal vertical wells are mainly drilled for information purposes - the core is part of that information process Recovery is very important - parameters will need to be changed dependent on the type of formation being cored (ie. Rich bitumen formations vs. water saturated formations) Clear communication with geology is very important during this operation Ensuring core is handled and labeled correctly at surface
What should you be aware of prior to wireline logging a vertical or deviated well?
Has the wellbore been properly cleaned and is the drilling fluid properly conditioned What tool types are being run What length of time will the wellbore be sitting static to conduct the wireline logs What type of tests are being conducted (ie. Side wall cores, multiple pads on the wellbore, etc.) Which points in the wellbore are more suited for repeat runs to prevent getting stuck.
Give example of “Out of Scope” work? How should it be managed compared to a regular task?
After stopping activity, the risk is assessed for unplanned work, safe work procedures are identified, a pre-job safety meeting conducted and work proceeds ahead. Depending on the risk and job scope, a JSA will often be documented and reviewed by the crew during the safety meeting.
What conditions contribute to barite sag using WBM or OBM?
Mud with to low of yield point to keep barite suspended, high downhole temperatures causing OBM to thin, wellbore inclination > 30deg will cause barite to settle onto low side of well, influx of water, gas or oil can reduce mud suspension capacity, not circulating drilling fluid for extended periods will allow barite to settle out.
What limits casing running speeds? What is safe running speed?
Wellbore condition and integrity, personnel safety and surge pressures. Safe speed for casing is 30m/min.
Explain best practices for running a multi-packer frac system into a HZ well.
Confirm packer equipment is delivered as per program and inspect all components Tally assembly. Confirm OD/ID dimensions, threads, x/o’s, etc. are correct and record same Confirm reamer OD/assembly is as per program. Review reaming parameters with Supt. Confirm pipe drift dimension Review wellbore surveys/DLS info with Supt. And Tool Rep Confirm with Supt, Eng and Tool Rep that all tools are set up to funcition at proper pressures Review packer running assembly with Supt, Eng and Tool Rep. Discuss hole conditions, procedures, concerns, contingencies, etc. Document any changes to the running program
Explain best practices to avoid casing wear.
Hardbanding should be casing friendly similar to Arnco 350XT. A 2nd alternative is a fine particle tungsten carbide ground smooth similar to SmoothX Hardbanding using a coarse tungsten carbide material should not be rotated inside casing Ensure rig is centered over hole and BOPs are properly anchored to substructure Confirm DP/HWDP and kelly bar is straight. Monitor pipe condition and laydown any bent jts Avoid high DLS when rotatin DP through casing - especially with high hook loads Monitor metal filings recovered on ditch magnets and drill cuttings - especially wells with high DLS or significant rotating hours inside casing Avoid rotating DP in surface casing that is not cemented to surface (casing should be in tension or cemented when DP is rotated inside it)
Explain steps you’ve taken to manage stuck pipe after packed-off on a connection.
The pack-off most likely occurred while hoisting pipe with pump off. Attempt to free pack-off by stacking 20-30daN weight at stuck point and apply +/- 1500kPa DPP. Attempt to get the DPP pressure to bleed off and establish some flow through the debris. Attempt to work pipe down without pulling tension at stuck point and maintain +/- 1500 kPa pressure as required. If this fails, attempt to jar down on string starting with small impacts and increase as required - monitor DPP for sign of bleed-off. If pressure bleeds off, start pump slow to avoid debris packing off at the same restriction. Debris has likely fallen in from a washout above the stuck point - so jarring up should be the lastresort before attempting back-off/free-pt. Also, avoid continuously rotating DP in a pack-off condition which can cause a heat induced failure and parted DP.
Explain factors that impact ballooning? What are “telltale signs” the hole is ballooning?
Ballooning will generally be worse with invert or brine mud because small fractures can easily induce without a filter cake present Ballooning is more likely as MW or ECD increases Ballooning is more common in some formations because they have low fracture gradients - shale/ coal stringers are typical problem areas Telltale signs of ballooning are formations taking losses while circulating and later there is evidence of flow when the pump is shut down - typically the flow will taper off as the fracture closes. In addition, if ballooning has occurred, gas response from flow-back will be substantially less compared to a gas influx Important to be aware ballooning can be intermittent if wellbore strengthening or LCM is added to the mud system
How does drilling a HZ well impact kick detection and well control practices? Explain how you would educate a rig crew on managing a gas influx in this situation.
As a result of the HZ length acting as a gas seperator, HZ must be drilled with caution in order to properly remove trapped gas in the well. A good practice where trapped gas is suspected (ie. High drilled and connection gas units) is to circ the HZ interval in stages to avoid handling large volumes and pressures at surface. A further risk is inducing a kick as the entrained gas is circulated out, allowed to expand and displace mud in the annulus 2 key points to cover with crews are 1) understanding gas in solution 2) HZ interval acting as a gas seperator
Explain operations, well control, and HSE requirements when drilling with invert mud.
Gas influx while using invert mud is difficult to detect because gas goes into solution and the flow indication is minimal (or none). As a result, gas will later break-out of the mud as it’s circulated out and hydrostatic pressure drops below bubble point pressure. The break-out will be sudden and the gas expansion will reduce hydrostatic pressure and can induce another gas influx Important that everyone is constantly monitoring gas response (drill, connection, BG, trip, etc.). Gas response provides a good indication of formation pressure and trip margin Important crews follow PPE requirements in the invert exposure control plan (and know where to find the plan). Crews should limit their exposure around shakers and ensure the mud tank area has adequate ventilation - certain tasks require a respirator. Eye wash stations must be ready and accessible. Diesel wash guns are not allowed. Rig floor must have adequate traction. Crews should have proper footwear for invert Important invert spills are avoided by proper housekeeping, equipment design and maintenance, drip trays, crew training, etc.
After reaching TD in the intermediate or lateral section, what hole cleaning practice should be performed prior to starting to back ream out of the hole?
At ICP, circulate minimum 3 bottom’s up while rotating the pipe at 40 RPM and reciprocate the pipe full stroke
What is the optimum drilling flow rate for a 311mm intermediate section and a 222mm lateral section? Additionally, what flow rates should be used for back reaming those hole section sizes?
311mm intermediate section: 3.2 m3/min
222mm lateral: 2.2 m3/min
Always use the drilling flow rate while back reaming
What is oil accretion in Heavy Oil & Oil Sands drilling? How is it controlled? If not controlled/reduced what effect will it have drilling and running liner?
Sticking tendency of the oil and bitumen to DP/casing is called accretion Using anti-accretion polymer High torque while drilling, difficulty in running liner due to sticking inside intermediate casing and high push requirement.
Why is the risk of differential sticking higher in Lloydminster area? What procedures will reduce the risk of differential sticking?
Due to differential pressure between mud hydrostatic and formation pressure, in depleted reservoirs the risks are higher Differential sticking potential in sand formations can be greatly reduced by not allowing the drill string to remain static for longer than 3-5 minutes Reciprocate and rotate a stand for a minimum of 3 times before connection, survey or any time the pipe movement will be stopped. This practice has proved to reduce the risk of differential sticking as the pressure in the vicinity of the wellbore is invaded/balanced by the wellbore hydrostatic pressure
Explain the importance of landing the ICP at planned TVD on a SAGD producer and injector. While drilling out intermediate casing, the first 40m of the lateral cannot have a directional survey until MWD is out of shoe - What directional measure is applied to ensure control on the TVD while drilling out of the shoe?
SAGD pairs are designed to be minimum 5m separation. As the reservoir thickness is limited, it is critical to not land the producer below the planned TVD to ensure not entering the water, at the same time less than a meter above the plan is critical to ensure that room is left for the injector The directional plan of the injector is revised after drilling the respective producer lateral. Injector ICP is planned either 5m above the producer ICP or 5m above the highest point of producer lateral. In either case, the injector ICP may be more than 5m above the producer ICP (sometimes up to 8m above) Recored ABI at shoe. If more or less than 90 degrees, evaluate build or drop tendency. Based on the plan, proximity to producer may require us to scribe and slide right out of the shoe. NOTE: Although is EM telemetry but most of the time could record ABI
Explain ranging of an injector well to a producer well. What tool is used? What well control measure is in place when a ranging tool is in the producer? What tool is used while ranging to offset wells to mitigate the risk of collision? Explain.
To drill an injector well to within a planned instance to a producer intermediate and lateral, a MGT ranging tool is used. A MGT is a coil which is run on wireline and tractor and is magnetized by a current. The MWD in the directional BHA is programmed to measure the magnetic field created by a MGT coil. A calculation by the surface software measures the vertical and lateral separation A lubricator with a stuffing box is installed on the producer casing bowl RMRS ranging method is applied. It includes RMRS sub (magnet) which is installed above the bit in the directional BHA. The RMRS probe is run in the offset well by wireline. The RMRS probe measures the magnetic field due to RMRS sub. Distance to offset the well is calculated accordingly
- What type of cement is used in surface and intermediate casing of thermal wells? Having a good cement bond in thermal wells is vital to receive the approval for well commissioning - what practices are applied to improve the cement integrity? What is the procedure for casing movement while circulating the casing on bottom? What is the procedure for casing movement when pumping and displacing cement?
Thermal cement is used on surface and intermediate casing Intermediate casing in the thermal well must have a good cement bond to surface. To ensure cement returns to surface, it is vital that any losses be reported and controlled before further drilling. Pump cement until cement returns to surface, then drop the plug and displace Rotate the casing at 10 RPM for about 5 minutes and record the torque. This is the base line for casing rotation while cementing. Casing connection has limited fatigue endurance due to rotation at high doglegs. NOTE: Do not rotate the caisng while circulation and mud conditioning. While pumping and displacing cement, continuously/slowly stroke the casing up and down 10m and rotate at 5-10 RPM unless hole condition limits the stroke or rotation. Set the torque limit at 75% of casing make up torque
