Drilling Engineering PE 311

1. Drilling Engineering PE 311

2. Drilling operations vary according to location, depth, formation characteristics and many other factors. But they all have the same underlying goal: to drill safely and at minimal cost while providing a fit-to-purpose well. A drilling problem is any occurrence or condition that stands in the way of well objectives. It could involve anything from weather to transportation delays to blowouts. In this discussion, we concentrate on problems that relate directly to the drilling process itself. Major drilling problems may including: Abnormal formation pressure, kick, lost circulation, borehole instability, stuck pipe, hydrogen sulfide, �

3. When the pore pressure in a permeable formation exceeds the wellbore pressure, fluid flows from the formation into the well. This fluid influx is known as a kick. The kick may cause blowout. Consequences: Loss of human life Loss of rig and equipment Loss of reservoir fluids Damage to the enviroment Huge cost to bring the well under control

4. The mud weight is generally designed such that the borehole pressure opposite permeable is around 200-300 psi greater than the formation pore pressure. This pressure differential is known as the overbalance. If the mud weight is reduced the overbalance becomes less and the risk of taking a kick becomes greater. The mud weight will fall during normal operations because of the following: Solids removal: If the solids removal equipment is not designed properly a large amount of the weighting solids (barite) may also be removed. Excessive dilution of the mud Settling of barite particles (barite sag) Gas cutting of the mud: if gas seeps from the formation into the circulating mud (known as gas-cutting), it will reduce the density of the drilling fluid.

5. Pressure due to mud column exceeds pore pressure

6. Kick due to abnormal pressure

7. Kick due to reduction in mud weight

8. If the height of the mud column has dropped below safe levels, the kick may occur. The most common reasons for this to happen include: Tripping out: Whenever pipe comes out of the hole, the fluid level drops by an amount corresponding to the pipe's displacement volume (for a triple stand of drill pipe, on the order of two barrels or less). Lost circulation: High pressure differentials between the wellbore and the formation may cause mud to flow into the formation, causing a dangerous drop in fluid level. Swabbing: is the process by which fluids are sucked into the borehole, from the formation, when the drillstring is being pulled out of hole.

9. Kick due to reduction in fluid level in borehole

10. If a kick occurs, and is not detected, a blowout may develop. The drilling crew must therefore be alert and know the warning signs that indicate that an influx has occurred at the bottom of the borehole. Since the influx is occurring at the bottom of the hole, the drilling crew relies upon indications at surface that something is happening downhole. Although these signs may not all positively identify a kick, they do provide a warning and should be monitored carefully. Some of the indicators that the driller sees at surface can be due to events other than an influx. For example, an increase in the rate of penetration of the bit can occur because the bit has entered an overpressured formation or it may occur because the bit has simply entered a new formation which was not predicted by the geologist. However, all of the following indicators should be monitored and treated with cautions.

11. The primary warning signs of a kick are those that give direct indications of flow. These include the following conditions: Flow rate, Q increase: The Q from the annulus increases, even though the pump rate is constant. Mud pit volume gain: The pit level rises, even though no materials have been added to the mud system. Well flowing without pumps: Mud continues to flow from the annulus after the pumps have been shut off. Improper fill-up when pulling out of the hole: the fluid is most likely flowing or being swabbed in from the formation.

12. Other warning signs are often referred to as secondary, because they do not directly indicate flow. Nevertheless, they should be taken seriously. Drilling break: An abrupt penetration rate increase can result from entry into a high-porosity, overpressured formation. Although this is not a direct flow indicator, it is a critical warning sign. Decrease in pump pressure accompanied by increase in pump speed: A low-density formation fluid entering the wellbore may cause pump pressure to decrease. The pump rate may increase as kick fluid in the annulus causes the heavier mud to fall down the drill pipe. Hook load increase: reduced buoyancy due to a lower-density fluid entering the wellbore. Reduced mud weight or gas-cut mud: Although this may indicate a kick, low mud weights at the surface are usually the result of gas expansion, and reflect only the fact that a gas-containing horizon has been drilled.

13. If a kick is detected and a pit gain has occurred on surface, it is clear that primary control over the well has been lost and all normal drilling or tripping operations must crease in order to concentrate on bringing the well back under primary control. The first step to take when primary control has been lost is to close the BOP valves, and seal off the drillstring to well head annulus at the surface. This is known as initiating secondary control over the well. It is not necessary to close off valves inside the drillpipe since the drillpipe is connected to the mud pumps and therefore the pressure on the drillpipe can be controlled.

14. The second step is to collect the following information: Pump data, including reduced circulating rates and pressures Capacities of casing, open hole, drill string and annulus Formation fracture pressures In order to get this information, the initial shut-in is needed.

15. If kicks occur during drilling for a fixed rig, following actions need to be made: Raise the kelly until a tool joint is above the rotary table. Shut down the mud pumps. Close the annular blowout preventer. Record shut-in drill pipe pressure, shut-in casing pressure and gain in pit volume.

16. If kicks occur during tripping for a fixed rig, following actions are needed Set the top tool joint on the slips. Install a full-opening, fully-opened safety valve in the drill pipe. Close the safety valve and the annular preventer. Notify company personnel. Pick up and make up the kelly. Open the safety valve. Record shut-in drill pipe pressure, shut-in casing pressure and

17. Note: the drillpipe and annulus pressure will be different since, when the influx occurs and the well is shut-in, the drillpipe will contain drilling fluid but the annulus will now contain both drilling fluid and the fluid (oil, gas or water) which has flowed into the well. Shut-in drill pipe pressure (SIDPP) Shut-in casing pressure (SICP) Pit volume gain --> Determine the weight of the kill mud; --> Calculate the volume and type of the influx.

18. Ppore = SIDPP + (Pmud)dp���� Ppore = SICP + (Pmud)ann + Pinflux� Where (Pmud)dp = Hydrostatic pressure of mud in DP (Pmud)ann = Hydrostatic pressure of mud in Ann Pinflux = Hydrostatic pressure of the influx in Ann Ppore = pore pressure

19. The purpose of replacing the old mud by the kill mud is to have a zero SIDPP. Therefore, the mud weight required to kill a well (kill mud) is equal to the sum of the original mud weight and the equivalent mud weight (EMW) of the shut-in drill pipe pressure: where MW2 = density of kill mud, lbm/gal ����������� MW1 = original mud weight, lbm/gal ����������� TVD = true vertical depth, ft

20. Example: While drilling ahead with a mud weight of 10.3 ppg, a well takes a 35-bbl kick at a depth of 9500 ft TVD. The well is shut in, and a SIDPP of 400 psi is recorded, along with a SICP of 1650 psi. What mud weight is needed to kill this well? Solution:

21. While well control procedures are designed to handle any type of fluid, it is useful to know whether the influx is primarily oil, water or gas. This allows us to predict maximum surface pressures and take any special fluid-handling precautions that might be necessary. We use the information recorded during the initial shut-in to calculate the fluid's pressure gradient. Based on the kick�s pressure gradient, type of fluid can be determined. Gas: 0.05 � 0.2 psi/ft Oil: 0.3 � 0.4 psi/ft Seawater: 0.47 � 0.52 psi/ft

22. The kick fluid gradient (ginflux) is equal to Students, prove this equation !!!!!!!!! where hinflux = height of influx in annulus. This is equal to the pit volume increase divided by the cross-sectional area of the annulus: V = pit volume increase, bbl ; d2 = hole diameter, inches ; d1 = pipe outside diameter, inches

23. Example: Determine the type of kick fluid that has entered a well, given the following data: Depth = 12780 ft (TVD) Mud weight = 13.2 lbm/gal Drill pipe = 4�� O.D. Hole size = 8.75�� SIDPP = 700 psi SICP = 980 psi Pit volume gain = 30 bbl

24. Solution: The kick fluid is gas

25. The procedure used in this method is to circulate out the influx and circulate in the heavier mud simultaneously. The influx is circulated out by pumping kill mud down the drillstring displacing the influx up the annulus. The kill mud is pumped into the drillstring at a constant pump rate and the pressure on the annulus is controlled on the choke so that the bottomhole pressure does not fall, allowing a further influx to occur and does not exceed the fracture pressure.

26. The advantages of this method are: Since heavy mud will usually enter the annulus before the influx reaches surface, the annulus pressure will be kept low. Thus, there is less risk or fracturing the formation at the casing shoe. The maximum annulus pressure will only be exerted on the wellhead for a short time. It is easier to maintain a constant bottomhole pressure by adjusting the choke.

27. Interpretation of wellbore pressures as a U-Tube

28. To avoid the formation damage, a low pump rate should be used. A kill rate of 1-4 bbls/min is recommended. The pressure drop in the drillstring, Pc1, which occurs while pumping at the kill rate will be known from the pump rate tests which are conducted at regular intervals during the drilling operation. Initially, the pressure at the top of the drillstring, known as the standpipe pressure, will be the sum of Pdp(SIDP) + Pc1. By the time the heavy mud reaches the bit, the initial shut-in pressure Pdp(SIDP) should be reduced to zero psi. The standpipe pressure should then be equal to the pressure drop due to circulating the heavier mud, Pc2.

30. The time taken (or strokes pumped) for the drillstring volume to be displaced to the heavy mud can be calculated by dividing the volumetric capacity of the drillstring by the pump output.

31. The engineer�s method can be divided into 4 stages: Stage 1: displacing drillstring to kill mud As the kill mud is pumped at a constant rate down the drillstring the choke is opened. The choke should be adjusted to keep the stand pipe pressure decreasing so that the bottomhole pressure is maintained at a level greater than the formation pressure throughout the operation, and hence there is no further influx occurs (this plot is discussed above). Once the heavy mud completely fills the drillstring, the standpipe pressure should stay the same, Pc2. The pressure in the annulus usually increases during stage I due to the reduction in hydrostatic pressure caused by gas expansion in the annulus.

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33. Stage 2: Pumping heavy mud into the annulus until influx reaches the choke During this stage of the operation, the choke is adjusted to keep the standpipe pressure constant. The annulus pressure will vary more significantly than in phase I due to two effects: The increased hydrostatic pressure due to the heavy mud entering the annulus will tend to reduce Pann. If the influx is gas, the expansion of the gas will tend to increase Pann since some of the annular column of mud is being replaced by gas, leading to a decrease in hydrostatic pressure in the annulus.

34. Stage 3: all the influx removed from the annulus As the influx is allowed to escape, the hydrostatic pressure in the annulus will increase due to more heavy mud being pumped through the bit to replace the influx. Therefore, Pann will reduce significantly. If the influx is gas, this reduction may be very sever and cause vibrations which may damage the surface equipment.

35. Stage 4: influx being expelled and heavy mud reaching surface During this phase, all the origical mud is circulated out of the annulus and is the annulus is completely full of heavy mud. If the mud weight has been calculated correctly, the annulus pressure will be equal to zero. , and the choke should be fully open. The standpipe pressure should be equal to Pc2. To check that the well is finally dead, the pumps can be stopped and the choke closed. The pressures on the drillpipe and annulus should be zero. If the pressures are not zero, continue circulating the heavy weight mud. When the well is dead, open the annular preventer, circulate, and condition the mud prior the resuming normal operations.

37. The Drillers Method for killing a well is an alternative to the One Circulation Method. In this method the influx is first circulated out of the well with the original mud. The heavy weight kill mud is then circulated into the well in a second stage of the operation. As with the one circulation method, the well will be closed in and the circulation pressures in the system are controlled by manipulation of the choke on the annulus. This procedure can also be divided conveniently into 4 stages:

38. Stage1: circulation of influx to surface During this stage the well is circulated at a constant rate, with the original mud. Since the original mud weight is being circulated the standpipe pressure will equal Pdp + Pc1 throughout this phase of the operation. If the influx is gas then Pann will increase significantly. If the influx is not gas the annulus pressure will remain fairly static. � Stage 2: discharging the influx As the influx is discharged, the choke will be progressively opened. When all the influx has been circulated out Pann should reduce until it is equal to the original shut-in drillpipe pressure Pdp.

39. Stage 3: filling the drillstring with heavy mud At the beginning of the second circulation, the stand pipe pressure will still be Pdp + Pc1, but will be steadily reduced by adjusting the choke so that by the end of phase III the stand pipe pressure will be equal to Pc2. Stage 4: filling the annulus with heavy mud In this phase Pann will still be equal to the original Pdp, but as the heavy mud enters the annulus Pann will reduce. By the time the heavy mud reaches surface Pann = 0 and the choke will be fully opened. �

41. A well is being drilled at a vertical depth of 10,000 ft while circulating a 9.6 lbm/gal mud at a rate of 8.5 bbl/min when the well begins to flow. Twenty barrels of mud are gained in the pit over a 3-minute period before the pump is stopped and the blowout preventers are closed. After the pressures stabilized, an initial dirllpipe pressure of 520 psig and an initial casing pressure of 720 psig are recorded. The annular capacity of the casing opposite the drillpipe is 12.9 ft/bbl. The annular capacity opposite the 900 ft of drill collars is 28.6 ft/bbl. Determine: Kill mud weight Height of the influx in the annulus Type of the influx

42. Solution: Weight of kill mud:

43. Since the volume of the kick is smaller than the volume of the annular capacity opposite the drill collars, the kick occupies the annular against the drill collars only and not in the annulus against the drillpipe. The height of the influx in the annulus against the collars: The pressure gradient of the influx: The kick fluid is gas