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Diverter Operations Summary (API RP 64)Training and Instructions:Develop Written Procedures: Ensure that detailed written procedures for diverting are created and posted on the rig before the drilling operation begins (spudding).Conduct Drills: Design and execute various drills to assess the crew’s readiness and response to different diverting scenarios. These drills should be planned before spudding and scheduled periodically throughout the operations.Document and Analyze Drills: Keep a record of all diverter drills and analyze the results to pinpoint areas where the crew’s performance can be improved.Follow-Up and Improvement: Document any corrective actions taken to enhance crew performance and ensure lessons learned are addressed.Update Emergency Plans: As rig conditions change, ensure that emergency plans and training are kept up-to-date to reflect the current operating environment.Example of Diverter Procedures (API RP 64):Pick Up Kelly Connection: Raise the kelly connection 2 to 3 feet above the rig floor.Open the Vent Line: Select and open the correct overboard vent line based on the flow volume and prevailing wind direction.Close Diverter and Shale Shaker Valve(s): Secure the diverter and close the shale shaker valve(s) to prevent any further flow into the system.Check Slip Joint Packer Pressure (for Floating Rig): If a floating rig is in use, verify the slip joint packer pressure and make adjustments as necessary.Switch to Kill Fluid: Change over to pumping kill fluid at a rate suitable for the available equipment.Alert Personnel: Notify all rig personnel about the situation and any immediate actions required.Continue Pumping Kill Fluid: Keep pumping kill fluid while preparing to transition to seawater if drilling fluid runs low.Monitor for Gas Bubbles: Assign personnel to observe the vicinity of the drilling vessel for any signs of gas bubbles.Communicate Developments: Keep the person in charge informed of all progress and changes.Example of Diverter Procedures with a Floater and Subsea BOP Installed:Pick Up Kelly Connection: Raise the kelly connection 2 to 3 feet above the rig floor.Shut the Well In with BOPs: Stop the pump and immediately shut in the well using the blowout preventers (BOPs).Close Diverter and Shale Shaker Valve: Secure the diverter and close the shale shaker valve(s), keeping the vent valve(s) open. Inform the supervisor of the action.Determine Well Control Method: Assess the well conditions and select the appropriate well control procedure.Alert Rig Personnel: Notify all personnel on the rig about the situation and verify the slip joint packer pressure is adjusted as necessary.Shut Down Non-Essential Systems: Extinguish any open flames and power down unnecessary electrical systems to prevent further hazards.Monitor for Gas Bubbles: Immediately post someone to watch for gas bubbles around the rig.Report Diverter Flow or Gas Bubbles: If diverter flow or gas bubbles appear, inform the person in charge immediately for further action.This summary of diverter operations aligns with the guidelines in API RP 64, providing a structured approach to safely manage well control during drilling operations. Read More

Glossary of Terms Abnormal Formation Pressure: a formation pressure greater than the hydrostatic pressure exerted by vertical column of water with salinity normal for that geographic area. Abnormal pressure is therefore something higher than is normal for that area. Accumulator Bottle: a vessel for storing the hydraulic energy that is used to perform BOP functions Accumulator Drawdown Test: a test to verify the accumulator system is able to support the fluid volume and pressure require-ments of the BOP in use and to be capable of securing the well in the event of a total loss of power Acoustical Backup System: used to actuate up to sixteen different preselected critical functions if the primary system were to fail Active Barrier: a barrier designed to be actuated either manually (e.g. by a diver or ROV) or by some form of remote control Adjustable Choke: a choke that can be used to vary the rate of flow through its orifice Aerosol: the suspension of fine solid particles or liquid droplets, in air or another gas. Air Pump System (Accumulator): pneumatic pumps that should be capable of charging the accumulators to the system working pressures Anhydrite: a form of calcium sulphate Anhydrite: an evaporate with the chemical formula CaSO4 + H2O Annular BOP: a blowout preventer that uses a donut-shaped elastomeric sealing element to seal the space between the tubular and the wellbore or an open hole. Annular Capacity: the volume capacity of the annulus in units of bbl/ft Annulus: the is donut-shaped space between the wall of the hole and the drill string Anticline: although not strictly true, for our purpose we can think of an anticline as a fold in the rock that points up like the crest of a wave API Connection: a flange, hub, or studded connection that meets the API standards of manufacture Aquifer: a water-bearing rock or reservoir Arrested Compaction: similar to undercompaction Artesian Pressure: a well where the potentiometric surface is above the rig floor, causing the well to flow Atmospheric Pressure: the pressure exerted on the surface of the earth by the weight of the atmosphere. Normal atmospheric pressure at sea level is about 14.7psi Atoll: a circular coral island with central lagoon that usually formed around an ancient submerged volcano Auto-Shear System: a system to automatically shutdown the wellbore by activating the shear-blind rams in the event of total loss of control from the pods or the LMRP becomes unexpectedly disconnected Auto Fill Casing Valve: a self-filling casing shoe valve run to reduce the surging pressures while running casing. AX Ring Gasket: a Cameron gasket used in the subsea wellhead and LMRP hydraulic connector Back-reaming: a procedure for tripping out of the hole through tight spots and involves a combination of pumping and rotating Back Pressure: the pressure resulting from resisting flow Ball/flex Joint: designed to deflect the bending stresses imposed on the riser system by tides and sea currents Ball Joint: consists of a ball and socket arrangement where pressurized hydraulic fluid (from a pilot Read More

Reacting to a Warning Sign When a blowout preventer (BOP) is in place, the immediate reaction to a warning sign is to perform a flow check. This test determines whether the well is flowing without the pumps running, signaling a kick (a positive indicator). Conducting a Flow Check To conduct a flow check, operations must be paused to allow enough time for observation. The flow check duration typically ranges from 10 to 15 minutes, though it may take up to 30 minutes depending on factors like mud type, formation permeability, and other conditions. Flow Check Procedure While the specific procedure may vary by rig, the general steps are: Pause Drilling: Stop drilling or other rig activities. Space Out the Tool Joint: Position the tool joint so that neither it nor its upsets are aligned with the pipe rams. A diagram for spacing out the tool joint should be displayed in the dog house. Stop the Pumps: Turn off the pumps. Stopping the rotary is optional. Align to the Trip Tank: Line up the well with the trip tank for monitoring. Record Flow Data: Observe and document the flow-back volume and the time taken for flow to stop. Compare these values with previous flow check data. Analyze Flow Status: If there is no flow or the flow-back is consistent with previous checks (fingerprinting), continue with operations. If the flow exceeds the normal range, sound the alarm and immediately shut in the well. Do not wait for a second opinion or delay. Confirm Well Security: After securing the well, notify the supervisor. Flow Check During Drilling When drilling, the flow check procedure is slightly modified: Lift the Bit: Pick the bit up off the bottom and space out the tool joint in the stack. Stop Rotary (optional): You may choose to stop the rotary. Stop the Pump: Make sure the booster valve is closed. Line Up to the Trip Tank: Prepare the return flow to the trip tank. Monitor the Well for Flow: Observe for any signs of flow. Shut in if Flow is Detected: If the well is flowing, shut the appropriate BOP and open the HCR (C & K line) valves. Monitor for BOP Leaks: Watch the trip tank for any BOP leaks. If a leak is detected, close a preventer below the leak to prevent escalation to a blowout. Record Pressure Readings: Document the SIDPP, SICP, Kill Line Pressure, and pit gain. Prepare for Further Actions: On a floater, set the compensator as needed. When to Stop Pumping It’s best practice to keep the mud pump(s) running until the tool joint is properly positioned. This helps retain the extra annular pressure acting on the wellbore, minimizing the risk of a kick. Warning Signs During Tripping While tripping, warning signs like the well not taking the expected amount of fluid, increased drag, or increased string weight suggest the possibility of a kick or losses, both of which could lead to underbalance. If the trip sheet indicates deviations from expected hole Read More

Kick Warning Signs: What Drillers Need to Watch For Kick warning signs are crucial indicators that help a driller recognize when the well is at risk of going underbalanced, which could lead to a kick (influx of formation fluids into the well). These warning signs fall into three categories, as defined by the API: Offset Well Information Physical Response Indicators Chemical and Technical Indicators When a warning sign is detected, the driller should immediately perform a flow check to assess the situation and prevent further escalation. 1. Offset Well Information Offset wells refer to wells drilled in the same area before, providing valuable data on the formation and pressures. Information from offset wells can give advance warning of potential kick risks. Key data includes: Formation pressure gradients: Information on pressure zones and their depths can indicate areas that may be capable of flowing. Fracture gradients: Data on the fracture pressure of the formations can warn of potential loss zones. Permeability: Permeability data shows how easily fluids can enter the wellbore, indicating potential kick risks if the formation is highly permeable. This information is only useful if it is shared between reservoir engineers, well planners, and the rig team, ensuring everyone is aware of potential risks. 2. Well Physical Indicators Physical indicators are warning signs that can be observed directly during the drilling process. These indicators are often picked up through close monitoring of drilling parameters, mud monitoring systems, and flow line data. Physical warning signs include: Drilling break: A sudden change in the rate of penetration can signal that you’re drilling into an under-compacted shale or a high-pressure zone. Lost circulation: If mud returns are lost to the formation, it indicates that hydrostatic pressure is being reduced, putting the well at risk of going underbalanced. Pump pressure/speed variations: If the pump pressure or speed fluctuates, it could suggest that a kick has occurred or that the well is drilling sloughing formations. Temperature gradient increase: Higher temperatures can indicate you are drilling into high-pressure or gas-bearing formations, or under-compacted shale. Reduction in mud density: A decrease in mud density might suggest an influx of less dense formation fluids, increasing the risk of a kick. Gas levels increase: Rising levels of gas after connections (connection gas) can indicate increasing formation pressures. Similarly, trip gas after circulating can signal that hydrostatic pressure is decreasing. Tight hole/sloughing: When the hole becomes tight or sloughing, it can suggest that you’re encountering high-pressure formations. Changes in cuttings: Significant changes in the size, shape, or quantity of the drill cuttings can indicate that you’re drilling into high-pressure formations. 3. Chemical and Technical Indicators Chemical and technical indicators are usually monitored by specialized personnel such as mud engineers and mud loggers. These indicators help detect any subtle changes that might indicate a kick. They include: Chloride changes: Variations in chloride levels in the mud can point to a potential water kick. Oil shows and staining: If oil is observed on the cuttings or shaker screens, this can indicate Read More

What is Horner Time?   Horner Time refers to a technique used in reservoir engineering to analyze pressure buildup data from a well test, particularly in a situation where the well is shut in after being produced or flowed. It is named after the engineer J. R. Horner, who developed this method in the 1950s. Horner Time is an important concept for interpreting pressure transient tests, which help assess the productivity and behavior of the reservoir. How Horner Time Works Horner Time is applied to build-up tests, which occur after the well has been flowing for some time and is then shut in to monitor how pressure increases back to equilibrium over a period of time. The test helps determine the reservoir properties, such as permeability, skin factor, and reservoir pressure. The Horner Plot is a graphical representation of pressure vs. Horner Time, where Horner Time is used as the time axis. Formula for Horner Time The Horner Time is calculated as: Application of Horner Time Analyzing Pressure Data: When a well is shut in after production, pressure data is recorded over time. The pressure increase is plotted against the Horner Time, where the Horner Time accounts for the pressure response over different periods. This allows engineers to analyze the rate at which the pressure recovers and to estimate reservoir properties like permeability and reservoir pressure. Pressure Transient Analysis: The Horner method helps to convert pressure buildup data into a more interpretable form. By plotting pressure on the y-axis and Horner Time on the x-axis, you can obtain a straight line on the graph, which is useful for estimating reservoir parameters. Estimating Reservoir Properties: Using the Horner Plot, engineers can estimate: Reservoir permeability: The rate at which fluids can flow through the reservoir rock. Skin factor: A measure of damage or changes in permeability near the wellbore. Reservoir pressure: The pressure at the initial state of the reservoir before any production. Decline Curve Fitting: In some cases, Horner Time can be used in decline curve analysis for forecasting production decline in reservoirs, helping operators make better decisions regarding well stimulation, production strategy, and reservoir management. In Summary: Horner Time is a time transformation used in reservoir engineering to analyze pressure buildup data during a well test. It allows engineers to apply pressure transient analysis to evaluate important reservoir parameters like permeability, skin factor, and initial pressure. The method involves plotting pressure versus Horner Time and fitting the data to determine reservoir characteristics. This technique is a fundamental tool in reservoir engineering for optimizing well performance and assessing the long-term productivity of oil and gas reservoirs. Read More