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Well Control Principles

Well Control Principles. Well Control Principles. Primary Well Control Secondary Well Control Tertiary Well Control Hydrostatic Pressure Formation Pressure Porosity And Permeability Kill Mud Density Indications of Increasing Formation Pressure. Well Control Principles.

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Well Control Principles

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  1. Well Control Principles

  2. Well Control Principles • Primary Well Control • Secondary Well Control • Tertiary Well Control • Hydrostatic Pressure • Formation Pressure • Porosity And Permeability • Kill Mud Density • Indications of Increasing Formation Pressure

  3. Well Control Principles • The function of Well Control can be subdivided into 3 main categories: • Primary Well Control: is the use of the fluid to prevent the influx of formation fluid into the well bore. • Secondary Well Control: is the use of the BOP to control the well if Primary WC can not be maintained. • Tertiary Well Control: squeeze back, cement ...

  4. The Well is Balanced: when Hydrostatic Pressure = Formation Pressure

  5. The Well is Under Balanced: when Hydrostatic Pressure < Formation Pressure

  6. The Well is Over Balanced: when Hydrostatic Pressure > Formation Pressure

  7. Hydrostatic Pressure Because the pressure is measured in psi and depth is measured in feet, it is convenient to convert Mud Weight from ppg to a pressure gradient in psi/ft. The conversion factor is 0.052 Fluid Density (ppg) x 0.052 = Pressure gradient (psi/ft) Hydrostatic Pressure is the pressure exerted by a column of fluid at rest, and is calculated by multiplying the gradient of the fluid by the True Vertical Depth at which the pressure is being measured: Fluid gradient (psi/ft) x TVD = Hyd. Pressure(psi)

  8. T V D You have to consider the vertical height or depth of the fluid column, the shape of the hole doesn’t matter.

  9. Normal Formation Pressure Normal formation pressure is equal to the hydrostatic pressure of the water occupying the pore spaces from the surface to the subsurface formation. Native fluid is mainly dependent on its salinity and is often considered to be: 0.465 psi/ft

  10. Abnormal Formation Pressure Abnormal formation pressures are any formation pressures that are greater than the hydrostatic pressure of the water occupying the pore spaces. Commonly caused by the under-compaction of shale’s, clay-stone or faulting...

  11. Subnormal Pressure: is defined as any formation pressure that is less than “normal” pressure. It can be due to reservoir depletion,fault … Transition Zone: is the formation in which the pressure gradient begins to change from a normal gradient to a subnormal gradient or, more usually, to an abnormal gradient.

  12. UNDERCOMPACTED SHALES / SAND. UNCONSOLIDATED SHALE-DENSITY INCREASES WITH DEPTH - WATER ESCAPES SAND WITH COMMUNICATION TO SURFACE SHALE-DENSITY DECREASES WITH DEPTH-WATER ENCLOSED ENCLOSED SAND LENS WITH FORMATION FLUID

  13. GAS CAP NORMAL FORMATION PRESSURE ABOVE CAP ROCK =0.465 PSI/FT Ph Pabnormal = Pf-Pg Pf Pg GAS PRESSURE GRADIENT = 0.1 PSI/FT COMMUNICATION BETWEEN FLUID AND GAS

  14. SURCHARGED FORMATIONS

  15. NATURALLYSURCHARGED FORMATIONS FAULT ZONE Pf Pf

  16. ARTESIAN WELL NORMAL FORMATION PRESSURE AT THE WELL UNTILL BELOW THE CAP ROCK LAKE HYDROSTATIC PRESSURE FROM FORMATION WATER COLUMN POROUS SANDSTONE BELOW CAP ROCK

  17. SURFACE EROSION ENCLOSED FORMATION LEVEL CHANGE H1 H3 Pf H2 Pf Pf

  18. Porosity & Permeability The essential properties of reservoir rocks are: - Their porosity and permeability. Theporosity provides the storage space for fluids and gases and is the ratio of the pore spaces in the rock to the bulk volume of the rock. This is expressed as a percentage. Reservoir rocks commonly have porosity’s ranging from 5% to 30%. Formation permeability is a measure of how easy the fluid will flow through the rock. Permeability is expressed in Darcys, from a few milliDarcys to several Darcys. These properties will determine how much and how quick a kick will enter into the well. Kicks will enter a wellbore faster from rocks having high permeability.

  19. Tiny openings in rock are pores Porosity Pores are connected for the Permeability

  20. Formation Pressure When the well is shut in, Formation Pressure can be found with the following formula: SIDPP + Hydrostatic pressure = Formation Pressure SICP + Influx Hyd + Mud Hyd = Formation Pressure SICP + Mud Hydrostatic + Influx Hydrostatic = SIDPP + Mud Hydrostatic = Formation Pressure

  21. KICK INDICATORS

  22. POSITIVE KICK SIGNS Positive Indications of a kick: - Flow from Well (pumps off) - Increase in Flow from Well (pumps on) - Pit Volume Gain

  23. KICKS WHILE TRIPPING Incorrect Fill or Return Volumes - Swabbing - Surging If any deviation, the FIRST action will be to install a fully open safety valve and make a Flow-Check. Remember: It is possible that the well will not flow even if an influx has been swabbed in.

  24. KICKS WHILE DRILLING Early Warning Signs That the well MIGHTbe going under-balanced

  25. Indications of Increasing Formation Pressure • Increase in Drilling Rate • Change in D - Exponent • Change in Cutting size and shape • Increase in Torque and Drag • Chloride Trends • Decrease in Shale Density • Temperature Measurements • Gas Cut Mud • Connection Gas

  26. ROP Depth Increase in Drilling Rate: While drilling normally pressured shale and assuming a fairly constant bit weight, RPM, and hydraulic program, a normal decrease in penetration rate can be expected. When abnormal pressure is encountered, differential pressure and shale density are decreased causing a gradual increase in penetration rate.

  27. Torque Depth Increase in Torque and Drag Increase in torque and drag often occurs when drilling under balanced through some shale intervals. There is a build up of cuttings in the annulus and this may be a sign that pore pressure is increasing.

  28. “d” Depth Change in “d” Exponent: “d” is an indication of drill ability and ROP, RPM, WOB, bit size are used to calculate its value. Trends of “d” normally increase with depth, but in transition zones, it may decrease with lower than expected value.

  29. Change in cutting size and shape Normally pressured shale: cuttings are small with rounded edges, generally flat. Abnormally pressured shale: cutting are long and splintery with angular edges. As differential between the pore pressure and bottom pressure is reduced, the cuttings have a tendency to “explode” of bottom.

  30. Chloride Depth Chloride Trends: The chloride content of the mud filtrate can be monitored both going into and coming out of the hole. A comparison of chloride trends can provide a warning or confirmation signal of increasing pore pressure.

  31. Shale Density Depth Decrease in Shale Density: Shale density normally increases with depth but decreases as abnormal pressure zones are drilled. When first deposited, shale has a high porosity. During normal compaction, a gradual reduction in porosity occurs with an increase of the overlaying sediments.

  32. Temp. Depth Temperature Measurements: The temperature gradient in abnormally pressured formations is generally higher than normal.

  33. Gas Cut Mud The presence of gas cut mud does not indicate that the well is kicking ( gas may have been entrained in the cutting ). However, the presence of gas cut mud must be treated as an early warning sign of a potential kick. - Gas cut mud only slightly reduces mud column pressure, when it is close to surface. - Drilled cuttings from which the gas comes may compensate for the decrease.

  34. Connection Gas Connection gas are detected at the surface as a distinct increase above the background gas, as bottom up is circulated after a connection. Connection gases may indicate a condition of near balance. If connection gas is present, limiting its volume by controlling the drilling rate should be considered.

  35. SYSTEM PRESSURE LOSSES

  36. Objectives • Identify the different pressures losses in the system • Identify which one influence bottom hole pressure • Convert this pressure to an equivalent mud weight

  37. 100 psi 0 psi 100 psi Mud System Pressure Losses • Pumping through a pipe with a mud pump at 80 spm, with gauges mounted on the discharge of the pump and at the end of the pipe. • The gauge on the pump reads 100 psi. • The gauge on the end of the pipe reads 0 psi. • It can be assumed from this information that the 100 psi drop in pressure through the pipe is the result of friction losses in the pipe as the fluid is pumped through it. 80 SPM

  38. 500 psi 400 psi 100 psi 400 psi 0 psi Mud System Pressure Losses 80 SPM

  39. Mud System Pressure Losses 1000 psi 900 psi 100 psi 80 SPM 400 psi 500 psi 500 psi 0 psi

  40. 2300 psi 2200 psi 100 psi 400 psi 1800 psi 500 psi 1300 psi 1300 psi Mud System Pressure Losses 80 SPM 0 psi

  41. Mud System Pressure Losses 2600 psi 2500 psi 0 psi 100 psi 80 SPM Annular Pressure Losses 400 psi 300 psi 2100 psi 500 psi 1600 psi 1300 psi 300 psi

  42. MUD WT = 10 ppg 10,000 ft TVD Mud System Pressure Losses APLEXAMPLE 0 psi 0 psi 0 psi • A well has been drilled to10,000 ft. • The mud weight is 10 ppg. • To find our Hydrostatic pressure we use the following formula; • Mud Wt x 0.052 x TVD 10 x 0.052 x 10,000 = 5,200psi. • The gauge on the drawing shows bottom hole hydrostatic pressure. 0 SPM 0 psi 0 psi 5200 psi

  43. 2600 psi 2500 psi 100 psi 0 psi MUD WT = 10 ppg 400 psi 10,000 ft TVD 300 psi 2100 psi 500 psi 1600 psi 1300 psi 5500 psi Mud System Pressure Losses APL EXAMPLE • If we now start to circulate at 80 spm through our system with the same pressure losses as before. • As you can see from this example the bottom hole pressure has increased by 300 psi. • This increase is due to the Annular Pressure Losses (APL) acting down on the bottom of the well and is usually called “Bottom Hole Circulating Pressure” (BHCP) 80 SPM

  44. The APL while circulating has the same effect on bottom hole pressure as increasing the mud weight. This theoretical increase in mud weight is called the Equivalent Circulating Density or Equivalent Mud Weight. It can be calculated by using the following formula: _____APL(psi) __ + Original Mud Weight TVD x 0.052 Equivalent Circulating Density

  45. Summary: • Annular Pressure Losses are the pressure losses caused by the flow of fluid up the annulus and are the only losses in the system that affect BHP. • Equivalent Circulating Density is the effective density at any depth created by the sum of the total hydrostatic plus the APL.

  46. 300 psi 600 psi 450 psi 800 psi 1200 psi Exercise - Pressure Gradient? - Hydrostatic Pressure? - Pump Pressure @ 40 spm? - A P L? - ECD at 40 SPM? 40 SPM MUD WT = 12 ppg MD = 9,550 ft TVD = 8,000 ft

  47. EFFECTS ON PRESSURES

  48. MUD WEIGHT CHANGE 2600 psi • A well is being drilled using 10 ppg mud. At 80 spm the total circulating system pressure losses are 2600 psi. • It is decided to increase the mud weight to 11 ppg. 80 spm Mud wt 10 ppg

  49. MUD WEIGHT CHANGE 2860 psi It is a good drilling practice to calculate the new circulating pressure before changing the mud weight. The way we calculate this change in pressure is to use the following formula; New Mud ppg x Old psi. Old Mud ppg 11 ppg x 2600 = 2860psi 10 ppg The new pump pressure would be approximately 2860 psi. 80 spm Mud wt 11 ppg

  50. Final Circulating Pressure • The formula that was just used to calculate the pressure change due to a change in mud weight, is also the formula used to calculate the Final Circulating Pressure. Kill Mud wt x Slow circulating rate press . Old Mud wt

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