Well control school well control manual i

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Well control school well control manual i

  1. 1. TABLE OF CONTENTS 1 PRESSURE BASICS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 2 KICK FUNDAMENTALS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1 3 DETECTION OF KICKS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1 4 KICK THEORY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 5 PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-1 6 WELL CONTROL BASICS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 7 WELL CONTROL METHODS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-1 8 COMPLICATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-1 9 FLUIDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9-1 10 SURFACE EQUIPMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-1 11 SUBSEA WELL CONTROL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11-1 12 SPECIAL TOPICS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12-1 13 REMEDIAL OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13-1 14 SUBSURFACE EQUIPMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14-1 15 COILED TUBING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15-1 16 SNUBBING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16-1 17 WIRELINE UNITS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17-1 18 MMS REGULATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18-1 19 SIMULATOR EXERCISES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19-1 GLOSSARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . G-1 INDEX . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1 ILLUSTRATION/PHOTO CREDITS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-7 WCS–Well Control School expresses thanks to all companies and individuals contributing to this text. Material contained here, by general consensus of those involved in the course development, is based on the best sources of knowledge available to the authors. WCS does not warrant or guarantee any procedures or information presented in this text. By the very nature of the oil industry, procedures, equipment, standards and practices vary widely. It is not the intent of WCS to endorse policies and procedures, but rather to communicate to readers generally accepted practices. © NOVEMBER 2002 WCS–WELL CONTROL SCHOOL ALL RIGHTS RESERVED PHONE: 5O4•361•8282 FAX: 5O4•361•5551 EMAIL: staff@wellcontrol.com WEBSITE: www.wellcontrol.com WELL CONTROL SCHOOL • 2600 MOSS LANE • HARVEY, LOUISIANA 7OO58
  2. 2. INTRODUCTION T his manual was compiled for use as the primary text for blowout prevention courses conducted around the world by WCS – Well Control School. Its scope is broad, and recommendations or suggestions of good practices are designed to meet or exceed the training requirements established by the U.S. Minerals Management Service (MMS) and the International Association of Drilling Contractors (IADC), as well as to address the knowledge base necessary to competently perform many of the skills required by the International Well Control Forum (IWCF). Additionally, WCS hopes that field personnel will find the book a useful and practical onsite reference, covering a wide range of accepted well control practices. Every effort has been made to use standard or universal terminology. Still, common usage varies among different segments of the industry. The drilling hand’s drillpipe becomes the workover hand’s tubing. Terms remain consistent throughout chapters and meanings should be apparent within the context of the topic discussions. The chapters of this book are arranged in the order of presentation for our MMS certified Drilling Well Control course, however each section of the manual stands alone. Candidates enrolled in courses other than drilling, for instance Workover/Well Servicing, may find themselves directed to sections of the text that appear to be out of sequence. This is unavoidable due to the comprehensive nature of the manual. Numerical values and units of measure appear in the English system. Metric equivalents are enclosed in parentheses following the English value. Tables used for metric conversions in the text appear in Chapter Eighteen. The mathematical formulas in Chapter Eighteen are presented lineally, that is, in the order in which values and operatives are entered into a hand-held calculator. In some cases this form of presentation may differ from accepted written mathematical formats. Our goal is for the learner to arrive at the correct answer in the simplest and most direct way regardless of his or her educational background. A glossary, portions of the MMS publication CFR 30 which apply to well control and training regulations and special topics are also included. These chapters are intended to provide technical reference and useful information for industry workers across disciplines. Although the manual is not intended to be a work of science, WCS is indebted to many engineers and scientists throughout the industry for technical advice and assistance. It is impossible to acknowledge on an individual basis all the companies and personnel who contributed materials to this compilation. It is our sincere hope that their thanks will come by way of the knowledge that in some way we have all helped to avert that greatest of all oilfield tragedies, the blowout. ö
  3. 3. CHAPTER 1
  4. 4. Remember to think downhole. The concepts provided in this section cover the foundations for good well control. PRESSURE BASICS U nderstanding pressure and pressure relationships is important if we are to understand well control. By defi- nition, pressure is the force that is exerted or placed on a unit of area, such as pounds per square inch (psi). The pressures that we deal with daily in the oil industry include fluid, formation, friction and mechanical. When certain pressure limits are exceeded, disastrous consequences can result, including blowouts and/or the loss of life. FLUID PRESSURE What is a fluid? A fluid is simply some- thing that is not solid and can flow. Water and oil are obviously fluids. Gas is also a fluid. 1-1
  5. 5. CHAPTER 1 1-2 Under extreme temperature and/or pressure almost anything will become fluid. Under some conditions salt or rock become fluid. For our purposes, fluids that we will consider are those normally associated with the oil industry, such as oil, gas, water, muds, packer fluids, brines, completion fluids, etc. Fluids exert pressure. This pressure is the result of the density of the fluid and the height of the fluid column. Density is usually mea- sured in pounds per gallon (ppg) or kilograms per cubic meter (kg/m³). A heavy fluid exerts more pressure because its density is greater. The force or pressure that a fluid exerts at any given point is usually measured in pounds per square inch (psi) or in the metric system, bar. To find out how much pressure a fluid of a given density exerts for each unit of length, we use a pressure gradient. A pressure gradient is normally expressed as the force which the fluid exerts per foot (meter) of depth; it is measured in pounds per square inch per foot (psi/ft) or bars per meter (bar/m). To get the pressure gradient we must convert the fluid’s density in pounds per gal- lon to pounds per square inch per foot (or kilograms per cubic meter, kg/m³ to bar/m). DENSITY CONVERSION FACTOR The conversion factor used to convert density to pressure gradient in the English system is 0.052. In the metric system, it is 0.0000981. Remember that the definition of pressure gradient is the pressure increase per unit of depth due to its density. For our text, we will use pounds per gallon (ppg) to measure density and feet (ft) for depth measurements in the English system and kilograms per cubic meter (kg/m³) to measure density and meters (m) for depth measurements in the metric system. The way 0.052 is derived is by using a one- foot cube (one foot wide by one foot long by one foot high). It takes about 7.48 gallons to fill the cube with fluid. If the fluid weighs one pound per gallon, and you have 7.48 gallons, then the total weight of the cube is 7.48 pounds, or 7.48 pounds per cubic foot. The weight of one of these square inches, one foot in height, can be found by dividing the total weight of the cube by 144: 7.48 ÷ 144 = 0.051944 The conversion factor 0.052 is commonly used for oilfield calculations. Pressure Fluid Pressure (Force) Pressure (Force) What is pressure? Pressure: 1: the force per unit area that is exerted on a surface. 2: the force that a fluid exerts when it is in some way confined within a vessel.
  6. 6. PRESSURE BASICS 1-3 PRESSURE GRADIENT To find the pressure gradient of a fluid, multiply the density of the fluid by 0.052; or in metrics, by 0.0000981. Pressure Gradient = Fluid Density × Conversion Factor So the pressure gradient of a 10.3 ppg (1234 kg/m³) fluid can be found by multiplying the fluid weight by the conversion factor. Pressure Gradientpsi/ft = Fluid Densityppg × Conversion Factor = 10.3 ppg × 0.052 = 0.5356 psi/ft Pressure Gradientbar/m = Fluid Densitykg/m³ × Conversion Factor = 1234 kg/m³ × 0.0000981 = 0.1211 bar/m EXAMPLE 1 What is the pressure gradient of a fluid with a density of 12.3 ppg (1474 kg/m³)? Pressure Gradientpsi/ft = Fluid Densityppg × Conversion Factor = 12.3 X 0.052 = 0.6396 psi/ft Pressure Gradientbar/m = Fluid Densitykg/m³ × Conversion Factor = 1474 X 0.0000981 = 0.1446 bar/m PROBLEM 1A What is the pressure gradient of a fluid that weighs 9.5 ppg (1138 kg/m³)? Pressure Gradientpsi/ft = Fluid Densityppg X Conversion Factor Pressure Gradientbar/m = Fluid Densitykg/m³ X Conversion Factor PROBLEM 1B What is the pressure gradient of fresh water which weighs 8.33 ppg (998 kg/m³)? If a fluid weighs one pound per gallon, the weight of one square inch in a one foot length is 0.052 lbs. 1' 1' 1' To calculate pressure at the bottom of a well use true vertical depth.
  7. 7. 1-4 TVD VS. MD Once we know how to find pressure exerted per foot, we can calculate the hydrostatic pressure at a given depth. All we have to do is multiply the pressure gradient by the number of feet to that vertical depth. Here we have to learn the distinction between measured depth (MD) and true vertical depth (TVD). In the illustration below you can see that the depth straight down (the way that gravity pulls) for both wells is 10,000 ft (3048 m). Well A has a measured depth of 10,000 ft (3048 m), and a true vertical depth of 10,000 ft (3048 m). Since gravity pulls straight down, along a true vertical (straight down) path, to calculate the pressure at the bottom of the hole we use the 10,000 ft (3048 m) depth. Well B has a measured depth of 11,650 ft (3550.92 m), and its true vertical depth is 10,000 ft (3048 m). Gravity still pulls straight down, not along the path of the well. You would have a vertical depth of 10,000 ft (3048 m) from the surface straight down to where the well ended. Therefore, to calculate the pressure at the bottom of Well B, you have to use the true vertical depth of 10,000 ft (3048 m). The illustration on page 1-5 offers another way of looking at the difference between true vertical depth and measured depth. In this illustration, we have a picture of square blocks, 15 by 10. Count how many blocks the well covers. This represents the measured depth of the well. Now, count the blocks from the bottom of the well, straight up to surface. The numbers of these blocks represent true vertical depth. HYDROSTATIC PRESSURE Hydrostatic pressure is the total fluid pressure created by the weight of a column of fluid, acting on any given point in a well. Hydro means water, or fluid, that exerts pressure like water, and static means not moving. So hydrostatic pressure is the pressure created by the density and height of a stationary (not moving) column of fluid. We already know how to calculate a pressure gradient from the fluid’s weight. Hydrostatic pressure can be calculated from a pressure gradient to a given point: Hydrostatic Pressure = Pressure Gradient × DepthTVD Or, it may be calculated by: Hydrostatic Pressure = Fluid Density × Conversion Factor × DepthTVD MD and TVD 10,000' 10.0PPGMUD Well A Well B 10.0PPGMUD11,650'MD True vertical depth vs. measured depth. Hydrostatic pressure: force exerted by a body of fluid at rest; increases directly with the weight and length of the fluid column. CHAPTER 1
  8. 8. 1-5 EXAMPLE 2 What is the hydrostatic pressure at the bottom of a well which has a fluid density of 9.2 ppg (1102 kg/m³), a MD of 6,750’ (2057.4 m) and a TVD of 6,130’ (1868.42 m)? Remember, the formula for calculating hydrostatic pressure is: Hydrostatic Pressurepsi = Fluid Densityppg × Conversion Factor × Depthft, TVD = 9.2 × 0.052 × 6,130 = 2,933 psi Hydrostatic Pressurebar = Fluid Densitykg/m³ × Conversion Factor × Depthm, TVD = 1102 × 0.0000981 × 1868.42 = 201.99 bar PROBLEM 2A Find the hydrostatic pressure at the bottom of a well with a 9.7 ppg (1162 kg/m³) fluid in it and a MD of 5,570’ (1697.74 m) and TVD of 5,420’ (1651.02 m). Hydrostatic Pressurepsi = Fluid Densityppg × 0.052 × Depthft, TVD Hydrostatic Pressurebar = Fluid Densitykg/m³ × 0.0000981 × Depthm, TVD PROBLEM 2B Find the hydrostatic pressure at 4,300’ (1310.64 m) TVD, of a well with fluid density of 16.7 ppg (2001 kg/m³). The well has a MD of 14,980’ (4565.9 m) and a TVD of 13,700’ (4175.76 m). The above equations for fluid gradient and hydrostatic pressure are basic to understanding the fundamentals of pressure in wells. To prevent the well from flowing, fluid pressure in the well must at least equal the formation pressure. Although a gauge placed at the bottom of a fluid column would read the hydrostatic pressure of that column, it also would read the atmospheric pressure exerted on the column. This pressure varies with weather conditions and elevation and is normally considered 14.7 psi or 15 psi (approximately one bar) at sea level. If a gauge has a unit notation of psig, it includes the atmospheric column above it. If gauge reads in psig, it has been calibrated to subtract the atmospheric column above it. MD TVD True vertical depth vs. measured depth. Atmospheric pressure at sea level is about 15 psi; the metric equivalent is approximately one bar. PRESSURE BASICS GAUGE/ATMOSPHERIC PRESSURE
  9. 9. U-TUBE It is often helpful to visualize the well as a U-tube (see above). One column of the tube represents the annulus and the other column represents the pipe in the well. The bottom of the U-tube represents the bottom of the well. In most cases, there are fluids creating hydrostatic pressures in both the pipe and annulus. Atmospheric pressure can be omitted, since it works the same on both columns. If there were 10 ppg (1198 kg/m³) fluid in both the pipe and annulus, hydrostatic pressures would be equal and the fluid would be static on both sides of the tube. However, what will happen if fluid in the annulus is heavier than the fluid in the string? The heavier fluid in the annulus exerting more pressure downward will flow into the string, displacing some of the lighter fluid out of the string, causing a flow at surface. The fluid level will fall in the annulus, equalizing pressures. When there is a difference in the hydro- static pressures, the fluid will try to reach balance point. This is called U-tubing, and it explains why there is often flow from the pipe when making connections. This is often evident when drilling fast because the effective density in the annulus is increased by cuttings. Another example of U-tubing is when a slug is pumped. The heavier slug is designed to allow tubing to pull dry by falling to a level below the average length of stand pulled. The depth where the slug will fall and the amount of fluid that U-tubes from the well can be calculated using the following equations: Gain In Pits = (Slug Weight – Annulus Weight) × Volume of Slug ÷ Annulus Weight Distance of Drop = Gain in Pits ÷ Pipe Capacity EXAMPLE 3 What will be the gain in the pits, and how far will the slug fall if the mud weight is 10 ppg (1198 kg/m³), the pipe’s capacity is 0.0178 bbl/ft (0.00929 m³/m)? The volume of the slug is 30 bbls (4.77 m³) and weighs 11 ppg (1318 kg/m³). Annulus U–Tube Analogy Annulus String String Higher density fluid U–Tubing U–Tubing U-tubing: the tendency of liquids to seek a pressure balance point in an open well. CHAPTER 1 1-6
  10. 10. Gain In Pitsbbls = (Slug Weightppg – Annulus Weightppg) × Volume of Slugbbls ÷ Annulus Weightppg = (11 – 10) × 30 ÷ 10 = 1 × 30 ÷ 10 = 3 bbls Distance of Dropft = Gain In Pitsbbls ÷ Pipe Capacitybbls/ft = 3 ÷ 0.0178 = 168.5 ft Gain In Pitsm³ = (Slug Weightkg/m³ – Annulus Weightkg/m³) × Volume of Slugm³ ÷ Annulus Weightkg/m³ = (1318 - 1198) × 4.77 ÷ 1198 = 120 X 4.77 ÷ 0.00929 ÷ 1198 = 0.478 m³ Distance of Dropm = Gain In Pitsm³ ÷ Pipe Capacitym³/m = 0.478 ÷ 0.00929 = 51.45 m PROBLEM 3 What will be the gain in the pits, and how far will the slug fall if the mud weight is 11.6 ppg (1390 kg/m³), the pipe’s capacity is 0.00579 bbl/ft (0.00302 m³/m)? The volume of the slug is 15 bbls (2.39 m³) and weighs 12.4 ppg (1486 kg/m³). Gain In Pitsbbls = (Slug Weightppg – Annulus Weightppg) × Volume of Slugbbls ÷ Annulus Weightppg Distance of Dropft = Gain In Pitsbbls ÷ Pipe Capacitybbls/ft Gain In Pitsm³ = (Slug Weightkg/m³ – Annulus Weightkg/m³) × Volume of Slugm³ ÷ Annulus Weightkg/m³ Distance of Dropm = Gain In Pitsm³ ÷ Pipe Capacitym³/m Two important characteristics of reservoir rocks are porosity, tiny openings in rock (far left) and permeability, the connection of these holes which allows fluids to move (near left). Porosity is the measurement of void space within a rock, expressed as a percentage. PRESSURE BASICS 1-7
  11. 11. 1-8 FORMATION CHARACTERISTICS Porosity and permeability, along with pres- sure differences, must be considered if we are to understand well control. A reservoir rock looks solid to the naked eye. A microscopic examina- tion reveals the existence of tiny openings in the rock. These openings are called pores. The porosity of the rock is expressed as a percentage. It is the ratio of void (pore) space to solid volume. Another characteristic of a reservoir rock is that it must be permeable. That is, the pores of the rock must be connected so hydro- carbons can move between them. Otherwise the hydrocarbons remain locked in place and cannot flow into a well. FORMATION PRESSURE Formation pressure is the pressure within the pore spaces of the formation rock. This pressure can be affected by the weight of the overburden (rock layers) above the formation, which exerts pressure on both the grains and pore fluids. Grains are solid or rock material, and pores are spaces between grains. If pore fluids are free to move, or escape, the grains lose some of their support and move closer together. This process is called compaction. Normally pressured formations exert a pressure equal to a vertical column of native fluid from the formation to surface. The pressure gradient of the native fluid usually ranges from 0.433 psi/ft (0.0979 bar/m) to 0.465 psi/ft (0.1052 bar/m), and varies depending on the geologic region. Formations pressured in this range are designated normal, depending on the area. For simplicity, this text will designate a gradient of 0.465 psi/ft (0.1052 bar/m) as normal. In normally pressured formations most of the overburden weight is supported by the grains that make up the rock. When the overburden increases with depth, pore fluids are free to move and the amount of pore space is reduced due to compaction. Abnormally pressured formations exert pressure greater than the hydrostatic pressure (or pressure gradient) of the contained formation fluid. When abnormally pressured formations develop, during the compaction phase, the pore fluid movement is restricted or stopped. The pore fluid pressure increases, generally exceeding 0.465 psi/ft (0.1052 bar/m). The result causes the increasing overburden weight to be partially supported by pore fluid rather than by the rock grains. Such formations may require working fluid densities up to, and sometimes greater than, 20 ppg (2397 kg/m³) to control them. Abnormal pressures may be caused in other ways, including the presence of faults, salt domes, uplifting, and differences in elevation of underground formations. In many regions, hundreds of feet of pre-existing rock layers (overburden) have been stripped off by erosion. At the new, shallower depths this loss from erosion can cause the pressure to become abnormal, above 0.465 psi/ft (0.1052 bar/m), or 8.94 ppg (1072 kg/m³). When a normally pressured formation is raised toward the surface while prevented from losing pore fluid in the process, it will change from normal pressure (at a greater depth) to abnormal pressure (at a shallower depth). When this happens, and then you drill into the formation, mud weights of up to 20 ppg (2397 kg/m³) may be required for control. This process accounts for many of the shallow, abnormally pressured zones in the world. In areas where faulting is present, salt layers or domes are predicted, or excessive geothermal gradients are known, drilling operations may encounter abnormal pressure. An abnormally pressured formation can often be predicted using well history, surface geology, downhole logs or geophysical surveys. Subnormally pressured formations have pressure gradients lower than fresh water, or less than 0.433 psi/ft (0.0979 bar/m). Naturally occurring subnormal pressure can be developed when the overburden has been stripped away, leaving the formation exposed at the surface. Fracture pressure is the amount of pressure it takes to permanently deform the rock structure of a formation. CHAPTER 1
  12. 12. 1-9 Depletion of original pore fluids through evaporation, capillary action and dilution produces hydrostatic gradients below 0.433 psi/ft (0.0979 bar/m). Subnormal pressures may also be induced through depletion of formation fluids. FRACTURE PRESSURE Fracture pressure is the amount of pressure it takes to permanently deform (fail or split) the rock structure of a formation. Overcoming formation pressure is usually not sufficient to cause fracturing. If pore fluid is free to move, a slow rate of entry into the formation will not cause fractures. If pore fluid cannot move out of the way, fracturing and permanent deformation of the formation can occur. Fracture pressure can be expressed as a gradient (psi/ft), a fluid density equivalent (ppg), or by calculated total pressure at the formation (psi). Fracture gradients normally increase with depth due to increasing overburden pressure. Deep, highly compacted formations can require very high fracture pressures to overcome the existing formation pressure and resisting rock structure. Loosely compacted formations, such as those found offshore in deep water, can fracture at low gradients. Fracture pressures at any given depth can vary widely because of the geology of the area. FORMATION INTEGRITY TESTS An accurate evaluation of a casing cement job as well as of the formation is extremely important during the drilling of a well and for subsequent work. The information resulting from Formation Integrity Tests (FIT) is used throughout the life of the well and also for nearby wells. Casing depths, well control options, formation fracture pressures and limiting fluid weights may be based on this information. To determine the strength and integrity of a formation, a Leak Off Test (LOT) or a Formation Integrity Test (FIT) may be performed. Whatever the name, this test is first: a method of checking the cement seal between casing and the formation, and second: determining the pressure and/or fluid weight the test zone below the casing can sustain. Whichever test is performed, some general points should be observed. The fluid in the well should be circulated clean to ensure it is of a known and consistent density. If mud is used for the test, it should be properly conditioned and gel strengths minimized. The pump used should be a high-pressure, low-volume test or cementing pump. Rig pumps can be used if the rig has electric drives on the mud pumps, and they can be slowly rolled over. If the rig pump must be used and the pump cannot be easily controlled at low rates, then the leak-off technique must be modified. It is a good idea to make a graph of the pressure versus time or volume for all leak-off tests as shown in the illustrations on the next page. Integrity Test Casing Cement Cement Test Formation The information resulting from formation integrity tests is used throughout the life of a well. PRESSURE BASICS
  13. 13. LEAK-OFF TEST (LOT) A leak-off test is performed to estimate the maximum pressure or mud weight (fluid density) that the test point can withstand before formation breakdown or fracture occurs. LEAK-OFF TECHNIQUE 1 The well is pressured in increments of 100 psi (6.9 bar) or fluid is pumped into the well in approximately one-half barrel (0.079 m³) increments of volume. After each increase in pressure, the pump is stopped and the pressure is held for about 5 minutes. If the pressure holds, the next increment is tested. If the pressure does not hold, the well is pressured again. The test is completed when the pressure will not hold after several attempts, or if the well will not pressure up any further. LEAK-OFF TECHNIQUE 2 The choke is opened on the manifold and the pump is started at an idle. The choke is closed to increase the pressure in increments of 100 psi (6.9 bar). At each interval of pressure, the fluid volume in the pits is watched until it is certain that no fluid is being lost to the formation. The test is complete at the pressure where fluid is continuously being lost to the formation. Some fluid will be lost at each pressure increase. If this technique is to be used, a small tank should be used so large amounts of fluid are not forced into the formation. Circulating frictional pressure losses which are present in this technique add more unseen pressure on the formation tested, which will give slightly different results (lower fracture pressures) than technique number 1. LIMITED INTEGRITY TEST A limited formation integrity test (limited FIT), also called a jug test, is performed when it is not acceptable to cause the formation to fracture. It may also be used on wells drilled in developed fields. In such cases, operators have good data concerning formation strength and do not expect to approach fracture pressures. In the limited formation integrity test, the wellbore is pressured to a predetermined pressure or fluid weight. If the formation can withstand the applied pressure, the test is called good. Both tests, Limited FIT and LOT, have their good and bad points. In the Limited FIT, the formation is not broken down, however, the maximum pressure before the formation starts to accept fluid is not determined. In the LOT, the pressure where the formation starts accepting fluid is determined, but there is a possibility of fracturing the formation. Increments of Volume Generally about 20 Gal (75 Liters) Cumulative Volume Pumped Increments of Pressure PRESSURE SURFACEPRESSURE(PSI) PRESSURE TIME PUMP STROKES TIME Increments of Pressure Weight Stop Here Stop Here Pressure ~vs~ Time or Volume for Leak-off Tests Slack in System Shut-In Time Pit Limit Shut Pumps Down Instantaneous Shut-in Pressure End of Test A B D C E Pressure vs time or volume for leak-off tests Jug test: limited formation integrity test, often performed when risk of formation damage is high. CHAPTER 1 1-10
  14. 14. Estimated Integrity Fluid Densityppg = (Test Pressurepsi ÷ 0.052 ÷ Depth of Testft, TVD) + Test Fluid Densityppg Est. Integrity Fluid Densitykg/m³ = (Test Pressurebar ÷ 0.0000981 ÷ Depth of Testm, TVD) + Test Fluid Densitykg/m³ Test fluid density is seldom used throughout the entire well. If the fluid density changes, then the surface pressure that may damage the formation should be re-calculated. To find the new estimated integrity pressure with a different density fluid: Est. Integrity Pressurepsi = (Est. Integrity Fluid Densityppg – Present Fluid Densityppg) × Depth of Testft, TVD × 0.052 Est. Integrity Pressurebar = (Est. Int. Fluid Densitykg/m³ – Present Fluid Densitykg/m³) × Depth of Testm, TVD × 0.0000981 EXAMPLE 4 Solve the following equations for the formation's estimated integrity fluid density (maximum fluid weight without causing formation damage), and the estimated integrity pressure that may cause damage with a different fluid density using the following data. Note: When doing the following exercises, decimals in the answers should not be rounded up. Safety against formation fracture lies in the lower values. The well has a TD of 11,226' (3421.68 m) and a Casing Shoe set at 5,821' (1774.24 m) TVD. The Leak Off Test Pressure was 1,250 psi (86.19 bar), with a Leak Off Test Fluid of 9.6 ppg (1150 kg/m³). The Present Fluid Wt. is 10.1 ppg (1210 kg/m³). First find the Estimated Integrity Fluid Density: Estimated Integrity Fluid Densityppg = (Test Pressurepsi ÷ 0.052 ÷ Depth of Testft, TVD) + Test Fluid Densityppg = (1,250 ÷ 0.052 ÷ 5,821) + 9.6 = 4.1 + 9.6 = 13.7 ppg. Est. Integrity Fluid Densitykg/m³ = (Test Pressurebar ÷ 0.0000981 ÷ Depth of Testm, TVD) + Test Fluid Densitykg/m³ = (86.19 ÷ 0.0000981 ÷ 1774.24) + 1150 = 495 + 1150 = 1645 kg/m³ FLUID DENSITY/PRESSURE The total pressure applied causes leak off or formation damage. This is usually a combination of the hydrostatic pressure of a fluid plus an additional pressure, such as pump pressure on a leak off test. The applied pressure raises the total pressure against the formation. From test data, calculations estimate the integrity fluid density. This is the total pressure, represented as fluid density, above which leak off or formation damage may occur. This may also be called the maximum allowable mud weight or frac mud weight. The calculations to find the estimated integrity fluid density follow. When computing formation integrity values decimals in the results are not rounded up. PRESSURE BASICS 1-11
  15. 15. 1-12 In formation integrity calculations, it is more conservative to not round up. So, in the previous calculations 4.1 ppg was used instead of 4.13 ppg (495 kg/m³ instead of 495.19 kg/m³). In this example, the present mud weight is higher than the test mud weight so we must solve for the present estimated integrity pressure. Estimated Integrity Pressurepsi = (Est. Integrity Fluid Densityppg – Present Fluid Densityppg) × Depth of Testft, TVD × 0.052 = (13.7 – 10.1) × 5,821 × 0.052 = 1,089 psi Estimated Integrity Pressurebar = (Est. Int. Fluid Densitykg/m³ – Pres. Fluid Densitykg/m³) × Depth of Testm, TVD × 0.0000981 = (1645 – 1210) × 1774.24 × 0.0000981 = 75.71 bar PROBLEM 4 What is the estimated integrity fluid density and estimated integrity pressure that may damage the formation for a well with an MD of 12,000’ (3657.6 m), TVD of 10,980’ (3346.7 m). The Casing Shoe is at 8,672’ (2643.23 m) TVD. The Leak Off Test Pressure was 1,575 psi (108.59 bar) with a Leak Off Test Fluid Density of 11.1 ppg (1330 kg/m³), and the Present Fluid Density is 11.6 ppg (1390 kg/m³). First, solve for the estimated integrity fluid density: Estimated Integrity Fluid Densityppg = (Test Pressurepsi ÷ 0.052 ÷ Depth of Testft, TVD) + Test Fluid Densityppg Estimated Integrity Fluid Densitykg/m³ = (Test Pressurebar ÷ 0.0000981 ÷ Depth of Testm, TVD) + Test Fluid Densitykg/m³ Second, solve for the present estimated integrity pressure: Estimated Integrity Pressurepsi = (Est. Integrity Fluid Densityppg – Present Fluid Densityppg) × Depth of Testft, TVD × 0.052 Estimated Integrity Pressurebar = (Est. Int. Fluid Densitykg/m³ – Pres. Fluid Densitykg/m³) × Depth of Testm, TVD × 0.0000981 Often a chart is generated to post on the rig floor showing incremental mud weight increases and the estimated integrity pressures with each. To do so, calculate the gain in hydrostatic pressure for an increment of 0.1 ppg (11.98 kg/m³). Hydrostatic Pressure = Fluid Weight Increase × Conversion Factor × DepthTVD The estimated integrity pressure that may be applied is reduced by the hydrostatic pressure increase gained by each increase in mud weight. A chart beginning with the present mud weight up to integrity fluid density versus integrity pressure can then easily be prepared. If fluid density is changed, surface pressure that may damage the formation must be recalculated. CHAPTER 1
  16. 16. 1-13 EXAMPLE 5 Prepare a chart of Estimated Integrity Pressure on surface for mud weights ranging from 10.1 to 11.1 ppg (1222 to 1330 kg/m³). The Casing Shoe depth is 5,821’ (1774.24 m) TVD and Estimated Integrity Pressure for present fluid weight 10.1 ppg (1210 kg/m³) is 1,250 psi (86.19 bar). First, find the increase in hydrostatic pressure for 0.1 ppg (11.98 kg/m³): Hydrostatic Pressurepsi = Fluid Wt. Inc.ppg × 0.052 × Depthft, TVD = 0.1 × 0.052 × 5,821 = 30 psi Hydrostatic Pressurebar = Fluid Wt. Inc.kg/m³ × 0.0000981 × Depthm, TVD = 11.98 × 0.0000981 × 1774.24 = 2.09 bar Based on the gain in hydrostatic pressure, subtract this value from the calculated Estimated Integrity for each corresponding increase in mud weight. PROBLEM 5 Prepare a chart of Estimated Integrity Pressure on surface for mud weights ranging from 11.7 to 12.6 ppg (1402 to 1510 kg/m³). The Casing Shoe depth is 8,672’ (2,643.23 m) TVD and the Estimated Integrity Pressure for present fluid weight 11.6 ppg (1390 kg/m³) is 1,352 psi (93.22 bar). Hydrostatic Pressurepsi = Fluid Wt. Inc.ppg × 0.052 × Depthft, TVD Hydrostatic Pressurebar = Fluid Wt. Inc.kg/m³ × 0.0000981 × Depthm, TVD Next, fill in chart at right. Alternate terms such as fracture mud weight, and either MASP (Maximum Allowable Surface Pressure) or MAASP (Maximum Allowable Annular Surface Pressure) are also used for estimated integrity fluid density and estimated integrity pressure. If such terms and information are used as limiting factors and without proper understanding of limiting pressures vs. maintaining control of the well, serious well control complications can result. If this information is used during a well kill operation you must also take kick position, distribution and density into account. Estimated Integrity Pressure on Surface Fluid Estimated Fluid Estimated Density Integrity Press. Density Integrity Press. (ppg) (psi) (kg/m3) (bar) Estimated Integrity Pressure on Surface Fluid Estimated Fluid Estimated Density Integrity Press. Density Integrity Press. (ppg) (psi) (kg/m3) (bar) 10.1 1250 1210 86.19 10.2 1220 1222 84.1 10.3 1190 1234 82.01 10.4 1160 1246 79.92 10.5 1130 1258 77.83 10.6 1100 1270 75.74 10.7 1070 1282 73.65 10.8 1040 1294 71.56 10.9 1010 1306 69.47 11.0 980 1318 67.38 11.1 950 1330 65.29 PRESSURE BASICS
  17. 17. EMW = (Pressure ÷ Conversion Factor ÷ Depth of InterestTVD) + Present Fluid Density EXAMPLE 6 What is the EMW for a zone with an MD depth of 3,120’ (950.97 m) and TVD of 3,000’ (914.4 m) when the well is shut in with 375 psi (25.86 bar) registering on the casing gauge? Present Fluid Density is 8.8 ppg (1055 kg/m³). EMWppg = (Pressurepsi ÷ 0.052 ÷ Depth of Interestft, TVD) + Present Fluid Densityppg = (375 ÷ 0.052 ÷ 3,000) + 8.8 = 2.4 + 8.8 = 11.2 ppg EMWkg/m³ = (Pressurebar ÷ 0.0000981 ÷ Depth of Int.m, TVD) + Present Fluid Densitykg/m³ = (25.86 ÷ 0.0000981 ÷ 914.4) + 1055 = 288 + 1055 = 1343 kg/m³ PROBLEM 6 What is the EMW for a zone with a MD of 7,320’ (2231.14 m) and TVD of 6,985’ (2129.03 m) if the estimated choke and friction pressures total 730 psi (50.33 bar)? The Present Fluid Density is 13.8 ppg (1654 kg/m³). EMWppg = (Pressurepsi ÷ 0.052 ÷ Depth of Interestft, TVD) + Present Fluid Densityppg EMWkg/m³ = (Pressurebar ÷ 0.0000981 ÷ Depth of Interestm, TVD) + Present Fluid Densitykg/m³ EQUIVALENT MUD WEIGHT From the previous discussions, it should be apparent that any applied pressure raises the total pressure at a given point. If the applied pressure is known, then it can be calculated to an equivalent weight. Alternatively, if a zone must be pressure tested to an equivalent weight, then calculations may be performed to determine the test pressure. The equivalent mud weight (EMW) is also the summation of all pressures (hydrostatic pressure, choke or back pressure, applied pressure, kick pressure, circulating pressure losses, etc.) at a given depth or zone and is expressed as a fluid density. If these pressures are known or can be estimated, the EMW can be calculated as follows: Frictional resistance: the opposition to flow created by a fluid when it flows through a line or other container. CHAPTER 1 1-14
  18. 18. To determine how much applied pressure is required to test to a pre-determined EMW at a given depth: Test Pressurepsi = (EMWppg – Present Fluid Densityppg) × 0.052 × Depth Testedft, TVD Test Pressurebar = (EMWkg/m³ – Present Fluid Densitykg/m³) × 0.0000981 × Depth Testedm, TVD EXAMPLE 7 How much test pressure should be used to test a formation with a MD of 5,890’ (1795.27 m) and a TVD of 5,745’ (1751.08 m) to an equivalent fluid density of 13.4 ppg (1606 kg/m³)? The Present Fluid Density is 9.1 ppg (1090 kg/m³). Test Pressurepsi = (EMWppg – Present Fluid Densityppg) × 0.052 × Depth Testedft, TVD = (13.4 – 9.1) × 0.052 × 5,745 = 4.3 × 0.052 × 5,745 = 1285 psi Test Pressurebar = (EMWkg/m³ – Present Fluid Densitykg/m³) × 0.0000981 × Depth Testedm, TVD = (1606 – 1090) × 0.0000981 × 1751.08 = 88.64 bar PROBLEM 7 How much test pressure should be used to test a formation with a MD of 7,590’ (2313.43 m) and a TVD of 7450’ (2270.76 m) to an equivalent fluid density of 14.3 ppg (1714 kg/m³)? The Present Fluid Density is 8.9 ppg (1067 kg/m³). Test Pressurepsi = (EMWppg – Present Fluid Densityppg) × 0.052 × Depth Testedft, TVD Test Pressurebar = (EMWkg/m³ – Present Fluid Densitykg/m³) × 0.0000981 × Depth Testedm, TVD Most pressure loss will occur circulating down the string and through restrictions such as jet nozzles. PRESSURE BASICS 1-15
  19. 19. 1-16 PRESSURE–LOSSES/CIRCULATING Friction is the resistance to movement. It takes force, or pressure, to overcome friction to get anything to move. Friction has to be overcome to lift pipe, move fluid, or even to walk. How much friction is present to overcome depends upon many factors. These include density or weight, type and roughness of the surfaces making contact, surface area, thermal and electrical properties of the surfaces and direction and velocity of the objects. The amount of force used to overcome friction is called frictional loss and can be measured in many ways. Torque, drag (amps, foot-pounds, horsepower) and force (psi or bar) to move fluid are a few. Thousands of psi (bar) of pressure can be lost to the well’s circulating system as fluid is pumped through surface lines, down the string, and up the annulus. The pressure on the pump is actually the amount of friction that must be overcome to move fluid throughout the wellbore at a given flow rate. Most of the pressure loss will occur when circulating down the string and through restrictions such as jet nozzles. Pressure losses also occur in other parts of the circulating system, such as when the choke is used to hold back pressure on the casing side during well killing operations. When fluid finally returns to the pits it is under atmospheric, or almost zero, pressure. When the well is being circulated, bottomhole pressure is increased by the amount of friction overcome in the annulus. When pumps are shut off, wellbore pressure is reduced because no frictional force is being overcome. Casing Bit 900 Flowline TANK 3000 2950 Standpipe Drill Pipe Pump 0 Circulating Pressure Bottomhole pressure: 1: pressure exerted by a column of fluid in the wellbore. 2: formation pressure at depth of interest. CHAPTER 1
  20. 20. 1-17 Since friction adds pressure to the wellbore, it increases the effective weight, or the equivalent circulating density (ECD). The total value is the equivalent of bottomhole pressure with the pump on. If pressure in a permeable formation is closely balanced by ECDs, a well could flow when the pump is turned off. Data obtained from logging while drilling tools (LWD) can be used to get an accurate reading of annular pressure, which may be used to determine ECD. BOTTOMHOLE PRESSURE Pressure is imposed on the walls of the hole. The hydrostatic of the fluid column accounts for most of the pressure, but pressure to move fluid up the annulus also acts on the walls. In larger diameters, this annular pressure is small, rarely exceeding 200 psi (13.79 bar). In smaller diameters it can be 400 psi (27.58 bar) or higher. Backpressure or pressure held on the choke also increases bottomhole pressure, which can be estimated by adding up all the known pressures acting in, or on, the annular (casing) side. Bottomhole pressure can be estimated during the following activities. WELL STATIC If no fluid is moving, the well is static. The bottomhole pressure (BHP) is equal to the hydrostatic pressure (HP) on the annular side. If shut in on a kick, bottomhole pressure is equal to the hydrostatic pressure in the annulus plus the casing (wellhead) pressure. NORMAL CIRCULATION During circulation, the bottomhole pressure is equal to the hydrostatic pressure on the annular side plus the annular pressure loss (APL). ROTATING HEAD During circulating with a rotating head the bottomhole pressure is equal to the hydrostatic pressure on the annular side, plus the annular pressure loss, plus the rotating head backpressure. CIRCULATING A KICK OUT Bottomhole pressure is equal to hydrostatic pressure on the annular side, plus annular pressure loss, plus choke (casing) pressure. (For subsea, add choke line pressure loss.) PUMP BHP = HP Well Static Well static Normal Circulation PUMP BHP = HP + APL Normal circulation Circulation with Rotating Head BHP = HP + APL + Rotating Head Back Pressure PUMP Rotation Head Circulation with rotating head Kick Circulation BHP = HP + APL + Choke Press PUMP BOP Stack Kick circulation Hydrostatic pressure is controlled by careful monitoring and control of fluid weight. PRESSURE BASICS
  21. 21. MOVING PIPE – SURGE/SWAB The total pressure acting on the wellbore is affected by pipe movement upwards or downwards. When tripping out swab pressure is created, reducing the pressure on the wellbore. Swabbing occurs because the fluid in the well does not drop as fast as the string is being pulled. This creates a suction force and reduces the pressure below the string. This force can be compared to a plunger in a syringe, with formation fluid being pulled into the wellbore. When lowering the string too fast, surge pressure is created because the fluid does not have a chance to get out of the way. Since liquids do not compress to any appreciable degree, pressure throughout the well can increase and cause leak-off or fracture. Both surge and swab pressures are affected by the rate of pipe movement, clearances between pipe and hole and fluid properties. While it is often impossible to avoid these pressures, they can be minimized by slowing the tripping speed. Calculations are available to estimate maximum trip speed and surge and swab pressures, but these calculations are outside the scope of this manual. TRIP/SAFETY MARGINS Unless there is an excess of fluid weight to compensate for swabbing, formation fluid can enter the well and a kick can occur. The trip margin is an estimated increase in fluid density prior to a trip to compensate for loss of circulation pressure (ECD). A safety margin also compensates for swabbing pressures as pipe is pulled from the well. Using fluid density adjustments for a trip or safety margin requires good judgement. Too large a margin can cause lost circulation. Too small a margin may allow the well to kick. The margin depends on hole size, condition, pipe pulling speed, fluid and formation properties. DIFFERENTIAL PRESSURE The difference between the formation pressure and bottomhole hydrostatic pressure is differential pressure. These are classified as overbalanced, underbalanced and balanced. OVERBALANCED Overbalanced means the hydrostatic pressure exerted on the bottom of the hole is greater than the formation pressure: HP > FP UNDERBALANCED Underbalanced means the hydrostatic pressure exerted on the bottom of the hole is less than the formation pressure: HP < FP Swab Fluid Properties Pipe Movement Sand Swab Pressure Swabbing occurs because the fluid in the well does not drop as fast as the string is being pulled. CHAPTER 1 1-18
  22. 22. BALANCED Balanced means the hydrostatic pressure exerted on the bottom of the hole is equal to the formation pressure: HP = FP Most wells are drilled, and worked, in bal- anced to overbalanced conditions. If circulating or drilling, friction and cuttings contribute to the effective pressure on bottom. SUMMARY There are two main opposing pressures in a well. These are the fluid column hydrostatic pressure and the formation pressure. If one pressure overcomes the other, then a kick or lost circulation may occur. Since hydrostatic pressure is a function of the density of the working fluid in the well, its value may be controlled. By making careful calculations and by manipulating the formula for hydrostatic pressure, it is possible to test cement jobs, to estimate formation integrity, to project maximum mud weights and to control kicking wells. Kicks and blowouts are prevented by peo- ple who are able to work quickly and decisively under stress. An important part of the train- ing required for blowout prevention is an understanding of pressure concepts and the ability to perform accurate calculations. t Overbalanced HP > FP Underbalanced HP < FP Balanced HP = FP Differential pressure is the difference between formation pressure and bottomhole hydrostatic pressure. Kicks are prevented by people able to work quickly and decisively under stress. PRESSURE BASICS 1-19
  23. 23. CHAPTER 2
  24. 24. An understanding of pressure indicators, warning signs and why kicks occur can significantly decrease chances of kicks. KICK FUNDAMENTALS A kick is the unwanted influx of formation fluids into the wellbore. The results of a kick include lost operation time, hazardous operation with high pressure and gas, and possible equipment losses (from stuck pipe to rig loss) during attempts to regain control of the well. If recognized and controlled in time, the kick can be handled and removed from the well safely. If the kick is allowed to continue, it may no longer be able to be controlled. This is said to be a blowout or uncontrolled kick. Since a kick may happen at any time, we must be able to recognize, identify and react to all kick warning signs. These signs indicate either that the conditions for a kick exist or that the well may be kicking. It makes sense that all possible means should be used to prevent kicks. 2-1
  25. 25. CHAPTER 2 2-2 PREDICTING FORMATION PRESSURE The best way to avoid a well kick is to have a fluid in the hole that is heavy enough to control formation pressures but light enough to avoid lost circulation. In many parts of the world, pressures and temperatures at any depth can be predicted with reasonable confidence. However, crews must be alert to unexpected changes in pressure regardless of how safe, or routine, the current operation may be. Pressure in a normally pressured formation is roughly equal to that exerted by a column of formation fluid extending from the formation to surface, or between 0.433 and 0.465 psi/ft (0.098 and 0.105 bar/m). In this manual, we use the term abnormal pressures to mean a gradient greater than 0.465 psi/ft (0.105 bar/m). Abnormal pressures are not uncommon in many parts of the world. For example, abnormally high pressures are common along the U.S. Gulf Coast, and abnormally low pressures are found in some areas in West Texas, the Rocky Mountains, and many Northeast states. Geological conditions directly affect the formation pressures. Wells drilled into subsurface traps or structures that contain oil and gas may encounter abnormally high pressure. While the driller, toolpusher and operator’s representative are not exploration geologists, they are expected to be alert. They must be aware that abnormal pressure can be encountered at any depth and time. A trained, experienced crew is prepared for the unexpected. Well pressures can be predicted from three sources of information. Historical, seismic and geologic data may be used prior to drilling. While the well is being drilled, changes in drilling parameters may indicate changes in pressure and formations. Log data obtained with logging tools while drilling is valuable. HISTORICAL DATA Historical information from offset wells in the area is one of the better methods for determining potential trouble. Mud records and drilling reports can give a good general indication of drilling conditions. These records, with the application of geological and seismic background data can provide significant information on potential problems. Wireline Drilling GeologyThree ways to predict formation pressure Drilling records from offset wells can help predict formation pressure.
  26. 26. KICK FUNDAMENTALS 2-3 SEISMIC INTERPRETATIONS The science of seismology involves creating sound waves that penetrate the subsurface rock layers. Sound waves are reflected back from each formation and recorded by instruments that measure the intensity and nature of the reflections. By interpreting measurements, exploration geologists are able to deduce the shape and extent of subsurface formations, especially using 3D computer enhanced seismic plots. With this information, drilling programs for predicting potentially pressured zones can be developed accurately and safely. GEOLOGICAL DATA The geologic preplanning of the well looks at the general geology of the area. Certain geological conditions cause abnormal pressures and hazardous drilling, and they need to be noted in the well planning. A few of the most common conditions associated with subsurface pressure changes are faults, anticlines, salts, massive shale, charged zones or depleted zones. FAULTS When the drillbit crosses a fault, a significant change in pressure gradients may exist, resulting in a kick or lost circulation. Faults are often crossed deliberately in order to find oil and gas accumulations. Directional and horizontal drilling often cross fractures and faults, and the chances of drilling into a kick or losing circulation are high. ANTICLINES Anticlines are geological structures which are domed upward. Rock layers that were thrust up from greater depths often form these anticline structures. Higher pressures previously contained in the deeper burial position are preserved. For this reason, these anticline structures are often targeted. When drilling on a structural high of the anticline, high pressures should be anticipated. In addition, when deepening confirmation and production wells, or sidetracking, remember that the initial well may have been drilled on a flank (side), and by deepening or sidetracking, unexpected pressures could be encountered. A faulted formation An anticlinal structure Cap Subnormal Normal Normal Abnormal Abnormal Anticlines are geologic structures that have been thrust upward toward the surface.
  27. 27. CHAPTER 2 2-4 SALTS In many areas of the world, thick, nearly pure layers of salt are present. Often, salt is forced upward into the overlying formations to form salt domes. Under the pressure of the overburden, salt exhibits plastic flow ability, not allowing pore fluids to migrate through it. Because of this, formations beneath a salt layer are commonly overpressured. Pierced layers or formations are usually sealed by the salt and lifted up, leading to migration of oil and gas. These zones may have pressure in excess of the surrounding formations. MASSIVE SHALE Thick, impermeable shales restrict the upward movement of pore fluids. As more layers of overburden were accumulated, formation pressures became abnormal, not allowing for the normal compaction and cementing process. Shale sections formed under these conditions may be mobile or plastic, as they exhibit abnormal pressure when drilled, and will refill the hole when the bit is withdrawn. High fluid densities are often required to control these shales, and may require special casing programs. Overpressured shale will have a lower density and may drill faster due to the lack of normal compaction and hardness. A cap, or seal, of hardened rock often indicates the top of pressured shales. After the cap is drilled, the shale usually becomes progressively softer as pressure increases, resulting in increased penetration rates. Permeable rocks (sandstone) below such shales are generally overpressured also, due to the lack of escape routes for pore fluid as the overburden weight increases. CHARGED ZONES Shallow sands and formations exhibiting abnormal pressure are termed charged zones. Charged zones may be naturally occurring as the result of upward migration of pore fluids from a deeper zone, or they can be man-made. Poor or inadequate primary cement jobs, damaged, or corroded casing and tubulars and infield flood projects can lead to charged zones. Modern geophysical techniques may define shallow charged zones. Such zones are often called bright spots. Normal pressures from a deeper formation, when encountered at shallow depths, are usually difficult to control. Sand & Shale Interbedded Massive Shale Sandstone Structural Pressure Normal Pressure Impermeable Zone Massive shale as a transition zone. Salt Abnormal Pressure Normal Pressure Cap Abnormal Pressure Salt domes are common gulf coast structures. High pressures are often associated with salt domes.
  28. 28. KICK FUNDAMENTALS 2-5 DEPLETED ZONES Zones that have been depleted often have pressures that are lower than normal (subnormal). When encountering one of these zones, severe lost circulation may occur. If the fluid level falls, hydrostatic pressure will be reduced. This may allow another zone – or even the depleted zone – to flow. These conditions can occur where a well was previously drilled. Often there is no offset data available from wells that may have been drilled in the area. Incomplete local history or poor offset well records can be dangerous. PRESSURE INDICATORS – DRILLING The following are the most common signs of formation pressure changes. These signs must be recognized by rig crews and relayed to supervisors. Communication is vital because many of these signs also have other meanings. w Change in rate of penetration w Change in shape, size, amount of cuttings w Increase in rotary torque w Increase in drag w Sloughing shale w Increase in gas content w Variations from normal “d” exponent w Increase in flowline temperature w Decrease in shale density w Increase in chloride content Not all of the above indicators may be present at any one time. Rig personnel should be able to recognize these indicators as possible signs of drilling into higher pressures. PENETRATION RATE CHANGE An increase in the rate of penetration is one of the most widely accepted methods of determining changes in pore pressure. Normally, there is a decrease in drilling rate with depth. This decrease, which results from increased hardness and density of the rock, is also controlled by the difference between hydrostatic pressure and pore pressure. A change in the drilling rate could be an indicator of increasing formation pressure. The drilling rate changes when penetrating an abnormally pressured zone because the Fractures To Higher Zones Old Abandoned Well New Well Old Field Normal Pressure Man-made high pressure zones Abnormally pressured formations can be identified by electric logs. Rig crews need to be on the lookout for – and report immediately – any formation pressure change indicators.
  29. 29. CHAPTER 2 2-6 formation contains more fluids and is softer. The increasing formation pressure will also reduce the overbalance at the bottom of the hole. This means the cuttings will break loose under the bit more easily. A gradual increase or no change in the drilling rate when it should be decreasing can also be signs of increasing formation pressures. The abrupt increase is usually called a drilling break and an abrupt decrease is called a reverse break. Either can be a sign of drilling into another formation that may allow a well kick. When formation pressures change from normal to abnormal as the well is deepened, the area across the change is called a “transition zone.” While drilling a transition zone the mud weight should be maintained as close to formation pressure as possible. A change in pore pressure will then be reflected in the drilling rate. Any extra heavy mud weight will increase the differential pressure and reduce the drilling rate. This will hide the drilling rate increase normally seen as the result of pressure increases. There are, however, things other than pore pressure which affect rate of penetration, including formation changes, hydraulics, rotary speed, fluid properties, bit type, weight on bit, bit condition and mud weight. As previously mentioned, any formation changes present a serious interpretation prob- lem. In general, a sudden large change in drilling rate may indicate a formation change. CUTTINGS CHANGES: SHAPE, SIZE, AMOUNT, TYPE Cuttings are rock fragments chipped, scraped or crushed away from a formation by the action of the bit. The size, shape and amount of cuttings depend largely on formation type, bit type, weight on the bit, bit dullness and the pressure differential (formation versus fluid hydrostatic pressures). The size of the cuttings usually decreases as the bit dulls during drilling if weight on bit, formation type and the pressure differential, remain constant. However, if the pressure differential changes (formation pressure increases), even a dull bit could cut more effectively, and the size, shape and amount of cuttings could increase. On the left: shale cuttings from a normally pressured zone. On the right: shale cuttings from a transition zone. Transition zone: the term used to describe a change in formation pressure, e.g., from normal to abnormal.
  30. 30. KICK FUNDAMENTALS 2-7 TORQUE/DRAG INCREASE During a normal drilling operation rotary torque gradually increases with depth. This is the result of wall contact of the drillstring on the wellbore. Increased formation pressure causes larger amounts of cuttings to enter the wellbore as the bit’s teeth take larger bites into the formation. The increased amount of shale tends to stick, impede bit rotation, or pile up around the collars. An increase in torque over several hundred feet is a good indicator of a pressure increase. When drilling in a balanced or near balanced situation, an increase in drag occurs while making connections in an abnormally pressured zone. This increase can be due to the extra cuttings that enter the wellbore and pile up around or above the collars. Torque and drag may also increase because the formation is soft, which could cause the hole to close around the drill collars and bit. SLOUGHING SHALE/HOLE FILL As the formation pressure becomes greater than the mud column pressure, the mud column becomes less effective in supporting the walls of the hole, and eventually the shale begins to spall or sloughs off the sides of the wellbore. Sloughing shale is not an either/or situation, but depends upon the degree of underbalance and other factors such as the dips in the formations, compaction, cementing of the sand grains, internal stress, etc. Sloughing shale affects drilling by causing tight hole, fill on bottom, and eventually can cause the drillpipe, or other tools to become stuck. Sloughing shale is not always the result of abnormal pressures. It is often attributed to other causes, so the possibility of abnormal pressures may be overlooked. When pressure is the cause of popping, heaving, or sloughing shale, its shape will be long, splintery, and sharply curved. 0.5in to 1.5in SCALE FRONT SIDE BLOCKY, RECTANGULAR SHAPES MAY BE STRIATED FRONT SIDE DELICATE SPIKY SHAPE CONCAVE SURFACEPLAN PLAN Typical shale caving produced by stress relief (b)Typical shale caving produced by underbalanced conditions (a) TYPICALLY CRACKED When pressure is the cause of sloughing shale, its shape will be long, splintery and curved.
  31. 31. CHAPTER 2 2-8 Prior to any kind of trip the hole is usually circulated clean, meaning cuttings are removed from the well to prevent complications. If an abnormal pressured formation is penetrated, it is not unusual to find significant amounts of fill when trying to get back to bottom. This can be due to insufficient hydrostatic to prevent the walls from sloughing or popping into the wellbore. It should be pointed out that lack of pressure is not the only cause of this but could be an indicator of insufficient pressure. GAS CONTENT INCREASE An increase in the gas content of a drilling fluid is a good indicator of abnormally pressured zones. However, gas cutting is not always the result of an underbalanced condition and a correct understanding of gas cutting trends is important. DRILL GAS When a porous, non-permeable formation containing gas is drilled, cuttings containing gas are circulated up the hole. Hydrostatic pressure on these particles is reduced as they circulate up the hole. Gas in cuttings expands and releases to the mud system, cutting the weight. In such cases, increasing the mud weight will not stop the gas cutting. This condition can be verified by stopping the drilling operation and circulating bottoms up. The amount of gas should decrease significantly or stop. CONNECTION OR TRIP GAS While drilling with minimum mud weight, the swabbing effect of the upward pipe movement during a connection or trip can swab formation gases and fluids into the wellbore. This is generally referred to as trip gas or connection gas, and when these gases increase, formation gases may be increasing, or the pressure differential (mud to formation pressure) is changing. BACKGROUND GAS The best example of background gas is in West Texas where the low permeable Permian age Red Beds are drilled with water. The formation pressure in these beds is equivalent to about 16 ppg (1917 kg/m³ ) mud. The Red Beds have gas, but very low permeability. The result is that the mud is gas cut all the time, and causes particularly bad trip gas. 10500 10550 10600 10650 GAS UNITS CONNECTION OFF SCALE Flowline gas must be monitored carefully. An increase in the gas content of a drilling fluid may indicate abnormal pressure.
  32. 32. KICK FUNDAMENTALS 2-9 When you are using gas in the drilling fluid as an indicator of abnormal pressures, a gas detector unit is necessary. A trend of the background and/or connection gas can be noted as the drilling operation progresses. Both background and connection gas should be watched carefully and taken as a possible warning of increasing pore pressure. VARIATIONS FROM “D” EXPONENT The “d” exponent method of detecting and predicting abnormal pressures while drilling is sometimes used. Calculation of the “d” exponent is simple and requires no special equipment. The required information, which should be available on the rig site, is penetration Modern LWD tools use mud pulse telemetry to collect formation data. An accurate plot of the “d” exponent can help predict mud weights required for safe drilling.
  33. 33. CHAPTER 2 2-10 rate, rotary rpms, weight on bit and hole diameter. The “d” is then calculated (by computer program, slide rule or nomograph) and then plotted on semi-log paper. A change in the slope of the line is an indicator of pressured zones. Improvements in plotting techniques have refined the method to the extent that now required mud weights in many areas can be routinely predicted with an accuracy of from 0.2 to 0.5 ppg (24 to 60 kg/m³ ) of the mud weight. Properly used, this information can reduce well kicks and, just as importantly, reduce the use of unnecessarily heavy mud that lowers drilling rate and increases drilling cost. MWD AND LWD The MWD (measurement while drilling) and LWD (logging while drilling) tools are a sophisticated arrangement of electronic instruments. Directional drilling, and formation evaluation information can be gathered and recorded in a real time manner, depending on the configuration and type of tool. Measured parameters such as formation resistivity, torque, temperature, downhole pressure, and acoustic responses, can be used to identify changes in drilling conditions and influx detection. The responses of the parameters vary according to the fluid system (water or oil based), and some interpretation of signals is necessary. Electricity is generated to power the tool by a turbine or impeller in the string assembly. Specific pump rates are required to provide proper power for the tool. Depending on the type of tool, once information is gathered it can be transmitted by wireline, fluid pulses (pressure waves), electromagnetic waves or acoustic waves. The pulses are received by sophisticated sensors on surface and then relayed to computers that decode or translate the pulses into useable information. SHALE DENSITY DECREASE Shales that are normally pressured have undergone normal compaction and their densities increase uniformly with depth. This uniform increase allows shale density to be predicted. Any reduction from the trend can be interpreted as a zone of higher pore pressure since high pressure shales are less dense than normal pressured shales. This occurs as a result of pore fluids trapped in shale sections during the compaction process. Problems clouding the field usefulness of shale density pressure prediction lie in the methods for measuring shale density. Three methods are commonly used. They are: LWD techniques provide real time info of well conditions. MWD and LWD tools gather data that can be used to predict formation pressure.
  34. 34. KICK FUNDAMENTALS 2-11 w Variable density liquid column w Mud balance density w MWD (measurement while drilling) logging techniques. Determining the source depth of the shale cuttings is not easy, and the selection and preparation of the cuttings for measurement depends largely on the experience of the person making the measurement. FLOWLINE TEMPERATURE INCREASE The seal at the top of a transition zone limits the movement of water. So above normal temperatures occur in both the transition zone and in the zone of higher pressure below. If a normal trend of flowline temperature is plotted, a change of 2 to 6 degrees or more per 100 feet (30.48 m) above this trend can be an indication of a transition zone. In addition to indicating a pore pressure change, changes in flowline temperature may also be attributed to: w A change in circulation rate w A change in solids content of mud w A change in mud chemistry w A change in drilling practices. The temperature curves (shown below), although not always definitive, are an additional indicator that help in the decision to stop drilling or increase present mud weight. Offshore, as the water depth increases, the ability to use the temperature plot decreases. It can be rendered useless by the cooling effect of the water unless the temperature at the stack can be monitored. In deep water, the surface temperature of the drilling mud returning may remain constant throughout the operation. CHANGE IN CHLORIDE CONTENT Changes in the salt or chloride ion content of the drilling fluids are a valid pressure indicator. If insufficient pressure exists formation seepage or flow may enter the wellbore and mingle with the drilling fluid. This will change the chloride content of the mud. Depending on the existing chloride content of the mud, an increase or decrease may be determined based on whether the formation fluid’s salt content is higher or lower. However, changes are difficult to establish unless there is a close control of the mud checks. Most methods currently available to make chloride ion tests are inadequate to show subtle changes. In fresh water/bentonite muds, increases in chloride content will cause an increase in the funnel viscosity and flow properties. 9 10 11 12 110100 120 130 Flow - Line Temperature (°F) Depth(1,000ft) Transition Zone An increase in flowline temperature could be an indication that formation pressure is increasing. Changes in flowline temperature can be used with other indicators to help identify transition zones.
  35. 35. CHAPTER 2 2-12 LOGGING PRESSURE INDICATORS The normal electric log or induction log measures the electrical resistivity of the formation. Since abnormally pressured shale formations generally have more water, they are less resistive than drier, normally pressured formations. The resistivity change can be measured and formation pressure calculated. The acoustic or sonic log measures the sound velocity or interval transit time of the formation. High-pressure shale formations that have more water have lower sound velocity and a resulting higher transit time. Calculations can be made to determine the formation pressure and porosity from these measurements. The density log measures the density of the formation based on radioactive measurements. High-pressure shale formations have less density and calculations can be made to determine formation pressure. CAUSES OF KICKS Any time the formation pore pressure is greater than the pressure exerted by the column of fluid in the well, formation fluid can flow into the well. This can occur from one or a combination of reasons. The most common causes of kicks follow. w Insufficient fluid density w Poor tripping practices w Improper hole fill while tripping w Swabbing/surging w Lost circulation w Abnormal pressure w Obstructions in the wellbore w Cementing operations w Special situations, including: ú Excessive drilling rate through gas sand ú Excessive water loss of drilling fluid ú Drilling into an adjacent well ú Charged formations ú Obstructions in wellbore ú Testing BOPs ú Trapped gas below BOPs ú Loss of subsea riser ú Secondary recovery projects ú Water flushes ú Drill stem testing (DST) ú Underbalanced drilling – failure to maintain adequate backpressure ú Platform leg INSUFFICIENT FLUID DENSITY Insufficient fluid density, or fluid not heavy enough to control the formation, is a common cause of kicks. The fluid in the wellbore must exert enough hydrostatic pressure to equal the formation pore pressure. If the fluid’s hydrostatic is less than formation pressure the well can flow. Probably the most common reason for insufficient fluid density is drilling into unexpected abnormally pressured formations. This situation can arise when unpredictable geological conditions are encountered, such as drilling across a fault that abruptly changes the formation being drilled. Insufficient fluid density can also be the result of misinterpreting normal drilling parameters (ROP, gas content, shale density, etc.) used as guides to weight up mud. (This usually means the transition zone was missed and the first permeable formation caused the kick.) Mishandling mud at the surface accounts for many instances of insufficient fluid density. Opening the wrong valve on the pump suction manifold and allowing a tank of light weight fluid to be pumped; bumping the water valve so more water is added than intended; washing off shale shakers; or clean up operations - can all affect fluid density. Once a formation has been drilled the pore pressure may be determined by electric logs.
  36. 36. KICK FUNDAMENTALS 2-13 Rainwater may find its way into the circulating system, greatly affecting density and severely altering the fluid’s properties. Also cutting back the weight of the fluid in the well can be dangerous because you are intentionally adding water to the system while circulating. If too much water is added, or the fluid’s density becomes too low, the well may start to flow. However, since the crew is mixing and adding volume to the pits, a gain from the flowing well may be hard to detect. It is good practice to add known or measured volumes when mixing. If the water used to cut the fluid’s density can be taken from a tank with a known volume, then the amount of water taken from that tank should equal the gain in the pits. If there is more gain than can be accounted for, the well may be flowing. Notify proper rig personnel when mixing, adding or transferring fluid in the pits. Other causes of improper fluid density include changing out the present fluid in the well for fracturing or acid jobs, spotting large pills, or changing to perforating, completion or packer fluids. TRIPPING OUT Perhaps the leading cause of kicks results from pulling pipe out of the well. Many factors come into play during a trip. Simply put, either you don’t have adequate fluid weight to hold the formations back, or pressure was reduced in the wellbore during the trip to allow an influx. Under normal activities if circulation can be stopped prior to the trip out without taking a kick, then a kick should not occur during tripping. A factor that is often not considered is the frictional force exerted on the formation by fluid circulation. This is called annular pressure loss (APL), and may represent the equivalent circulating density (ECD) of over 1 ppg (120 kg/m³ ) of weight material. Once the pumps are shut down, circulating pressure is lost and bottomhole pressure is reduced to the hydrostatic pressure of the fluid in the annulus. This reduction in bottomhole pressure may allow the well to start kicking. Before starting a trip, always watch the hole to see if the well is flowing after the pumps are shut down. Company policy may dictate 5 to 30 minutes to just watch the well. This is time well spent if it prevents a kick and the complications that may result. If proper time is given to make sure the well is not flowing, and then a kick is taken on the trip out, it is assumed that something that happened while pulling the pipe started the kick. The vast majority of these kicks are due to swabbing/surging. SWABBING AND SURGING Whenever pipe is moved through fluid, both swab and surge forces are present. The direction of pipe travel dictates the dominant force, swab or surge. When pipe travels upwards, (for example, a trip out of the hole) swab pressure is dominant. Fluid often cannot fall down between the pipe and wellbore as fast as the pipe is being pulled upwards. So a reduction in pressure is created under the pipe allowing formation fluid to feed in until the pressure reduction stops. This is called swabbing. If enough fluid is swabbed in, it may lighten the total hydrostatic enough for the well to begin to flow. The analogy of pulling a plunger in a syringe illustrates this concept. Surge pressure is also present as pipe is being tripped out of the hole, but usually has less effect than swabbing. Fluid surrounding the pipe (especially above bottomhole assembly) must get out of the way by moving upwards around the pipe and up the hole. If the pipe is pulled too fast, not all of the fluid can move out of the way. A pressure buildup may occur, leading to losses and hydrostatic reduction. On the trip out, three main things – the clearance, fluid properties and the rate of pipe movement – affect swabbing and surging. Before starting a trip, observe the well carefully to make sure it doesn’t flow when the pumps are shut down.
  37. 37. CHAPTER 2 2-14 CLEARANCE One of the most important factors in swab pressure development is the clearance between the pipe (tubing, drillpipe, collars, stabilizers or tools) and the wellbore (open or cased hole). The smaller the clearance, the more restriction fluid must overcome to flow. Wells with tight areas, swelling formations, sloughing formations, or wells prone to balling tools decrease clearance and increase the chance for swabbing in a kick. While it is usually not possible to control these factors, proper tripping practices, such as reduced tripping speeds, minimize the chance of swabbing an influx into the well. Factors compounding and reducing clearance include restrictions between the string and wellbore or casing, such as swelled formations, collapsed casing, or a balled up bit. These problems are not usually known until it is too late. Keep in mind that the clearance between pipe and casing may be smaller than thought. This increases the chance of swabbing in a kick, or surging the well. OTHER FACTORS AFFECTING CLEARANCE SALT AND SWELLING FORMATIONS Some examples of clearance problems from formations are salt and swelling. Salt is plastic. Depending on the pressure being imposed on it, the clearance in the wellbore can be reduced once the pump has been turned off (loss of circulating pressure and also lateral pressure on the wellbore). Salts have been known to close in around the string giving it just enough clearance for circulation. In addition, clays swell when exposed to water, narrowing the string to wellbore clearance, and increasing the chance for the well to be swabbed in. With reduced clearance during the trip out, stabilizers and bottomhole assemblies could stick or cause severe swabbing. BALLING Balling refers to materials (barite, fluid, formation matter, wall cake) gathered around a bit, stabilizer, tool joint or any part of the string. This gathering increases effective OD at that point and reduces clearance between the string and hole. As clearance narrows, this problem may be seen as an increase in torque (more balled up pipe-to-formation contact) and/or an increase in pick-up weight from drag due to the well contact and lifting of the mud column. PULLING INTO SHOE It is a shame that some drillers learn the hard way the double jeopardy associated with casing shoes. First, there is the possibility of a stabilizer or tool catching on the casing shoe, which may result in rig damage, the pipe being parted, or the shoe pulled in and pipe stuck. Second, there is the reduction of clearance as the bottomhole assembly is pulled up into the casing. Clearance complications can also happen when any part of the string, or bottomhole assembly, becomes balled. AN EXAMPLE: The casing is assumed to be gauge, but the open hole may have a washout factor ranging from 5% to 150%. For example, the ID of the casing is 8.835” (224.41 mm) and you pull 8 1⁄2” (215.9 mm) stabilizers that are balled up to an OD of 10 1⁄2” (266.7 mm). Once the balled up stabilizers enter the casing shoe, the excess mud around the stabilizers will shear off. Now the stabilizers, balled up with cuttings and mud, will have an OD that is roughly the same as the ID of the casing. It is similar to pulling a swab into the casing. Prior to pulling off bottom, each driller should calculate the number of feet or the number of stands of pipe pulled prior to the bottomhole assembly entering the casing shoe. Always reduce speed when entering the casing shoe and be alert. Always keep an especially close monitor on hole fill. Swabbing can occur if pipe is pulled from a well faster than the fluid can fall below it.
  38. 38. KICK FUNDAMENTALS 2-15 HOLE ANGLE AND DOGLEGS When pulling up through deviated wells and dogleg areas, remember that the BHA is dragged against the top portion of the wellbore. This may result in the pipe and BHA picking up debris (balling) and reducing clearance. This reduced clearance makes it harder for fluid to fall back down around the assembly. During drilling operations, cuttings will tend to fall or stay on the low side of deviated holes and doglegs, reducing the ID and making it tight when pulling out. BOTTOMHOLE ASSEMBLY LENGTH The longer the reduced clearance area, the greater the chance for swabbing. It stands to reason that 500’ (152.4 m) of collars will not contribute as much to swabbing as 1,000’ (304.8 m) of collars. NUMBER OF STABILIZERS As in the case above, a pendulum bottomhole assembly with one stabilizer will not swab as much as a packed hole assembly with several stabilizers. As the number of stabilizers increases, so does the chance of balling and swabbing. TOOLS RUN Extra care should be taken when pulling tools that create small clearances. The larger the OD of the tool, the greater the chance for swabbing. In open hole operations severe balling can result. Swabbing effects are minimal when pulling smaller OD tools such as stingers, or open ended and small diameter pipe, since the clearances are greater. FLUID PROPERTIES Since swabbing depends on the lifting and flowing of fluid from where it was before pipe was moved, the properties of the fluid are critical. The following properties are important: viscosity, gel strength, density and water loss. VISCOSITY Viscosity, or readiness of a fluid to flow, is perhaps the most critical of all factors in swabbing. If fluid is thick or viscous, it has a difficult time flowing down as pipe is pulled upwards. When fluid’s viscosity is high, slower pulling speeds are needed to allow fluid to fall back down around smaller clearances. By tripping out slowly, according to calculations, minimal bottomhole pressure losses occur. This reduces the potential for the well to swab or flow. The funnel viscosity test should be checked in order to determine if the fluid is in good enough condition to begin the trip. If the hole and/or fluid have problems, the mud may have to be conditioned in the hole before starting the trip. GEL STRENGTH Gel strength is the attraction of solids particles to each other. A strong attraction resists flow from static conditions and increases swab pressures. If fluid has progressive gel strength, upward pulling of pipe can also produce surge pressures upward. This pressure may cause weak zones to take fluid, lowering the hydrostatic head and contributing to the kick mechanism. DENSITY If the mud density is too high and causes seepage or loss of fluid into the formation, it can effectively push the pipe into the side of the hole. Cuttings, wall cake, and other debris can be collected by stabilizers, or other downhole tools. This can reduce clearance and create a swabbing effect. When mud densities are too low, bottomhole tools tend to scrape the sides of the wellbore due to swelling formations. They can collect debris and reduce clearance. In some instances if the overbalance is high enough, the swabbing potential may decrease. WATER LOSS The advantages of high water loss muds include faster penetration rates. Disadvantages include sticking problems due to thick, gummy wall cakes reducing the ID of the hole that increase the chance of swabbing. Fluids with high gel strengths increase the likelihood of swabbing on trips.
  39. 39. CHAPTER 2 2-16 RATE OF PIPE MOVEMENT The rate of pipe movement directly affects swab and surge pressures. The faster the pipe travels the greater the swab and surge pressures and the higher the potential for swabbing in an influx. Chances of swabbing in a kick (and/or breaking down the formation) will increase with trip speed. One misconception is that once the bit enters the shoe, the well can no longer be swabbed and trip speed tends to increase. We need to remember that there is the potential to have a smaller clearance inside the casing than the open hole. IMPROPER HOLE FILL Whenever the fluid level in the hole drops, the hydrostatic pressure exerted by the fluid also drops. When the hydrostatic pressure falls below the formation pore pressure, the well may flow. Pipe may be pulled dry or wet depending on conditions. If it is pulled dry it is due to a heavy slug that was pumped in the string prior to the trip, pushing out a length of the lighter fluid in the pipe. As the pipe is pulled, the slug will fall again, so subsequent stands will also pull dry. Depending on practices, the slug may affect the fill up on the first five to ten, or more, of the stands of pipe pulled. If tripping out begins too soon after pumping the slug, the pipe could pull partially wet if the slug is not given time to seek its level. During a dry trip out of the hole, the volume of steel pipe being removed results in a corresponding drop in wellbore fluid. The hole must be refilled to maintain sufficient hydrostatic pressure to control formation pressure. If the pipe is pulling wet (fluid remains in the pipe), and a mud bucket is used to drain away from the hole, trip tank or pits, then the combined volume of the steel pipe and the internal capacity of the pipe are removed. This results in a larger amount of fluid being required to fill the hole than when pulling dry pipe. However, if the mud bucket drains back into the hole, trip tank or pits, then the amount to fill would be the same as pulling dry pipe (providing mud bucket does not leak). If a mud bucket is not used, it is difficult to account for spillage on the rig floor, decreasing the quantity of fluid that should be returned to the mud system and measured. If not all of the wet pipe’s fluid can be recovered, divert the fluid away from the active or measured pit volume and use the calculations for wet pipe. Coiled tubing units are an exception. As the coiled tubing is extracted from the well, the tubing displacement and capacity are removed from the well. The coil stays loaded with fluid unless it is displaced with nitrogen prior to tripping out. Coiled tubing can circulate as the pipe is extracted, reducing chances for swab and keeping the hole full. It should be noted that many tables do not have the correct data to use for trip calculations because they omit the tool joints and upsets. These tables simply list the size of the tube, and nominal weight per foot, for example, 5” OD (127 mm), 19.5 ppf (29.02 kg/m), as well as the capacities and displacements. Manufacturers’ pipe data is accurate, but charts and tables may be confusing because there are many combinations of thread forms, tool joint ODs, IDs and lengths and a wide variety of capacity/displacement numbers. Pipe range also affects the adjusted weight per foot. API RP7G illustrates the methodology for calculating accurate pipe displacement and gives correct charts and tables. The rate of pipe movement directly affects swab or surge pressures.
  40. 40. KICK FUNDAMENTALS 2-17 To calculate the volume to fill the well when tripping dry pipe out: Barrels to Fill = Pipe Displacementbbls/ft × Length Pulledft m³ to Fill = Pipe Displacementm³/m × Length Pulledm To calculate the volume to fill the well when tripping wet pipe out: Barrels to Fill = (Pipe Displacementbbls/ft + Pipe Capacitybbls/ft) × Length Pulledft m³ to Fill = (Pipe Displacementm³/m + Pipe Capacitym³/m ) × Length Pulledm EXAMPLE 1 How many barrels will it take to fill the annulus if 15 dry joints (assume each joint is 31’ [9.45 m]) of 4 1/2” (114.3 mm) drillpipe, with 0.00639 bbls/ft (0.00333 m³/m) displacement, were pulled from 9 5/8” (244.5 mm) casing having an ID of 8.755” (222.38 mm)? Barrels to Fill = Pipe Displacementbbls/ft × Lengthft = 0.00639 × (15 × 31) = 0.00639 × 465 = 2.97 bbls m³ to Fill = Pipe Displacementm³/m × Lengthm = 0.00333 × (15 × 9.45) = 0.00333 × 141.75 = 0.47203 m³ PROBLEM 1A How many barrels (m³) will it take to fill the annulus if 15 joints of 5” (127 mm) drillpipe (31’ [9.45 m] per joint, 0.007593 bbls/ft [0.00396 m³/m] displacement, 0.01776 bbl/ft [0.00926 m³/m] capacity) were pulled from 9 5/8” (244.5 mm) casing having an ID of 8.375” (212.73 mm)? PROBLEM 1B How many barrels (m³) will it take to fill the annulus if 15 joints of 2 7/8” (73.03 mm) production tubing (31’ [9.45 m] per joint, 0.00236 bbls/ft [0.00123 m³/m] displacement, 0.00579 bbl/ft [0.00302 m³/m] capacity) were pulled from 9 5/8” (244.5 mm) casing having an ID of 8.375” (212.73 mm)? When tripping out dry, the volume of steel removed from the well must be replaced with an equal volume of fluid.
  41. 41. CHAPTER 2 2-18 To accurately measure the fluid, use a trip tank or pump stroke counter system. Filling the hole with a trip tank, if one is available, is preferred since the trip tank has a small, easily measured volume. However, the pump stroke counter system may also be used. To calculate the number of strokes to fill up the hole: Strokes to Fill = Barrels to Fill ÷ Pump Outputbbls/stk Strokes to Fill = m³ to Fill ÷ Pump Outputm³/stk EXAMPLE 2 How many strokes will it take to fill the hole with 2.97 bbls (0.472 m³) using a triplex pump with an output of 0.127 bbl/stk (0.0202 m³/stk). Strokes to Fill = Barrels to Fill ÷ Pump Outputbbls/stk = 2.97 ÷ 0.127 = 24 stks Strokes to fill = m³ to fill ÷ Pump outputm³/stk = 0.472 ÷ 0.0202 = 24 stks Note: Since the strokes were a fraction higher than a whole number (i.e., 23.4), strokes are rounded up to the next highest number. PROBLEM 2A How many strokes will it take to fill the hole with a triplex pump with an output of 0.105 bbl/stk (0.0167 m³/stk), when 15 joints (31 feet [9.45 m] per joint) of 5” (127 mm) drillpipe, (0.007593 bbl/ft [0.00396 m³/m] displacement, 0.01776 bbl/ft [0.00926 m³/m] capacity) were pulled dry from 9 5/8” (244.5 mm) casing having an ID of 8.375” (212.73 mm)? PROBLEM 2B How many strokes will it take to fill the annulus with a triplex pump with an output of 0.049 bbl/stk (0.0078 m³/stk), if 15 joints of 2 7/8” (73.03 mm) production tubing (31’ [9.45 m] per joint, 0.00236 bbls/ft [0.00123 m³/m] displacement, 0.00579 bbl/ft [0.00302 m³/m] capacity) were pulled wet from 7” (177.8 mm) casing having an ID of 5.92” (150.37 mm)? It should be noted that pump strokes never come out exact because of the lag time for mud to flow down the flowline and move the flow sensor. During this lag time the pump stroke counter continues to count. This adds around 5 to 10 (or more) strokes to the fill up. Good practices and also certain regulatory bodies require that the well be filled every five stands of pipe pulled, or before the decrease in hydrostatic pressure equals 75 psi (5.17 bar), whichever comes first. Measuring fill-up by pump strokes is not perfectly accurate due to the lag time as the fluid runs through the flowline.
  42. 42. KICK FUNDAMENTALS 2-19 To calculate the amount of dry pipe that may be pulled before a 75 psi (5.17 bar) reduction in hydrostatic pressure occurs: Max. Lengthft = (Pressure Droppsi ÷ 0.052 ÷ Fluid Densityppg) × (Csg. Cap.bbls/ft – Pipe Displ.bbl/ft) ÷ Pipe Displ.bbl/ft Max. Lengthm = (Pressure Dropbar ÷ 0.0000981 ÷ Fluid densitykg/m³) × (Csg. Cap.m³/m – Pipe Displ.m³/m) ÷ Pipe Displ.m³/m EXAMPLE 3 How many feet of dry 4 1/2” (114.3 mm) drillpipe with a displacement of 0.00597 bbls/ft (0.00311 m³/m) and a capacity of 0.01422 bbls/ft (0.00742 m³/m), could be pulled from 9 5/8” (244.48 mm) casing having an ID of 8.835” (224.41 mm) and a capacity of 0.07583 bbl/ft (0.03955 m³/m) with a fluid density of 12.5 ppg (1498 kg/m³) prior to a bottomhole pressure drop of 75 psi (5.17 bar) occuring? Max. Lengthft = (Pressure Droppsi ÷ 0.052 ÷ Fluid Densityppg) × (Csg. Cap.bbls/ft – Pipe Displ.bbl/ft) ÷ Pipe Displ.bbl/ft = (75 ÷ 0.052 ÷ 12.5) × (0.07583 – 0.00597) ÷ 0.00597 = 115.4 × 0.06986 ÷ 0.00597 = 1,350.4 ft Max. Lengthm = (Pressure Dropbar ÷ 0.0000981 ÷ Fluid Densitykg/m³) × (Csg. Cap.m³/m – Pipe Displ.m³/m) ÷ Pipe Displ.m³/m = (5.17 ÷ 0.0000981 ÷ 1498) × (0.03955 – 0.00311) ÷ 0.00311 = 35.18 × 0.03644 ÷ 0.00311 = 412.2 m Note: It should be pointed out that in this example, even though 1,350.4 ft (412.2 m) of tubing could be pulled prior to a 75 psi (5.17 bar) decrease in hydrostatic pressure, regulations may require a limit on stands that may be pulled prior to fill up. PROBLEM 3A How many feet of dry 5” (127 mm) drillpipe with a displacement of 0.00709 bbls/ft (0.0037 m³/m) and a capacity of 0.01776 bbl/ft (0.00926 m³/m), a casing capacity of 0.056 bbl/ft (0.02921 m³/m) and with a fluid density of 13.8 ppg (1654 kg/m³) could be pulled prior to a 75 psi (5.17 bar) reduction in bottomhole pressure occuring? Trip tanks provide an accurate means of monitoring hole fill-up on trips.
  43. 43. CHAPTER 2 2-20 PROBLEM 3B How many feet of dry 2 7/8” (73.03 mm) tubing with a displacement of 0.00224 bbl/ft (0.00117 m³/m) and a capacity of 0.00578 bbl/ft (0.00302 m³/m), a casing capacity of 0.036 bbl/ft (0.00188 m³/m) with a fluid density of 14.3 ppg (1714 kg/m³) could be pulled prior to a 75 psi (5.17 bar) reduction in bottomhole pressure occuring? To calculate the amount of wet pipe that may be pulled before a 75 psi (5.17 bar) reduction in hydrostatic pressure occurs: Max. Lengthft = (Pressure Droppsi ÷ 0.052 ÷ Fluid Densityppg) × (Csg. Cap.bbls/ft – Pipe Displ.bbl/ft – Pipe Cap.bbl/ft) ÷ (Pipe Displ.bbl/ft + Pipe Cap.bbl/ft) Max. Lengthm = (Pressure Dropbar ÷ 0.0000981 ÷ Fluid Densitykg/m³) × (Csg. Cap.m³/m – Pipe Displ.m³/m – Pipe Cap.m³/m) ÷ (Pipe Displ.m³/m + Pipe Cap.m³/m) EXAMPLE 4 How many feet of wet 4 1/2” (114.3 mm) drillpipe with a displacement of 0.00597 bbls/ft (0.00311 m³/m) and a capacity of 0.01422 bbls/ft (0.00742 m³/m), could be pulled from 9 5/8” (244.48 mm) casing having an ID of 8.835” (222.41 mm) and a capacity of 0.07583 bbl/ft (0.03955 m³/m) with a fluid density of 12.5 ppg (1498 kg/m³) could be pulled prior to a 75 psi (5.17 bar) reduction in bottomhole pressure occuring? Max. Lengthft = (Pressure Droppsi ÷ 0.052 ÷ Fluid Densityppg) × (Csg. Cap.bbls/ft – Pipe Displ.bbl/ft – Pipe Cap.bbl/ft) ÷ (Pipe Displ.bbl/ft + Pipe Cap.bbl/ft) = (75 ÷ 0.052 ÷ 12.5) × (0.07583 – 0.00597 – 0.01422) ÷ (0.00597 + 0.01422) = 115.4 × 0.05564 ÷ 0.02019 = 318.5 ft Max. Lengthm = (Pressure Dropbar ÷ 0.0000981 ÷ Fluid Densitykg/m³) × (Csg. Cap.m³/m – Pipe Displ.m³/m – Pipe Cap.m³/m) ÷ (Pipe Displ.m³/m + Pipe Cap.m³/m) = (5.17 ÷ 0.0000981 ÷ 1498) × (0.03955 – 0.00311 – 0.00742) ÷ (0.00311 + 0.00742) = 35.18 × 0.02902 ÷ 0.01053 = 97.1 m PROBLEM 4A How many feet of wet 5” (127 mm) drillpipe with a displacement of 0.00709 bbls/ft (0.0037 m³/m) and a capacity of 0.01776 bbl/ft (0.00926 m³/m), a casing capacity of 0.056 bbl/ft (0.00291 m³/m) and with a fluid density of 13.8 ppg (1654 kg/m³) could be pulled prior to a 75 psi (5.17 bar) reduction in bottomhole pressure occuring? Good practices dictate that a well be filled after five stands of drillpipe (or one stand of collars) are pulled out of the hole.
  44. 44. KICK FUNDAMENTALS 2-21 PROBLEM 4B How many feet of wet 2 7/8” (73.3 mm) tubing with a displacement of 0.00224 bbl/ft (0.00117 m³/m) and a capacity of 0.00578 bbl/ft (0.00302 m³/m), a casing capacity of 0.036 bbl/ft (0.01878 m³/m) and with a fluid density of 14.3 ppg (1714 kg/m³) could be pulled prior to a 75 psi (5.17 bar) reduction in bottomhole pressure occuring? The fill up tally (volume or strokes) should be accumulated on the trip out as an overall check on fill. If tally is not close to calculated strokes or volume, a problem could exist. Often the well takes or gives fluid to the wellbore during trips. This is neither lost circulation nor a kick. It should be standard practice to maintain trip records on the rig. If formation seepage or fluid loss occurs, comparison with prior records is the only way to accurately predict hole fill volumes. Properly maintained trip records are invaluable in preventing kicks and showing how much fluid was lost to the formation. When out of the hole, the well should be monitored and kept full. If the hole is taking fluid and fluid level is allowed to drop, hydrostatic pressure will drop also. In some cases (as in subnormal pressured zones), it may be necessary to maintain the static fluid level at a level below surface to maintain a balanced condition. The fluid level should be maintained downhole by trickling fluid from measured tanks into the well and continuously monitoring. The importance of keeping the hole full cannot be emphasized enough. On wells with shallow gas conditions, a small drop in hydrostatic and/or swab pressures can start the well flowing. At shallow depths, gas can be to the rig floor before a preventer has time to close. It is of the utmost importance to use proper hole fill techniques under these conditions. Remember that the displacement of collars is five to ten times as great as the displacement of the drillpipe or tubing. Failure to fill up for each collar removed could drop the fluid level enough to start the well flowing. Trip log while tripping in the hole; accurate trip records are a must on every job. Stand No. Starting Trip Tank Reading Finish Trip Tank Reading Difference Theoretical (Calculated) Trend (Difference) Accumulated Trend Remarks (Comment when change of pipe, problems, etc.) 67 5 8.7 3.7 3.7 - - Starting in with collars 66 8.7 12.3 3.6 3.7 -.1 65 12.3 14.2 1.9 3.7 -1.8 -1.9 64 14.2 16.9 2.7 3.7 -1 -2.9 Slowing speed down, possible surge 63 16.9 20.6 3.7 3.7 - -2.9 Fill collars and monitored hole - ok 62 20.6 22.1 1.5 2.43 -.93 -3.83 Running collars in 61 22.1 25.3 3.2 2.43 +.77 -3.06 60 25.3 27.6 2.3 2.43 -.13 -3.19 Filled up hevi-wate Running in with pipe 55 27.6 36.9 9.3 11.5 -2.2 -5.39 Slowing down run in speed 50 36.9 44.2 7.3 11.5 -4.2 -9.59 Still losing, emptied trip tank 45 0 12.7 12.7 11.5 +1.2 -8.39 44 12.7 27 14.3 11.5 +2.8 -5.59 Stop trip and check for flow On a trip back in, do not assume the well is dead until bottoms up has been circulated.

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