Did You Know?
K&M offers a range of training for Drilling and Completion Engineers, Supervisors, Superintendents, Rig Crews and Service Company personnel.
It is possible for the bottom hole circulating temperature to be higher than bottom hole static temperature? This is contrary to popular belief that circulation cools down the well/BHA. The reason that the circulating temperature is higher is because the pressure drop along the drill string during circulation is dissipated as heat energy to increase the temperature. Higher bottom hole circulating temperature is more likely to occur in bigger hole sizes such as 17½" and 12¼" as the flow rates used are higher. The use of synthetic
oil-based mud is also more likely to result in higher bottom hole circulating temperature compared water-based mud as the specific heat for base oil is significantly lower than water i.e. less heat energy required to increase the temperature by a specific amount. In addition, water-based mud typically has lower plastic viscosity (PV) value which reduces the drill string pressure drop, i.e. less heat generated.
Bottom hole circulating temperature higher than static temperature may result in
pre-mature BHA failure if the circulating temperature is approaching/ exceeding the limits of the BHA. It will also result in higher flow line temperature. If heat is not dissipated in the mud pits fast enough, the suction temperature will also be higher and when suction temperature exceeds 7o·c
(158°F) the mud pumps reliability reduces as the polyurethane material on the swabs typically starts to soften when temperature exceeds 7o·c (158°F). In some situations, mud cooler is necessary to cool down the flow line temperature.
As such, modelling of bottom hole circulating, flow line and suction temperatures are crucial in achieving a high-performance drilling operation.
Above are two temperature plots with drilling parameters for the same well. The top plot is for sidetrack 1 and the bottom plot is for sidetrack 2 (BHA was stuck during the trip out in sidetrack 1). In sidetrack 2, the well path, drill string and BHA are engineered to reduce the pressure drop, and the bottom hole circulating temperature at TD of sidetrack 2 is significantly less than sidetrack 1 for the same flow rate and mud type.
Did you know that in a high angle well, poor hole cleaning results in lower ECD? This is contrary to the popular belife that ECD increases when hole cleaning is poor. The reason that ECD decreases with poor hole cleaning is that only cuttings suspended in the mud contributes to ECD while cuttings laying on the low side of the hole does not. When hole cleaning is poor, there will be less cuttings suspended in the mud in the near vertical section of thr well, as such, lower ECD.
In the example below, a high angle tangent 16" section was drilled. The rotary speed was reduced from 150 rpm to 70 rpm for directional control reasons from 3,250m (10,660') onwards to section TD at 3,800m (12,465'). ROP remained at 50-60 m/hr (160-200 ft/ hr) while flow rate was constant at 5,500 lpm (1,450 gpm). Both pick up and slack off drag trend increased indicating insufﬁcient hole cleaning due to the reduction in rotary speed. However, both the ESD and ECD were showing a decreasing trend from 3,250m (10,660') onwards to section TD at 3,800m (12,465'). The measured ESD and ECD were lower than the hydraulics model prediction. This example clearly shows that ECD decreases with poor hole cleaning and lower than expected ECD relatively to the model should not be taken as everything was going well.
In high angle or extended reach wells, Torque is generally not a good indicator of hole condition – in most cases torque friction factors actually REDUCE over the course of a long drilling section. In the example below, a 6000ft section of high angle 9⁷⁄₈” hole was drilled. Right after drilling out the previous casing shoe surface torque was 4k ft-lb and equivalent to a 0.50 friction factor. Looking ahead to TD, if the friction factor stayed the same, torque would have been nearly 20k ft-lb. Even more concerning, with that friction factor rotation of the 7” liner string would have been impossible. But as drilling progressed, the torque friction factor was continuously reducing. Two factors drive this very common phenomenon: 1) while rotating at high speed (for hole cleaning) the tool-joints are polishing the inside of the previous casing creating a lower friction surface and 2) as a cutting bed develops the drill pipe is supported by the cuttings and the hard, oil coated cuttings act effectively as ball bearings. It’s always important to monitor torque in any complex well – but don’t expect it to tell you if the hole is clean!
K&M Technology's Proprietary Software Platform ERA (Extended Reach Architecture) features a “steady state” circulating temperature model that is used to correct fluid density, downhole rheology, and metallurgical properties of tubulars to adjust for temperature effects. The temperature in the well is computed based on the heat transfer between formation, pipe and fluid in the annulus. The model accounts for the heat generated by the bit, torsional friction and fluid friction. ERA allows to calibrate the circulating temperature model using three main parameters - Geothermal Temperature – Usually the largest source of heat. Simple or complex definition of geothermal temperature is possible. This should be based on offset wells or temperature surveys. - Inlet Temperature – A fixed value or a function of flowline temperature - Heat Transfer Factor – Calibration factor to account for unknowns related to the fluid composition and annular conditions. The biggest uncertainty.
K&M Technology's Proprietary Software Platform ERA (Extended Reach Architecture) has a Built in Sensitivity Analysis feature. ERA allows the user to see results with sensitivity to practically any drilling, tripping or cementing parameter. You can choose which parameter to run sensitivity on or rely on ERA’s built in set of standard plots which is populated with the most common sensitivities.
K&M Technology's Proprietary Software Platform ERA (Extended Reach Architecture) Wellpath Builder feature builds well paths from scratch using our built-in design profiles. Just choose your desired profile, enter simple parameters, like desired DLS, TVD and Inclination, and ERA calculates the rest for you. Add targets to drive the design and tie into existing surveys. Proximity to other wells is calculated and displayed to help guide your design.
K&M Technology's Proprietary Software Platform ERA’s (Extended Reach Architecture) Downhole MSE feature can infer downhole mechanical specific energy (MSE) using surface parameters by backing out the drill string’s contribution to surface-measured loads. ERA can also utilize downhole measurement, allowing users to compare two independent methods of calculating MSE at the bit. This approach yields unique opportunities to prevent and/or correct destructive conditions from occurring downhole
K&M Technology's Proprietary Software Platform ERA’s (Extended Reach Architecture) VME Limit plots show the maximum permissible surface tension and surface torque limits and are plotted alongside expected loads to give engineers and field personnel confidence that operations will not exceed specified pipe limitations, even under complex loading situations.
K&M Technology Group’s ERA (Extended Reach Architect) Software has Integrated Geomechanics - When basic log data is input, users can build their own mechanical earth model to calculate earth stresses and rock properties, or users can directly enter this data from third party MEMs. ERA will then compute geomechanical limits for any well path. Calculated limits include breakdown and breakout thresholds for several different failure criteria and variable risk levels. ERA will also compute wellbore damage (via pseudo-caliper and/or pseudo-image logs) for planned operating conditions, or postmortem.
There seems to be a belief that doglegs are “smoothed out” while drilling and especially after casing runs.
- In the example below, a well was sidetracked due to a shallow fish that was left in hole.
- The well was a deep TVD well with high tension loads across the shallow doglegs at the sidetrack point. This resulted in high normal forces and risks causing a casing wear problem.
- Given a fixed tension load, the normal forces are directly proportional to the size of the dogleg.
- A gyro was run to determine how much lower the doglegs were after running the intermediate casing across the sidetrack point.
- The result of the gyro confirmed that the doglegs had not been reduced and in fact were higher than measured with the MWD. The first graph below shows the MWD survey. The second graph shows the Gyro survey compared to the MWD.
- Confirming that the doglegs still posed a significant risk of wear to the casing resulted in the operator utilizing non-rotating drill pipe protectors (NRDPPs) to drill the 8½” section to protect the 9⅝” casing.
Using Auto-fill equipment reduces surge pressures and mitigate risk of mud losses during tight clearance casing deployment? High surge pressure can result in mud losses and formation damage, which can jeopardize successful cement placement and zonal isolation. Accurate modeling of surge pressures with open and closed string set up during planning stage will help you evaluate if the use of auto-fill equipment can be beneficial to your operations, without the need for costly design changes to your well! What is happening: Due to low annular clearance, surge loads can exceed the formation loss gradient even at low running speed. This is particularly apparent in challenging wells with narrow mud window, such as Extended Reach or deep-water projects. If running the casing conventionally as closed ended, the fluid in the annulus is pushed up-ward generating high surge pressure; however, with the installation of auto-fill, the drilling fluid will flow freely into and up the casing, reducing both the surge and swab pressure loads felt by the formation. Reducing surge pressure will mitigate risk of mud losses and also can allow increased running speed. To ensure useful application of auto-fill equipment, optimum hole cleaning and following equipment operating procedures will you help mitigate risk of tool plugging or auto-conversion during the run.
K&M Technology Group’s ERA (Extended Reach Architect) Software focuses on a Holistic Design Structure- ERA’s unique configuration keeps the user centered over the entire well. This approach allows the user to develop the well as a system, rather than focusing on piecemeal components only.
K&M Technology Group’s ERA (Extended Reach Architect) Software Execution Mode allows a user to input measured operational data that feeds into ERAs calculation engines, allowing direct comparison between modeled and theoretical loads, normalized for varying parameters as the well is drilled. Loads are also forecasted to TD to allow real-time decision making. This is the same module that K&M ERD Advisors use daily to advise our clients worldwide.
Are you concerned on a challenging geological target interception, or Well collision avoidance? Designing a complex platform exit strategy? Managing your large well surveying database? K&M team has the unique capabilities and expertise to provide support on the key aspects of the Surveying Management
- Surveying Management Process
- Advance Surveying Techniques
- Anti-collision and Survey QA/QC
- Relief Well Planning
- Platform/Pad Drilling Design
- Surveying Management Training
• The weak point of a string won’t necessarily occur at surface and won’t necessarily occur in the smaller / weaker pipe either (if running a taper string).
• In the example shown the weak point does not occur at surface, nor does it occur in the “weaker” 4½” drill pipe.
• The weak point actually occurs at around 600’ with the tensile capacity of the string being reduced at this depth as a result of the string being subject to additional stress from already having to “bend” around the dogleg at ~600’
• Its important that the combined loads on a string be analyzed and the actual as drilled surveys taken into account. The example also illustrates the potential issues that can arise as a result of unplanned large shallow doglegs.
Running a reamer style shoe often results in the need to ream through horizontal intervals due to their poor bypass area:
• Reaming shoes typically have a larger OD than conventional shoes and a reduced bypass area, so there is an increased risk of solids accumulating in front of it, resulting in the necessity to ream.
Did You Know?
When you have a stuck pipe incident on a long horizontal well, we are told to work the pipe in the opposite direction to which it was moving when it became stuck. However, if you don’t pick up the pipe enough distance to overcome the drill string stretch, then you might not get free ever.
What is happening: Normally the stuck pipe gets stuck at the BHA. When you put tension on the drill string, the amount of pipe movement at surface is not all transferred to the BHA due to friction.
If you pull the pipe a distance that is less of the pipe’s stretch, then you will never get the pipe free. You need to first estimate how much pipe stretches or compresses when stuck at the BHA. In this example you will need to pull at least 40 ft (for a 0.20FF) at surface before any movement gets transferred to the bit and BHA located at 23,000 ft measured depth on this horizontal well
Your Maximum Overpull can be well below the tension limit of your drill pipe? That shallow doglegs can greatly reduce your maximum overpull?
What is happening: What your drill pipe feels during an overpull even is not just tension – but is a combined load of tension, torque (if present), and bending. Shallow doglegs can cause high side forces and bending stresses!
If taking only the drill pipe published tension limit, the example below would think that an overpull of 100 kips (at the bit) is no problem – however, the shallow doglegs and associated bending stresses show that the overpull limit is not felt at surface – but rather at ~1,100’!
Breakover (static) torque after connections can be a reliable indicator that the drill string is getting differential stuck. While drilling, connection practices should be tailored to capture the relevant data:
· Rotate FIRST after a connection (no up-down movement of the string)
· Record peak torque (i.e. breakover) values
· Compare to the dynamic off bottom torque In this example, there was little difference between the breakover and the off-bottom torque in the Claystone section. There was a significant increase in breakover torque from 13,250’ (Friction Factor > 0.25) in a clean sand with permeability. On the last two connections at 14,060’ and 14,157’, the static Friction Factor increased to 0.33 indicating increasing differential sticking while the pipe was stationary. Although collecting the breakover torque data unfortunately the wellsite team did not respond to the increasing divergence between static and dynamic friction. While circulating the hole clean at TD, the pipe became stuck after being stationary for ±12 mins while making a connection backreaming stands. Unfortunately, the pipe could not be freed resulting in a costly unplanned sidetrack.