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(1)RD. NTRE. C. ON. CE. • ABE L & WEL. OL S •. & Well Control Training Centre. ILL N DR IN G SC HO. ABERDEEN DRILLING SCHOOLS. EE. TROL TRAININ. G. WELL CONTROL for the Rig-Site Drilling Team. ➞ ➞. TRAINING MANUAL.

(2) WELL CONTROL for the Rig-Site Drilling Team. COPYRIGHT STATEMENT. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, including photocopying and recording without the written permission of the copyright holder, application for which should be addressed to: Aberdeen Drilling Schools Ltd., 50 Union Glen, Aberdeen, AB11 6ER. Such written permission must also be obtained before any part of this publication is stored in a retrieval system of any nature. Brand names, company names, trademarks, or other identifying symbols appearing in illustrations and/or text are used for educational purposes only and do not constitute an endorsement by the author or publisher. Illustrations have been included in this document with the kind permission of Cooper Cameron UK Ltd, Shaffer A Varco Co and Hydril UK Ltd..

(3) WELL CONTROL for the Rig-Site Drilling Team. CONTENTS. SECTION. Introduction 11. Fundamental Principles of Well Control. 22. Causes of Kicks. 33. Kick Indicators. 44. Shut-in Procedures. 55. Methods of Well Control. 66. Well Control Equipment. 7. Inspection, Testing and Sealing Components. 89. Surface BOP Control Systems. 910. Subsea BOP Control Systems and Marine Riser Systems. 10. Formulae, Conversion Factors & Glossary of Terms.

(4) WELL CONTROL for the Rig-Site Drilling Team INTRODUCTION. INTRODUCTION The objective of this manual is to provide a good understanding of the fundamentals of Well Control that can be applied to most Well Control operations. In all cases, minimising the kick volume and closing the well in is our first priority. We have tried, as far as possible, to avoid using specialist terms and iconography. This manual describes industry recognised standards and practices and basic Well Control procedures. They differ from our advanced Well Control methods which tend to be well, formation, or rig specific. The manual covers the guidelines found in API 59 and API 53 along with the International Well Control Forum syllabus. All Well Control principles rely upon an understanding that good planning and early recognition and close in, is the best form of Well Control. Not all kicks are swabbed kicks, many wells are drilled into unknown formation. It is recognised that equipment can fail despite all the correct procedures being followed. This is why you will find the equipment section comprehensive and useful for general trouble shooting ideas..

(5) SECTION 1 :. FUNDAMENTAL PRINCIPLES OF WELL CONTROL Page. 1. 0. Objectives. 1. 1. 1. General Information. 1. 1. 2. Hydrostatic Pressure. 3. 1. 3. Formation Pressure. 4. 1. 4. Normal Formation Pressure. 4. 1. 5. Abnormal Pressure. 7. 1. 6. Formation Fracture Pressure. 12. 1. 7. Leak-off Tests. 14. 1. 8. Maximum Allowable Annular Surface Pressure - MAASP. 21. 1. 9. Casing Setting Depths. 21. 1. 10. Circulating Pump Pressure. 23. 1. 11. Choke Line Friction. 25. 1.12. Workshop 1. 30.

(6) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. FUNDAMENTAL PRINCIPLES OF WELL CONTROL 1.0 OBJECTIVES The objectives of this section are to introduce the Fundamental Principles of Well Control.. 1.1 GENERAL INFORMATION The function of Well Control can be conveniently subdivided into three main categories, namely PRIMARY WELL CONTROL, SECONDARY WELL CONTROL and TERTIARY WELL CONTROL. These categories are briefly described in the following paragraphs. Primary Well Control It is the name given to the process which maintains a hydrostatic pressure in the wellbore greater than the pressure of the fluids in the formation being drilled, but less than formation fracture pressure. If hydrostatic pressure is less than formation pressure then formation fluids will enter the wellbore. If the hydrostatic pressure of the fluid in the wellbore exceeds the fracture pressure of the formation then the fluid in the well could be lost. In an extreme case of lost circulation the formation pressure may exceed hydrostatic pressure allowing formation fluids to enter into the well. An overbalance of hydrostatic pressure over formation pressure is maintained, this excess is generally referred to as a trip margin. Secondary Well Control If the pressure of the fluids in the wellbore ( i.e. mud) fail to prevent formation fluids entering the wellbore, the well will flow. This process is stopped using a “blow out preventer” to prevent the escape of wellbore fluids from the well. This is the initial stage of secondary well control. Containment of unwanted formation fluids.. 1-1.

(7) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. Tertiary Well Control Tertiary well control describes the third line of defence. Where the formation cannot be controlled by primary or secondary well control (hydrostatic and equipment). An underground blowout for example. However in well control it is not always used as a qualitative term. ‘Unusual well control operations’ listed below are considered under this term:a). A kick is taken with the kick off bottom.. b). The drill pipe plugs off during a kill operation.. c). There is no pipe in the hole.. d). Hole in drill string.. e). Lost circulation.. f). Excessive casing pressure.. g). Plugged and stuck off bottom.. h). Gas percolation without gas expansion.. We could also include operations like stripping or snubbing in the hole, or drilling relief wells. The point to remember is "what is the well status at shut in?" This determines the method of well control.. 1-2.

(8) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. 1.2 HYDROSTATIC PRESSURE Hydrostatic pressure is defined as the pressure due to the unit weight and vertical height of a column of fluid. Hydrostatic Pressure = Fluid Density x True Vertical Depth It is the vertical height/depth of the fluid column that matters, its shape is unimportant.. TVD. Note:. Figure 1.1 Different shaped vessels Since the pressure is measured in psi and depth is measured in feet, it is convenient to convert mud weights from pounds per gallon ppg to a pressure gradient psi/ft. The conversion factor is 0.052. Pressure Gradient psi/ft = Fluid Density in ppg X 0.052 Hydrostatic Pressure psi = Density in ppg X 0.052 X True Vert. Depth The Conversion factor 0.052 psi/ft per lb/gal is derived as follows: A cubic foot contains 7.48 US gallons. A fluid weighing 1 ppg is therefore equivalent to 7.48 lbs/cu.ft The pressure exerted by one foot of that fluid over the area of the base would be: 7.48 lbs –––––––– = 144 sq.ins. 0.052 psi 12". 12". Figure 1.2 Area definition of a cubic foot. 12". 1-3.

(9) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. Example: The Pressure Gradient of a 10 ppg mud =. 10 x 0.052. =. 0.52 psi/ft. Conversion constants for other mud weight units are: Specific Gravity x 0.433. =. Pressure Gradient psi/ft. Pounds per Cubic Foot ÷ 144 =. Pressure Gradient psi/ft. 1.3 FORMATION PRESSURE Formation pressure or pore pressure is said to be normal when it is caused solely by the hydrostatic head of the subsurface water contained in the formations and there is pore to pore pressure communication with the atmosphere. Dividing this pressure by the true vertical depth gives an average pressure gradient of the formation fluid, normally between 0.433 psi/ft and 0.465 psi/ft. The North Sea area pore pressure averages 0.452 psi/ft. In the absence of accurate data, 0.465 psi/ft which is the average pore pressure gradient in the Gulf of Mexico is often taken to be the “normal” pressure gradient. Note:. The point at which atmospheric contact is established may not necessarily be at sea-level or rig site level.. 1.4 NORMAL FORMATION PRESSURE Normal Formation Pressure is equal to the hydrostatic pressure of water extending from the surface to the subsurface formation. Thus, the normal formation pressure gradient in any area will be equal to the hydrostatic pressure gradient of the water occupying the pore spaces of the subspace formations in that area. The magnitude of the hydrostatic pressure gradient is affected by the concentration of dissolved solids (salts) and gases in the formation water. Increasing the dissolved solids (higher salt concentration) increases the formation pressure gradient whilst an increase in the level of gases in solution will decrease the pressure gradient.. 1-4.

(10) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. For example, formation water with a salinity of 80,000 ppm sodium chloride (common salt) at a temperature of 25°C, has a pressure gradient of 0.465 psi/ft. Fresh water (zero salinity) has a pressure gradient of 0.433 psi/ft. Temperature also has an effect as hydrostatic pressure gradients will decrease at higher temperatures due to fluid expansion. In formations deposited in an offshore environment, formation water density may vary from slightly saline (0.44 psi/ft) to saturated saline (0.515 psi/ft). Salinity varies with depth and formation type. Therefore, the average value of normal formation pressure gradient may not be valid for all depths. For instance, it is possible that local normal pressure gradients as high as 0.515 psi/ft may exist in formations adjacent to salt formations where the formation water is completely salt-saturated. The following table gives examples of the magnitude of the normal formation pressure gradient for various areas. However, in the absence of accurate data, 0.465 psi/ft is often taken to be the normal pressure gradient.. Figure 1.3 Average Normal Formation Pressure Gradients Pressure psi/ft. Gradient (SG). Fresh water. 0.433. 1.00. Brackish water. 0.438. 1.01. Salt water. 0.442. 1.02. Most sedimentary basins worldwide. Salt water. 0.452. 1.04. North Sea, South China Sea. Salt water. 0.465. 1.07. Gulf of Mexico, USA. Salt water. 0.478. 1.10. Some area of Gulf of Mexico. Formation Water. Example area Rocky Mountains and Midcontinent, USA. 1-5.

(11) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. Figure 1.4. Porosity % 0. 10. 20. 30. 40. 50. 60. 70. 80. 0. 1000. Depth (metres). 2000. Permian Pennsylvania and Oklahoma (Athy) Lias Germany (Won Engelwardt). 3000. Miocene and Pliocene Po Valley (Storer) Tertiary Gulf Coast (Dickinson). 4000. Tertiary Japan (Magara) Joides. 5000. Reduction in clay porosity as a function of depth (modified from Magara, 1978). 1-6.

(12) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. 1.5 ABNORMAL PRESSURE Every pressure which does not conform with the definition given for normal pressure is abnormal. The principal causes of abnormal pressures are:1.5.1 Under-compaction in shales When first deposited, shale has a high porosity. More than 50% of the total volume of uncompacted clay-mud may consist of water in which it is laid. During normal compaction, a gradual reduction in porosity accompanied by a loss of formation water occur as the thickness and weight of the overlaying sediments increase. Compaction reduces the pore space in shale, as compaction continues water is squeezed out. As a result, water must be removed from the shale before further compaction can occur. See Fig 1.4. Not all of the expelled liquid is water, hydrocarbons may also be flushed from the shale. If the balance between the rate of compaction and fluid expulsion is disrupted such that fluid removal is impeded then fluid pressures within the shale will increase. The inability of shale to expel water at a sufficient rate results in a much higher porosity than expected for the depth of shale burial in that area. Figure 1.5a Quality of reservoir permeability.. Coarse-grained, well sorted Good permeability. Fine Grained. Poorly-sorted. Poor permeability. 1-7.

(13) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. Figure 1.5b 10000 8000 6000 4000. PERMEABILITY (md). 2000 1000 800 600 400 200 100 80 60 40 20. Coarse - and very coarse - grained Coarse - and medium - grained. 10 8 6 4. Fine - grained Silty Clayey. 2 1. 0. 2. 4. 6. 8. 10. 12. 14. 16. 18. 20. 22. 24. 26. 28. 30. 32. 34. POROSITY % The relationship between permeability and porosity (from Chilingar, 1964). Figure 1.5c WATER ESCAPE CURVE. WATER CONTENT OF SHALES. (SCHEMATIC) WATER AVAILABLE FOR MIGRATION. % WATER 0 10 20 30 40 50 60 70 80 SEDIMENT SURFACE PORE WATER. BURIAL DEPTH (SCHEMATIC). PORE AND INTERLAYER WATER EXPULSION 1st DEHYDRATION AND LATTICE WATER STABILITY ZONE. INTERLAYER WATER. LATTICE WATER STABILITY ZONE. 2nd DEHYD'N STAGE. INTERLAYER WATER ISOPLETH. 3rd DEHYDRATION STAGE. DEEP BURIAL WATER LOSS 'NO MIGRATION LEVEL'. Water Distribution Curves for Shale Dehydration. 1-8. 36.

(14) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. 1.5.2 Salt Beds Continuous salt depositions over large areas can cause abnormal pressures. Salt is totally impermeable to fluids and behave plastically. It deforms and flows by recrystallisation. Its properties of pressure transmission are more like fluids than solids, thereby exerting pressures equal to the overburden load in all directions. The fluids in the underlying formations cannot escape as there is no communication to the surface and thus the formations become over pressured. 1.5.3 Mineralisation The alteration of sediments and their constituent minerals can result in variations of the total volume of the minerals present. An increase in the volume of these solids will result in an increased fluid pressure. An example of this occurs when anhydrite is laid down. If it later takes on water crystallisation, its structure changes to become gypsum, with a volume increase of around 35%. 1.5.4 Tectonic Causes Is a compacting force that is applied horizontally in subsurface formations. In normal pressure environments water is expelled from clays as they are being compacted with increasing overburden pressures. If however an additional horizontal compacting force squeezes the clays laterally and if fluids are not able to escape at a rate equal to the reduction in pore volume the result will be an increase in pore pressure. Figure 1.6. EXTENSION. EXTENSION. COMPRESSION. COMPRESSION. COMPRESSION. COMPRESSION. Amount of Shortening. POSSIBLE OVERPRESSURED ZONES. Abnormal Formation Pressures caused by Tectonic Compressional Folding 1-9.

(15) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. 1.5.5 Faulting Faults may cause abnormally high pressures. Formation slippage may bring a permeable formation laterally against an impermeable formation preventing the flow of fluids. Nonsealing faults may allow fluids to move from a deeper permeable formation to a shallower formation. If the shallower formation is sealed then it will be pressurised from the deeper zone. Figure 1.7. IMPERVIOUS SHALE. GAS OIL. WATER. This is a trap resulting from faulting in which the block on the right has moved up with respect to the one on the left.. 1.5.6 Diapirism A salt diapirism is an upward intrusion of salt to form a salt dome. This upthrust disturbs the normal layering of sediments and over pressures can occur due to the folding and faulting of the intruded formations.. Cap Rock Gas Oil Water. Water. Salt. Figure 1.8. Salt domes often deform overlying rocks to form traps like the one shown here.. 1.5.7 Reservoir Structure Abnormally high pressures can develop in normally compacted rocks. In a reservoir in which a high relief structure contains oil or gas, an abnormally high pressure gradient as measured relative to surface will exist as shown in the following fig: a OIL. Gas-Oil Contact (GOC). Gas Closure. Oil. Oil-Water Contact (OWC). Water Spill Point. b Gas Water. WATER. Figure 1.9a. Figure1.9b An anticlinal type of folded structure is shown here. Anticline differs from a dome in being long and narrow.. 1 - 10. Gas-Water Contact (GWC). Gas-Oil Contact (GOC). Gas Oil. Trap nomenclature (a) in a simple structural trap and (b) in stratigraphic traps. Note that the size of the stratigraphic trap on the left is limited only by its petroleum content, while the size of the trap on the right is self-limiting..

(16) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. 1.5.8 Typical types of hydrocarbon traps versus percentage of world total.. Major types of oil traps and percentage of world’s petroleum occurrence for each. 75%. 1%. Anticlines. Faults. 2%. Salt Diapirs. 3%. Unconformity. Structural Traps. 7%. 9%. Other Stratigraphic. Combination. 3%. Reef. Stratigraphic Traps. Combination Traps. Figure 1.10 1.5.9 Typical hydrocarbon seals versus percentage of world total. Types of seals and percentage of world’s petroleum occurrence for each. 65% 33% 2%. Shale. Evaporite (salt). Carbonate (limestone & dolomite). Figure 1.11. 1 - 11.

(17) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. 1.6 FORMATION FRACTURE PRESSURE In order to plan to drill a well safely it is necessary to have some knowledge of the fracture pressures of the formation to be encountered. The maximum volume of any uncontrolled influx to the wellbore depends on the fracture pressure of the exposed formations. If wellbore pressures were to equal or exceed this fracture pressure, the formation would break down as fracture was initiated, followed by loss of mud, loss of hydrostatic pressure and loss of primary control. Fracture pressures are related to the weight of the formation matrix (Rock) and the fluids (water/oil) occupying the pore space within the matrix, above the zone of interest. These two factors combine to produce what is known as the overburden pressure. Assuming the average density of a thick sedimentary sequence to be the equivalent of 19.2 ppg then the overburden gradient is given by: 0.052 x 19.2 = 1.0 psi/ft Since the degree of compaction of sediments is known to vary with depth the gradient is not constant. NORMAL COMPACTION Abnormally High Pressure Due to Hydrocarbon Column 0. 1. Pressure on the Gas-Water Contact. = 2790 psi. 2. Less Gas Column Pressure = 0.10 x 1000’ = 100 psi. 1. 3. Pressure at top of Sand = 2690 psi 4. Abnormal Gradient at top Sand 2690 psi ––––––– = 0.538 psi/ft 5000 ft. 4. DEPTH - 1000 ft. 5 1000’. GAS GRADIENT = 0.10 psi/ft. 6. WATER. Normal pressure at the Gas-Water contact .465 x 6000’ = 2790 psi. 7. 8. 9. Figure 1.12. 1 - 12.

(18) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. Onshore, since the sediments tend to be more compacted, the overburden gradient can be taken as being close to 1.0 psi/ft. Offshore, however the overburden gradients at shallow depths will be much less than 1.0 psi/ft due to the effect of the depth of seawater and large thicknesses of unconsolidated sediment. This makes surface casing seats in offshore wells much more vulnerable to break down and is the reason why shallow gas kicks should never be shut in. See Fig 1.13. Fracture Gradient Comparisons (for illustration purposes only). A. B. 0 ft Hydrostatic due to sea water 1500 x 0.445 = 667.5 psi. 1500 ft Pressure due to overburden 3000 x 1.0 = 3000 psi Pressure due to overburden 1500 x 1.0 = 1500 psi. 3000 ft Total Overburden 2167.5 psi (0.723 psi/ft). Total Overburden 3000 psi (1.0 psi/ft). C. D 0 ft. Hydrostatic due to sea water 1500 x 0.445 = 667.5 psi. 1500 ft. Pressure due to overburden 12000 x 1.0 = 12000 psi Pressure due to overburden 10500 x 1.0 = 10500 psi. 12000 ft Total Overburden 11167.5 psi (0.93 psi/ft). Total Overburden 12000 psi (1.0 psi/ft). Figure 1.13. 1 - 13.

(19) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. 1.7 LEAK-OFF TESTS The leak-off test establishes a practical value for the input into fracture pressure predictions and indicates the limit of the amount of pressure that can be applied to the wellbore over the next section of hole drilled. It provides the basic data needed for further fracture calculations and it also tests the effectiveness of the cement job. The test is performed by applying an incremental pressure from the surface to the closed wellbore/casing system until it can be seen that fluid is being injected into the formation. Leak-off tests should normally be taken to this leak-off pressure unless it exceeds the pressure to which the casing was tested. In some instances as when drilling development wells this might not be necessary and a formation competency test, where the pressure is only increased to a predetermined limit, might be all that is required. 1.7.1 Leak-Off Test Procedure: Before starting, gauges should be checked for accuracy. The upper pressure limit should be determined.. 1 - 14. 1). The casing should be tested prior to drilling out the shoe.. 2). Drill out the shoe and cement, exposing 5 - 10 ft of new formation.. 3). Circulate and condition the mud, check mud density in and out.. 4). Pull the bit inside the casing. Line up cement pump and flush all lines to be used for the test.. 5). Close BOPs.. 6). With the well closed in, the cement pump is used to pump a small volume at a time into the well typically a 1/4 or 1/2 bbl per min. Monitor the pressure build up and accurately record the volume of mud pumped. Plot pressure versus volume of mud pumped.. 7). Stop the pump when any deviation from linearity is noticed between pump pressure and volume pumped.. 8). Bleed off the pressure and establish the amounts of mud, if any, lost to the formation..

(20) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. EXAMPLES OF LEAK-OFF TEST PLOT INTERPRETATION In non-consolidated or highly permeable formations fluid can be lost at very low pressures. In this case the pressure will fall once the pump has been stopped and a plot such as that shown in Fig 1.14a will be obtained. Figs 1.14b and 1.14c show typical plots for consolidated permeable and consolidated impermeable formations respectively. b) Consolidated Permeable Formations. PRESSURE. PRESSURE. a) Unconsolidated Formations. CUMULATIVE VOLUME. CUMULATIVE VOLUME. c) Consolidated Impermeable Formations. Final Pumping Pressure After Each Volume Increment. PRESSURE. Final Static Pressure After Each Volume Increment Leak-off Point. CUMULATIVE VOLUME. IDEALISED LEAK-OFF TEST CURVES. Figure 1.14 1 - 15.

(21) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. Working example of leak-off test procedure (floating rigs) “Operational Drilling Procedures for Floating Rigs” is designed to determine the equivalent mud weight at which the formation will accept fluid. This test is not designed to break down or fracture the formation. This test is normally performed at each casing shoe. Prior to the formation leak-off, have “handy” a piece of graph paper (see graph 1 ), pencil and straight edge (ruler). Utilising the high pressure cement pumping unit, perform leak-off as follows:. 1 - 16. 1.. Upon drilling float equipment, clean out rat hole and drill 15 ft of new hole. Circulate and condition hole clean. Be assured mud weight in and mud weight out balance for most accurate results.. 2.. Pull bit up to just above casing shoe. Install circulating head on DP.. 3.. Rig up cement unit and fill lines with mud. Test lines to 2500 psi. Break circulation with cementing unit, be assured bit nozzles are clear. Stop pumping when circulation established.. 4.. Close pipe rams. Position and set motion compensator, overpull drillpipe (+/- 10,000 lbs), close choke/kill valves.. 5.. At a slow rate (i.e. 1/4 or 1/2 BPM), pump mud down DP.. 6.. a.. Pump 1/4 bbl - record/plot pressure on graph paper.. b.. Pump 1/4 bbl - record/plot pressure on graph paper.. c.. Pump 1/4 bbl - record/plot pressure on graph paper.. d.. Pump 1/4 bbl - record/plot pressure on graph paper.. e.. Pump 1/4 bbl - record/plot pressure on graph paper.. f.. Continue this slow pumping. Record pressure at 1/4 bbl increments until two points past leak-off. (See examples, Graph 1, 2 & 3.). g.. Upon two points above leak-off, stop pumping. Allow pressure to stabilize. Record this stabilized standing pressure (normally will stabilize after 15 mins or so)..

(22) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. h.. Bleed back pressure into cement unit tanks. Record volume of bleed back.. i.. Set and position motion compensator, open rams.. j.. Rig down and cement unit lines. Proceed with drilling operations.. k.. Leak-off can be repeated after step 6 if data confirmation is required, otherwise leak-off test is complete.. NOTE: For 20" and 13 3/8" csg leak-off tests, plot pressure every 1/2 bbl. Results will be the same. It should be noted that in order to obtain the proper leak-off and pumping rate plot, it will be necessary to establish a continuous pump rate at a slow rate in order to allow time to read the pressure and plot the point on the graph. (Barrels pumped vs. pressure - psi), normally 1/2 BPM is sufficient time. A pressure gauge of 0-2000 psi with 20 or 25 increments is recommended. NOTE: In the event Standing Pressure is lower than leak-off point. Use standing pressure to calculate equivalent mud weight. Always note volume of mud bled back into tanks.. 1.7.2 Formation Breakdown Pressure (psi) = hydrostatic pressure of mud in casing + applied surface pressure = (mud wt. x constant x vert shoe depth) + surface pressure The formation breakdown pressure can be expressed as a GRADIENT. Formation Breakdown Pressure (psi) Formation Breakdown Gradient (psi/ft) = –––––––––––––––––––––––––––––– Vert. Shoe Depth (ft) The formation breakdown gradient expressed as a maximum allowable mud weight: Maximum Allowable Mud Weight (ppg) = Formation Breakdown Gradient (psi/ft) ÷ 0.052 or Formation Breakdown Pressure (psi) Maximum Allowable Mud Weight (ppg) = –––––––––––––––––––––––––––––– ÷ 0.052 Vert Shoe Depth (ft). 1 - 17.

(23) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. Graph 1.1 Formation Pressure Test Work Sheet. 1100. 1000. 900. SURFACE TEST PRESSURE - PSI. 800. 700. 600. 500. 400. 300. NOTE: Commence measuring volume NOTE: after pressuring up to 200 psi NOTE: Pump at a 0.3 BPM rate and NOTE: plot pressures and volumes NOTE: (BBL's MUD). 200. 100. 0 0. 1. 2. 3. 4. 5. 6. 7. 8. 9. BARRELS MUD PUMPED. 1 - 18. 10. 11. 12. 13. 14.

(24) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. Graph 1.2. Typical Pressure Test csg set at 5000' TVD w/12 lb mud in hole.. 1100. Required Test Pressure (Equivalent to 16,0 Mud). 1000. 900. 705 psi 5 min stabilized pressure. SURFACE TEST PRESSURE - PSI. 800. 700. 600. 500. 400. 300. NOTE: Commence plotting pressure NOTE: and pumped volume after NOTE: pressuring up to 200 psi. 200. 100. 0 0. 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. BARRELS MUD PUMPED. 1 - 19.

(25) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. Graph 1.3 Typical Pressure Plot for Formation Breakdown and Fracture Propagation. Formation Breakdown Pressure. 1100. Leak-off Pressure. 1000. 900. SURFACE TEST PRESSURE - PSI. 800. 700. 600. 500. 400. 300. NOTE: Commence plotting pressure NOTE: and pumped volume after NOTE: pressuring up to 200 psi. 200. 100. 0 0. 1. 2. 3. 4. 5. 6. 7. 8. 9. BARRELS MUD PUMPED. 1 - 20. 10. 11. 12. 13. 14.

(26) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. 1.8 MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE - MAASP. The leak-off test was used to determine the strength of the formations below the casing shoe. The Formation Breakdown Pressure = an applied surface pressure + hydrostatic pressure of mud in the casing The applied surface pressure at which leak-off occurred is the maximum allowable annular surface pressure with the mud weight in use at that time. MAASP is the maximum surface pressure that can be tolerated before the formation at the shoe fractures. MAASP = Formation Breakdown pressure at shoe – Hydrostatic Pressure of mud in use in the casing shoe or rewritten as: MAASP = (Fracture gradient – Mud gradient) x True Vert. Shoe Depth or as: MAASP = (Max equiv. mud wt. – Mud wt. in casing) x (0.052 x True Vert. shoe depth) MAASP is only valid if the casing is full of the original mud, if the mud weight in the casing is changed MAASP must be recalculated. The calculated MAASP is no longer valid if influx fluids enter into the casing.. 1.9 CASING SETTING DEPTHS The choice of setting depths for all the casing strings is a vital part of the well planning process. An incorrect decision with the casing setting depths too shallow could have serious consequences. An unnecessarily deep setting depth could have adverse economic consequences when considering the extra time needed to drill the hole deeper and the extra amount of casing required to be run and cemented.. Seabed 30" Casing (Conductor) 36" Hole 20" Casing (Surface String.) 26" Hole. 13 1/8" Casing (Intermediate String) 17 1/2" Hole. 9 5/8" Casing (Production String) 12 1/4" Hole. Figure 1.15 Typical Offshore Casing Program. 7" Liner 8 1/2" Hole. 1 - 21.

(27) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. 1.9.1 Deep Casing Setting Depths The selection of deeper casing setting depths will use different criteria to those used for shallow casing seats. Initial selection of the setting depth is made with reference to the anticipated lithological column, formation pressure and fracture gradient profiles. Once all the information has been collated from offset well data a plot similar to that shown in Fig 1.16 can be drawn up. By studying the geology and pressure profiles, tentative setting depths can be chosen based on the prevention of formation breakdown by mud weights in use in the subsequent hole section. See Fig 1.17. From a Well Control point of view, it is necessary to determine whether this tentative setting depth will give adequate protection against formation breakdown when a kick is taken. A kick tolerance “factor” will normally be applied. Preferred Setting Depths. Required Setting Depths. (based on lithological column) (to prevent formation fracture due to weight of mud column) 0. 0. Fracture Gradient. 2. 2. Fracture Gradient 4. Depth x 1000 ft. Depth x 1000 ft. 4. 6. 8. 6. 10. 10. Pore Pressure Gradient. Pore Pressure Gradient 12. 12. 14. 14. 8.0. 10.0. 12.0. 14.0. 16.0. 18.0. Pressure Gradient - lb/gal Equivalent. PRESSURE PROFILE PREDICTIONS. Figure 1.16. 1 - 22. Proposed Mud Weight program. 8. 20.0. 8.0. 10.0. 12.0. 14.0. 16.0. 18.0. 20.0. Pressure Gradient - lb/gal Equivalent. PRESSURE PROFILES WITH CASING SETTING DEPTHS. Figure 1.17.

(28) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. 1.10 CIRCULATING PUMP PRESSURE The pressure provided by the rig pump is the sum of all of the individual pressures in the circulating systems. All the pressure produced by the pump is expended in this process, overcoming friction losses between the mud and whatever it is in contact with: • • • •. Pressure loss in surface lines Pressure loss in drill-string Pressure loss across but jets Pressure loss in annulus. Pressure losses are independent of hydrostatic and imposed pressures. Pressure losses in the annulus acts as a “back pressure” on the exposed formations, consequently the total pressure at the bottom of the annulus is higher with the pump on than with the pump off. Circulating bottom hole pressure. =. Static bottom hole pressure +. STATIC Formation will Kick. Annulus pressure losses. CIRCULATING Formation under Control. 0 psi. 3000 psi. Annulus Pressure Loss = 250 psi 10 ppg MUD. BHP = 5200 psi. BHP = 5450 psi 10000’. 5300 psi. Formation Pressure Figure 1.18. 5300 psi. 1 - 23.

(29) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. The total pressure on bottom can be calculated and converted to an equivalent static mud weight which exerts the same pressure. Equivalent Mud Wt (ppg) = (APL + Pmud ) ÷ 0.052 ÷ TVD a or APL Equivalent Mud wt E.C.D = Mud Wt in use + –––––––––– 0.052 X TVD Where:. APL P. muda. = =. Annulus Pressure Loss Hydrostatic Mud Pressure in Annulus. Circulating pressure will be affected if the pump rate or the properties of the fluid being circulated are changed. Example:Assuming a circulating pump pressure is 3000 psi when pumping at 100 spm. The pump speed is increased to 120 spm. To approximate the new circulating pump pressure: P(2) = P(1) x Where:-. (. New Pump Speed 2 ––––––––––––––––– Original Pump Speed. ). P(1) = Original pump pressure at original pump speed. P(2) = New circulating pressure at new pump speed.. P(2) = 3000 x. ( ). 120 2 –––– 100. P(2) = 4320 psi at 120 spm. Example:Assuming a circulating pump pressure in 3000 psi with a 10 ppg mud weight pumping at 100 spm. If the mud weight in the system was changed to 12 ppg. To approximate the new circulating pump pressure: P(2) = P(1) x. New Mud Weight –––––––––––––––– Original Mud Weight. 12 P(2) = 3000 x ––– 10. P(2) = 3600 psi when circulating with 12 ppg mud. Note:. 1 - 24. Changing either pump speed or mud weight will affect annulus pressure losses..

(30) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. 1.11 CHOKE LINE FRICTION LOSSES IN SUBSEA KILL OPERATIONS Figure 1.19 In subsea situations, a pressure loss exists when circulating through the choke due to the friction losses in the extended choke line running up from the BOP. This pressure loss is not accounted for in normal Slow Circulating Rate (SCR) measurements, which are taken while circulating up the marine riser (see Fig 1.19).. 500 PSI. SHAKERS. If the normal method of bringing pumps to kill speed is followed (that is, choke manifold pressure maintained equal to SICP until kill rate is achieved), bottom hole pressure will be increased by an amount equal to this choke line friction loss (CLFL). This excess pressure can result in serious lost circulation problems during the kill operations. Since fracture gradients generally decrease with increased water depth, correct handling of the CLFL becomes more critical as water depth increases. Beyond approximately 500 feet water depth, it should always be considered while planning well control operations. It is possible to measure CLFL while taking SCR’s. One simple way to do this is to pump down the choke line at reduced pump rates (taking returns up the open marine riser as is shown in Figure 1.20) and record the pressure reading on the choke manifold gauge.. CONVENTIONAL SCF FLOW PATH. Figure 1.20 DRILL PIPE. CHOKE MANIFOLD. 0 PSI. 200 PSI CHOKE. SHAKERS. FROM PUMP. It is fundamental to all standard methods of well control to maintain constant bottom hole pressure (BHP) throughout kill operations. To accomplish this a method must be used to keep total applied casing pressures relatively constant while bringing the mud pump to kill rate. In the absence of significant CLFL (surface stacks or shallow water), the method used is to merely keep choke manifold pressure equal to SICP until the pump is up to speed. CLFL MEASUREMENT PUMPING DOWN CHOKE LINE CLCF = 200 PSI. 1 - 25.

(31) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. But when CLFL exists, total applied casing pressure varies from SICP at pump start-up to SICP + CLFL with the pump at kill rate, if the above method were used. This would cause bottom hole pressure to increase by an amount equal to CLFL, as shown in Figures 1.21 and 1.22 Figure 1.21. Figure 1.22. DRILL PIPE. CHOKE MANIFOLD. DRILL PIPE. CHOKE MANIFOLD. 800 PSI. 1000 PSI. 1500 PSI. 1000 PSI. CHOKE. CHOKE. RETURNS CLFL 0 PSI (STATIC) SUBSEA BOP. SUBSEA BOP. APL 0 PSI. BHP 6000 PSI. Pf = 6000 psi Ph = 5200 psi (in annulus) PUMPS OFF (kick shut in). 1 - 26. CLFL 200 PSI (DYNAMIC). APL NEGLIGIBLE. BHP 6200 PSI. Pf = 6000 psi Ph = 5200 psi (in annulus) PUMP AT KILL RATE HOLDING CONSTANT CHOKE MANIFOLD PRESSURE CHANGE IN BHP = 200 psi increase.

(32) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. Figure 1.23 To eliminate this problem, two methods exist. First, by reducing choke manifold pressure by an amount equal to a known CLFL (adjusting choke manifold pressure to SICP -CLFL), the effect of the CLFL is negated. This is accomplished by reducing the original SICP by the amount of CLFL while bringing the pumps to speed (see Figure 1.23). Once kill rate pressure has been established, the choke operator switches over to the drill pipe gauge and follows the drill pipe pressure graph in the usual way. Or secondly, given a choke manifold configuration with separate pressure gauges for choke and kill lines, it is possible to utilise the kill line (shut off down-stream of the gauge outlet to prevent flow, thus eliminating friction) as a pressure connection to a point upstream of any potential CLFL (known or unknown). This is shown in Figure 1.24. If the kill line gauge in this instance is kept constant while bringing the pump to speed, the effect of CLFL is eliminated.. DRILL PIPE. CHOKE MANIFOLD. 1300 PSI. 800 PSI CHOKE. RETURNS CLFL 200 PSI (DYNAMIC). SUBSEA BOP. APL NEGLIGIBLE. BHP 6000 PSI. Pf = 6000 psi Ph = 5200 psi (in annulus) PUMP AT KILL RATE WITH REDUCED CHOKE MANIFOLD PRESSURE CHANGE IN BHP = 0 psi increase. Figure 1.24 Note the advantages of the second method: 1.. The gauge reading choke manifold pressure will show a decrease after pump is up to speed. The amount of this decrease is equal to the CLFL.. 2.. No precalculated or pre-measured CLFL information is required.. 3.. The kill line gauge can be subsequently used like the choke manifold pressure gauge on a surface stack for the purposes of altering pump rates or problem analysis.. NOTE: If the second method of handling the CLFL situation is preferred, it would be advisable to rig a remote kill line pressure gauge which could be seen by the choke operator.. 1000 PSI. DRILL PIPE. CHOKE MANIFOLD. 1300 PSI. 800 PSI CHOKE. RETURNS KLFL 0 PSI (STATIC). SUBSEA BOP. CLFL 200 PSI (DYNAMIC). APL NEGLIGIBLE. BHP 6000 PSI. Well shut in Pf = 6000 psi Ph = 5200 psi (in annulus) PUMP AT KILL RATE HOLDING CONSTANT KILL LINE PRESSURE READING CHANGE IN BHP = 0 psi increase. 1 - 27.

(33) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. It is extremely important to note that regardless of which method is used, they both accomplish the goal of maintaining constant bottom hole pressure equal to formation pressure, just as would be the case were CLFL absent. This is done without the need to alter any calculations on the kick sheet. Thus initial and final circulating pressures, which are read on the drill pipe gauge, are unaffected by CLFL. CLFL is recorded on the Kick Sheet for convenience only – it is not used in kick sheet calculations. Several additional points should be made about CLFL. It should be noted that it will only be possible to use the above recommended methods when SICP is greater than CLFL. If this is not true, it will be unavoidable to apply excess pressure to the bottom of the hole using standard well control procedures. Also, as kill mud comes up the annulus, total applied casing pressure needed to maintain constant bottom hole pressure will eventually drop below CLFL. After this point, drill pipe pressures will exceed planned Final Circulating Pressure in spite of having the choke wide open with no choke manifold back pressure.. Figure 1.25 DRILL PIPE. CHOKE MANIFOLD. 75 PSI. 100 PSI CHOKE. SUBSEA BOP. CLFL 0 PSI (STATIC). APL 0 PSI. BHP 5200 PSI. Pf = 5200 psi Ph = 5100 psi (in annulus) PUMPS OFF (kick shut in) FCP @ 4 bbl/min = 400 psi FCP @ 2 bbl/min = 200 psi CLFL @ 4 bbl/min = 200 psi CLFL @ 2 bbl/min = 60 psi. Figure 1.26 These situations can be mitigated by use of unusually slow pumping rates or by taking returns up choke and kill lines simultaneously. Figures 1.25 - 1.28 illustrate this problem and methods of dealing with it. They show an example in which a static SICP of 100 psi is reduced while pumping as result of the increase in back pressure created in circulating up the choke line, by itself or choke and kill lines together.. DRILL PIPE. CHOKE MANIFOLD. 575 PSI. 0 PSI CHOKE. RETURNS. SUBSEA BOP. CLFL 200 PSI (DYNAMIC). APL NEGLIGIBLE. Fig 24: Pumping 4 bbl/min with choke wide open. Note increase in BHP due to excess CL friction.. 1 - 28. BHP 5300 PSI. Pf = 5200 psi Ph = 5100 psi (in annulus) PUMP AT 4 BBL/MIN HOLDING 0 PSI CHOKE MANIFOLD PRESSURE CHANGE IN BHP = 100 psi increase. a.

(34) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. Fig 1.27: Pump rate reduced to bbl/min. BHP is held constant at SICP - CLFL. Fig 1.28: By taking flow up choke and kill lines simultaneously, the same effect is achieved as in fig 1.27, but at a pumping rate of 4 bbl/min.. Figure 51.27. Figure 1.28. DRILL PIPE. CHOKE MANIFOLD. 275 PSI. 40 PSI. CHOKE MANIFOLD. 475 PSI. 40 PSI. 40 PSI. CHOKE. RETURNS. SUBSEA BOP. DRILL PIPE. CLFL 60 PSI (DYNAMIC). CHOKE. CHOKE. RETURNS. RETURNS. KLFL 60 PSI (DYNAMIC). 2 BBL/MIN. 2 BBL/MIN. SUBSEA BOP. CLFL 60 PSI (DYNAMIC). 4 BBL/MIN. APL NEGLIGIBLE. BHP 5200 PSI. Pf = 5200 psi Ph = 5100 psi (in annulus) PUMP AT 2 BBL/MIN WITH REDUCED CHOKE MANIFOLD PRESSURE CHANGE IN BHP = 0 psi increase. APL NEGLIGIBLE. BHP 5200 PSI. Pf = 5200 psi Ph = 5100 psi (in annulus) PUMP AT 4 BBL/MIN USING CHOKE AND KILL LINES FOR RETURN FLOW CHANGE IN BHP = 0 psi. 1 - 29.

(35) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. 1.12 - WORKSHOP 1 SCORE 1.. Convert the following mud densities into pressure gradients. a. 13.5 ppg b. 16 ppg c. 12 ppg. 2.. _____________ ppg _____________ ppg _____________ ppg. 2. Calculate the hydrostatic pressure for the following. a. 9.5 ppg mud at 9000ft MD/8000 ft TVD =_____________ b. 15.5 ppg mud at 18000ft TVD/21000ft MD =_____________ c. 0.889 psi/ft mud at 11000ft MD/9000ft TVD =_____________. 4.. =_____________ =_____________ =_____________. 2. High bottom hole temperatures could affect the hydrostatic pressure gradients resulting in: a. An increase in the hydrostatic gradient b. A decrease in the hydrostatic gradient c. Would have no effect. 1 - 30. 2. Convert the following pressures into equivalent mud weights in PPG. a. 3495 psi at 7000ft b. at 4000ft with 2787 psi c. 12000ft MD/10500ft TVD with 9000 psi. 5.. 2. Convert the following gradients into mud densities. a. 0.806 psi/ft b. 0.598 psi/ft c. 0.494 psi/ft. 3.. _____________ psi/ft _____________ psi/ft _____________ psi/ft. 2.

(36) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. SCORE 6.. Assuming a 10 ppg mud is being circulated at 700 GPM at a depth of 10000ft TVD/MD the circulating pump pressure is 3000 psi. If the circulating friction losses in the system are as follows: Pressure losses through pipe/collars Pressure loss across the bit jets Pressure loss in the annulus a.. 1200 psi 1600 psi 200 psi. When circulating what is the dynamic bottom hole pressure? Answer...................... b.. What is the static bottom hole pressure? Answer...................... c.. 2. Referring to the data given above, if the mud weight being circulated at 700 GPM was 12 ppg rather than 10 ppg, what would pump pressure be? Answer....................... 7.. 2. Will this increase in the pump speed have any effect on bottom hole pressure? Answer YES/NO. f.. 2. If the pump speed is increased to give 800 GPM, what will the pump pressure be? Answer...................... e.. 2. What is the equivalent circulating density ECD? Answer...................... d.. 2. 2. When circulating a 12 ppg mud at 10000ft ECD is 12.3 ppg. What is the annular pressure loss? Answer....................... 2. 1 - 31.

(37) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. SCORE 8.. Calculate the pressure that one barrel of 12 ppg mud Wt exerts. a.. Around the drill collars if the annular capacity is 0.03 bbls/ft. Answer....................... b.. Around the drill pipe if the annular capacity is 0.05 bbls/ft. Answer....................... 9.. Annular-pressure loss =. where. YP L DH DP. = = = =. 4. YP x L ————— 200(DH-DP). Yield point of mud in lbs/100ft2 Length of annulus, collar or pipe Hole diameter Collar or pipe diameter. If a formation pore pressure gradient at 8500ft is 0.486 psi/ft, what mud weight is required to give an over-balance of 200 psi? Answer....................... WORKSHOP 1 - Answers 1 - 32. 2. Drilling at 12700ft with an 8 1/2" bit, the drill pipe is 5" with 700ft of 6 1/2" collars. The mud weight = 12 ppg. The yield point of the mud is 12lbs/100ft2. Use the equation given below to determine ECD. Answer....................... 12.. 2. If a 12 ppg mud over-balances the formation pressure by 240 psi theoretically how far could the mud level fall before going under-balance? Answer........................ 11.. 2. If the fluid level in a well bore fell by 480ft, what is the reduction in bottom hole pressure if the mud weight is 12 ppg? Answer....................... 10.. 2. 2.

(38) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. WORKSHOP 1 - Answers 1.. MUD WEIGHT x 0.052 a. b. c.. 2.. 0.702 psi/ft 0.832 psi/ft 0.624 psi/ft. 0.806 ÷ 0.052 0.598 ÷ 0.052 0.494 ÷ 0.052. = = =. 15.5 ppg 11.5 ppg 9.5 ppg. T.V.D. x MUD WEIGHT x 0.052 a. b. c.. 4.. = = =. GRADIENT ÷ 0.052 a. b. c.. 3.. 13.5 x 0.052 16.0 x 0.052 12.0 x 0.052. 8000 x 9.5 x .052 18000 x 15.5 x .052 9000 x 0.889. = = =. 3952 psi 14508 psi 8001 psi. = = =. 9.6 ppg 13.39 ppg (13.4) 16.48 ppg (16.5). PRESS ÷ T.V.D ÷ .052 a. b. c.. 3495 ÷ 7000 ÷ .052 2787 ÷ 4000 ÷ .052 9000 ÷ 10500 ÷ .052. 5.. b.. 6.. (T.V.D. x MUD WT x .052) + A.P.L. a. b. c. d.. Note d.. (10000ft x 10ppg x .052) + 200 10000 x 10 x .052 5400 ÷ 10000 ÷ .052 3000 x (800)2 —— (700). = = = =. 5400 psi 5200 psi 10.38 ppg 3918 psi. This calculation is the same relationship as Press-Strokes-Relationship. (i.e.) P x (new S.P.M)2 ————— (old S.P.M.). 1 - 33.

(39) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. e.. YES. f.. PRESS x (new MUD WT) ———————— (old MUD WT) 3000. 7.. A.P.L.. A.P.L.. 8.. 1 - 34. x (12) —— (10) = = = =. =. 3600 psi. (ECD - MUD WT) x (TVD x .052) (12.3 - 12) x (10000 x .052) .3 x 520 156 psi. MUD g psi/ft ——— ANN vol psi/ft a. =. 12 x .052. =. b. =. .624 psi/bbl —————— .05. 9.. 480 x 12 .052. =. 10.. PRESS - psi ——— MUD g psi/ft. =. .624 = —— .03. 20.8 psi/bbl. = 12.48 Psi/bbl. 299.52 psi (300 psi). 240 = —— .624ft. 384ft.

(40) WELL CONTROL for the Rig-Site Drilling Team SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL. 11.. A.P.L. around D/C. =. 12 x 700 = 21 psi ————— 200(8.5-6.5). A.P.L. around D/P. =. 12 x 12000 = 206 psi —————— 200 x (8.5 - 5). TOTAL A.P.L.. 12.. ECD. =. 12. ECD. =. 12.34 PPG. 8500 x .486. +. = 227psi. 227 —— ÷ .052 12700. = 4131 + 200 = 4331 psi. 4331 ÷ 8500 ÷ .052 = 9.79 ppg = (9.8 ppg). 1 - 35.

(41) SECTION 2 :. CAUSES OF KICKS Page. 2. 0. Objectives. 1. 2. 1. Introduction. 1. 2. 2. Primary Well Control- How it is Affected. 1. 2. 3. Causes of Kicks and Influxes. 6. 2. 4. Extracts From API RP59. 15. 2. 5. Workshop 2. 22.

(42) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. CAUSES OF KICKS 2.0 OBJECTIVES The objectives of this section are to Highlight the Causes of Kicks and Influxes.. 2.1 INTRODUCTION Primary control is defined as using the drilling fluid to control formation fluid pressure. The drilling fluid has to have a density that will provide sufficient pressure to overbalance pore pressure. If this overbalance is lost, even temporarily then formation fluids can enter the wellbore. Preventing the loss of primary control is of the utmost importance. Definition of Kick A kick is an intrusion of unwanted fluids into the wellbore such that the effective hydrostatic pressure of the wellbore fluid is exceeded by the formation pressure. Definition of Influx An influx is an intrusion of formation fluids into the wellbore which does not immediately cause formation pressure to exceed the hydrostatic pressure of the fluid in the wellbore, but may do, if not immediately recognised as an influx, particularly if the formation fluid is gas.. 2.2 PRIMARY WELL CONTROL - HOW IT IS EFFECTED To ensure primary well control is in place the following procedures and precautions must be observed. Mud Weight Mud into and out of the well must be weighted to ensure the correct weight is being maintained to control the well. This task is normally carried out by the shaker man at least every thirty minutes or less, depending upon the nature of the drilling operation and/or company policy. The mud weight can be increased by increasing the solid content and decreased either by dilution or the use of solids control equipment. Tripping Procedures Tripping in or out of the well must be maintained using an accurate log called a trip sheet. A trip sheet is used to record the volume of mud put into the well or displaced from the well when tripping. A calibrated trip tank is normally used for the accurate measurement of mud volumes and changes to mud volumes while tripping. 2-1.

(43) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. Figure 2.1 Well Name. Trip No.. Date. Mud Weight. Fluid Loss. Depth. D.P. Size. D.P. Displacement. Time Trip Started. D.C. Size. D.C. Displacement. Number of Stands. DISPLACEMENT Theoretical Last Trip Per ___ Std.. Total. Per ___ Std.. If rig pump is used, calculate from strokes.. 2-2. Total. This Trip Per ___ Std.. Comments. Total. If trip tank is used, record level of decrease..

(44) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. When tripping pipe or drill collars out of the hole, a given volume of mud is put into the well for the volume of steel removed. If the volume required to fill the hole is significantly less than the volume of steel removed, then tripping must be stopped to ensure the well is stable, and consideration given to going back to bottom to condition the mud and investigate the cause of the problem. THE HOLE MUST BE KEPT FULL AT ALL TIMES A full opening or safety valve should be available at all times on the drill floor together with the required crossover subs. A non-return (i.e. grey) valve should also be readily available. Figure 2.3 Figure 2.2 NON RETURN SAFETY VALVE (GREY VALVE) FULL BORE OPENING SAFETY VALVE. RELEASE TOOL VALVE RELEASE ROD. Body. Upper Seat. Crank Ball VALVE SEAT. Lower Seat. VALVE SPRING. Trip Margin (Safety Factor) Trip Margin (Safety Factor) is an overbalance to compensate for the loss of ECD and to overcome the effects of swab pressures during a trip out of the hole.. 2-3.

(45) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. Flow Checks Flow checks are performed to ensure that the well is stable. Flow checks should be carried out with the pumps off to check the well with ECD effects removed. Flow checks are usually performed when a trip is going to take place at the following minimum places: •. on bottom. •. at the casing shoe. •. before the BHA is pulled into the BOP's. Short Trips/Wiper Trips In some circumstances prior to pulling out of the hole a short trip, 5 or 10 stands should be considered. The well is then circulated and mud returns carefully monitored. Pumping a Slug of Heavy Mud This is a practice often carried out to enable the pipe to be pulled dry and the hole to be more accurately monitored during the trip. The following equation is used to calculate the dry pipe volume for the slug pumped: Dry Pipe Volume = Slug Volume x (Slug Weight ÷ Mud Weight - 1) This dry pipe volume can be converted to Dry Pipe Length by dividing this volume by the internal capacity of the pipe as illustrated in the following equation: Dry Pipe Length = Dry Pipe Volume (bbls) ÷ Drill Pipe Capacity (bbls/ft) Mud Logging A logging unit if available is extremely important particularly with respect to well control. The unit carries out some of the following services:. 2-4. •. Gas detection in the mud. •. Gas analysis. •. Cuttings density analysis. •. Recording mud densities in and out. •. Recording flow line temperatures. •. Recording penetration rates. •. Pore Pressure Trends.

(46) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. A typical mud logging system is illustrated in Figure 2.4 below.. FIG 2.4 TYPICAL MUD LOGGING SYSTEM KELLY POSITION ROP WOB DEPTH KELLY HOSE SWIVEL. STAND PIPE STANDPIPE PRESSURE PUMP. KELLY. PUMP RATE. SUCTION SUCTION PIT FLOWLINE PIT LEVELS. SHALE SLIDE GAS QUANTITY GAS TYPE MUD TEMPERATURE RETURN MUD WEIGHT. P. R. O. E CE V S A S LU IN A G T A IO N N D. CUTTINGS DENSITY. SHAKER. • ROTARY SPEED • TORQUE. G. GIN OG L D MU UNIT. VDU IN COMPANY REP'S OFFICE. 2-5.

(47) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. Communication If a transfer of mud to the active system is requested the driller will be informed, the logging unit must likewise be informed. Good communication all round is essential. Alarms The high and low settings for the pit level recorder and flow line recorder must be checked and are set to appropriate values.. 2.3 CAUSES OF KICKS AND INFLUXES The most common causes of kicks are: •. Improper monitoring of pipe movement (drilling assembly and casing). -. Trip out - making sure hole takes the proper amount of mud. Trip in - making sure it gives up proper amount of mud and preventing lost circulation due to surges.. •. Swabbing during pipe movement.. •. Loss of circulation.. •. Insufficient mud weight. -. •. Abnormal pressured formations Shallow gas sands. Special situations. -. Drill stem testing Drilling into an adjacent well Excessive drilling rate through a gas sand. Surveys in the past have shown that the major portion of well control problems have occurred during trips. The potential exists for the reduction of bottom hole pressure due to:. 2-6. •. Loss of ECD with pumps off.. •. Reduction in fluid levels when pulling pipe and not filling the hole.. •. Swabbing..

(48) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. 2.3.1 FAILURE TO KEEP THE HOLE FULL DURING A TRIP If the fluid level in the hole falls as pipe is removed a reduction in bottom hole pressure will occur. If the magnitude of the reduction exceeds the trip margin or safety overbalance factor a kick may occur. The hole must be kept full with a lined up trip tank that can be monitored to ensure that the hole is taking the correct amount of mud. If the hole fails to take the correct mud volume, it can be detected. A trip tank line up is shown in Fig 2.5. BELL NIPPLE RETURN LINE. FLOAT. FILL UP LINE. TANK. INDICATOR PUMP. Figure 2.5. CONTINUOUS CIRCULATING TRIP TANK. It is of the utmost importance that drill crews properly monitor displacement and fill up volumes when tripping. The lack of this basic practice results in a large amount of well control incidents every year.. 2.3.2 SWABBING AND SURGING Swabbing is when bottom hole pressure is reduced below formation pressure due to the effects of pulling the drill string, which allows an influx of formation fluids into the wellbore. When pulling the string there will always be some variation to bottom hole pressure. A pressure loss is caused by friction, the friction between the mud and the drill string being pulled. Swabbing can also be caused by the full gauge down hole tools (bits, stabilisers, reamers, core barrels, etc.) being balled up. This can create a piston like effect when they are pulled through mud. This type of swabbing can have drastic effects on bottom hole pressure. 2-7.

(49) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. The factors affecting swabbing and surging are: •. Pulling speed of pipe.. •. Mud properties.. •. Viscosity.. •. Hole geometry.. Surging Surging is when the bottom hole pressure is increased due to the effects of running the drill string too fast in the hole. Down hole mud losses may occur if care is not taken and fracture pressure is exceeded while RIH. Proper monitoring of the displacement volume with the trip tank is required at all times. Figure 2.6. PRESSURE SURGES. SWABBING ACTION. Swabbing is a recognised hazard whether it is “low" volume swabbing or “high” volume swabbing. A small influx volume may be swabbed into the open hole section. The net decrease in hydrostatics due to this low density fluid will also be small. If the influx fluid is gas it can of course migrate and expand. The expansion may occur when there is little or no pipe left in the hole. The consequences of running pipe into the hole and into swabbed gas must also be considered. Pulling Speeds Tripping speeds must be controlled to reduce the possibility of swabbing. It is normal practice for the Mud Logger to run a swab and surge programme and to make this information available to the Driller. This will provide ample information to reduce the possibility of unforeseen influx occurring. 2-8.

(50) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. Mud Properties Controlling the rheology of mud is important. Controlling water-loss to avoid thick wall cake will also help. Trip Margin A safety factor to provide an overbalance to compensate for swab pressure can be: Trip Margin Factor APL psi ––––––––––––––––– = ––––––––––––––––– (psi/ft) True Vert. Depth. ft APL = Annulus Pressure Loss If swabbing has been detected and the well is not flowing a non return valve should be installed and the bit returned to bottom. Flow check each stand. Once back on bottom the well should be circulated and the bottoms up sample checked for contamination. If the well is flowing or the returns from the well are excessive when tripping in then the following should be carried out: •. Install a non return valve. If there is a strong flow then a kelly cock may have to be installed first.. •. Shut the well in.. •. Prepare for stripping.. •. Strip in to bottom.. •. Circulate the well, check bottoms up for contamination.. Continuous monitoring of replacement and displacement volumes is essential when performing tripping. A short wiper trip and circulating the well before pulling completely out of the hole will provide useful information about swabbing and pulling speeds. Useful formulae for calculating the psi reduction per foot of drill pipe pulled are as follows: (mud grad. (psi/ft) x metal disp. (bbls/ft)) Pulling Dry Pipe: psi/ft or dry pipe pulled = –––––––--––––––––––––--––––––––––––––– (casing cap. (bbls/ft) - metal disp. (bbls/ft)). ( (. ) ). (mud grad. (psi/ft) x metal disp. + cap. (bbls/ft) Pulling Wet Pipe: psi/ft or wet pipe pulled = –––––––--–––––––-–––––-–––––––––-–––––– (casing cap. (bbls/ft) - metal disp. + cap. (bbls/ft)). 2-9.

(51) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. 2.3.3 LOSS OF CIRCULATION Another cause for a kick to occur is the reduction of hydrostatic pressure through loss of drilling fluid to the formation during lost circulation. When this happens, the height of the mud column is shortened, thus decreasing the pressure on the bottom and at all other depths in the hole. The amount the mud column can be shortened before taking a kick from a permeable zone can be calculated by dividing the mud gradient into the overbalance at the top of the permeable kick zone.. H (ft) =. Overbalance (psi) –––––––––––––––––––––– Mud Gradient (psi/ft). 2.3.4 INSUFFICIENT MUD WEIGHT A kick can occur if a permeable formation is drilled which has a higher pressure than that exerted by the mud column. If the overpressurised formations have low permeability then traces of the formation fluid should be detected in the returns after circulating bottoms up. If the overpressured formations have a high permeability then the risk is greater and the well should be shut-in as soon as flow is detected.. 2.3.5 ABNORMAL PRESSURED FORMATIONS A further cause of kicks from drilling accidentally into abnormally pressured permeable zones. This is because we had ignored the warning signals that occur, these help us detect abnormal pressures. Some of these warning signals are: an increased penetration rate, an increase in background gas or gas cutting of the mud, a decrease in shale density, an increase in cutting size, or an increase in flow-line temperature, etc. In some areas, there were adequate sands that were continuous and open into the sea or to the surface. In these areas the water squeezed from the shale formations, travelled through the permeable sands and was released to the sea or to a surface outcrop. This de-watering allowed the formations to continue to compact and thereby increase their density.. 2 - 10.

(52) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. Figure 2.7. SEA. PERMEABLE ZONE. NORMAL PRESSURE. In other areas, or at other times, the sands did not develop or were sealed by deposition of salt or other impervious formations, or by faulting such as we have indicated here. Although the shale water was squeezed, it could not escape. Since water is nearly incompressible, the shales could not compress past the point where the water in the shale started to bear the weight of the rock above. This section caused a condition in which the weight of the formation - that is, the overburden was borne not by the shale alone, but assisted by the fluids in the shale. In this situation the shale will have more porosity, and a lower density, than they would have had if the now pressured water had been allowed to escape. These formations, both sand and shale, are then overpressured. If a hole is drilled into an overpressured formation, weighted mud will be required to hold back the fluids contained in the pore space. Figure 2.8. SEA. FAULT. ABNORMAL PRESSURE Abnormally high formation pressure is defined as any formation pressure that is greater than the hydrostatic pressure of the water occupying the formation pore spaces. Abnormally high formation pressures are also termed surpressures, overpressures and sometimes geopressures. More often, they are simply called abnormal pressures.. 2 - 11.

(53) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. Abnormally high formation pressures are found worldwide in formations ranging in age from the Pleistocene age (approximately 1 million years) to the Cambrian age (500 to 600 million years). They may occur at depths as shallow as only a few hundred feet or exceeding 20,000 ft and may be present in shale/sand sequences and/or massive evaporite-carbonate sequences. The causes of abnormally high formation pressures are related to a combination of geological, physical, geochemical and mechanical processes. As defined, the magnitude of abnormally high formation pressures must be greater than the normal hydrostatic pressure for the location, and may be as high as the overburden pressure. Abnormally high pressure gradients will thus be between the normal hydrostatic gradient (0.433 to 0.465 psi/ft) and the overburden gradient (generally 1.0 psi/ft). However, locally confined pore pressure gradients exceeding the overburden gradient by up to 40% are known in areas such as Pakistan, Iran, Papua New Guinea, and the CIS. These super pressures can only exist because the internal strength of the rock overlying the super pressured zone assists the overburden load in containing the pressure. The overlying rock can be considered to be in tension. In the Himalayan foothills of Pakistan, formation pressure gradients of 1.3 psi/ft have been encountered. In Iran, gradients of 1.0 psi/ft are common and in Papua New Guinea, a gradient of 1.04 psi/ft has been reported. In one area of Russia, local formation pressure in the range of 5870 to 7350 psi at 5250 feet were reported. This equates to a formation pressure gradient of 1.12 to 1.4 psi/ft. In the North Sea abnormal pressures occur with widely varying magnitudes in many geological formations. The Tertiary sediments are mainly clays and may be overpressured for much of their thickness. Pressure gradients of 0.52 psi/ft are common with locally occurring gradients of 0.8 psi/ft being encountered. An expandible clay (gumbo) also occurs which is of volcanic origin and is still undergoing compaction. The consequent decrease in clay density would normally indicate an abnormal pressure zone but this is not the case. However, in some areas, mud weights of the order of 0.62 psi/ft or higher are required to keep the wellbore open because of the swelling nature of these clays. This is almost equal to the low overburden gradients in these areas. In the Mesozoic clays of the North Sea Central Graben, overpressures of 0.9 psi/ft have been recorded. One reported case indicated a formation pressure gradient of 0.91 psi/ft in the Jurassic section. In the Jurassic of the Viking Graben, abnormal formation pressure gradients of up to 0.69 psi/ft have been recorded.. 2 - 12.

(54) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. In Triassic sediments, abnormally high formation pressures have been found in gas bearing zones of the Bunter Sandstone in the southern North Sea. Also in the southern North Sea, overpressures are often found in Permian carbonates, evaporates and sandstones sandwiched between massive Zechsteins salts.. 2.3.6 SHALLOW GAS SANDS Kicks from shallow sands (gas and water) whilst drilling in the top hole section with short casing strings can be very hazardous, as documented by many case histories. Some of the kicks from shallow sands are caused by charged formations: poor cement jobs, casing leaks, injection operations, improper abandonments, and previous underground blowouts can produce charged formations.. 2.3.7 SPECIAL SITUATIONS a) Drill Stem Testing (DST) The formation test is one of the most hazardous operations encountered in drilling and completing oil and gas wells. The potential for stuck tools, blowouts, lost circulations, etc., is greatly increased. A drill stem test is performed by setting a packer above the formation to be tested, and allowing the formation to flow. Down hole chokes can be incorporated in the test string to limit surface pressures and flow rates to the capabilities of the surface equipment to handle or dispose of the produced fluid. During the course of the test, the bore hole or casing below the packer, and at least a portion of the drill pipe or tubing, is filled with formation fluid. At the conclusion of the test, this fluid must be removed by proper well control techniques to return the well to a safe condition. Failure to follow the correct procedures to kill the well could lead to a blowout. b) Drilling Into an Adjacent Well Drilling into an adjacent well is a potential problem, particularly offshore where a large number of directional wells are drilled from the same platform. If the drilling well penetrates the production string of a previously completed well, the formation fluid from the completed well will enter the wellbore of the drilling well, causing a kick. If this occurs at a shallow depth, it is an extremely dangerous situation and could easily result in an uncontrolled blowout.. 2 - 13.

(55) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. c) Excessive Drilling Rate Through a Gas Sand/Limestone When drilling a gas bearing formation, the mud weight will be gas cut due to the gas breaking out of the pore space of the cuttings near the surface. The severity of the influx will depend on the penetration rate, porosity and permeability, and is independent of mud weight. The importance attached to gas cutting is that gas is entering the wellbore in small quantities, which calls for caution. Degassing is necessary to ensure that good mud is being pumped back into the hole to prevent the percentage of gas from increasing with each circulation, which would allow greater and greater bottom hole hydrostatic pressure reductions. Figure 2.9 Reduction in Hydrostatic Head Due to Gas Cutting of the Mud 18 ppg mud cut 50% to 9.0 ppg Depth. Normal Head 18 ppg mud. Reduced Head. Head Reduction. 1,000'. 936 psi. 866 psi. 60 psi. 5,000'. 4,680 psi. 4,598 psi. 82 psi. 10,000'. 9,360 psi. 9,265 psi. 95 psi. 20,000'. 18,720 psi. 18,615 psi. 105 psi. Most of mud cutting is close to surface. Divert flow through choke manifold to prevent belching and to safely contain gas through mud gas separator. Time drill the gas cap to prevent severe gas cutting of mud. Gas cutting alone does not indicate the well is kicking, unless it is associated with pit gain. Allowing the well to belch over the nipple could cause reduction in hydrostatic pressure to the point that the formation would start flowing, resulting in a kick.. 2 - 14.

(56) WELL CONTROL for the Rig-Site Drilling Team SECTION 2 : CAUSES OF KICKS. 2.4 EXTRACTS FROM API RP59 4.1 Introduction. Loss of primary well control most frequently results from: 1) failure to keep the hole full; 2) swabbing; 3) insufficient drilling fluid density; and/or 4) lost circulation. These problems can occur during any operation conducted on a well. The goal of well control is to prevent a well kick (influx of formation fluid into the wellbore) from becoming a blowout (uncontrolled flow of formation fluid). 4.2 Conditions Necessary for a Kick. The two conditions that must be present in the wellbore for a kick to occur are 1) the pressure in the wellbore at the face of the kicking formation must be less than the formation pressure; and 2) the kicking formation must have sufficient permeability to allow flow into the wellbore. To maintain primary well control, drilling personnel should utilise all techniques at their disposal to ensure that the hydrostatic pressure in the wellbore is always greater than the formation pressure. A number of conditions which can cause or contribute to well kicks are discussed in Paras 4.3 through 4.15. 4.3 Hole Not Full of Drilling Fluid. When the fluid level in the wellbore is allowed to drop or is maintained with a lighter density fluid, the resultant reduced hydrostatic head can allow fluid entry from the formation. The rig should have drilling fluid measuring devices to determine that proper fluid replacement or displacement occurs when pulling or running pipe. The type of fluid measuring equipment used should be influenced by the anticipated well control operations involved in drilling the well. 4.4 Tripping Out of the Hole. When pulling pipe, its displacement volume should be replaced with the proper amount of drilling fluid to maintain constant hydrostatic pressure. Any significant reduction in hydrostatic pressure may result in loss of primary control. If the hole fails to take the proper amount of drilling fluid, hoisting operations should be suspended and an immediate safe course of action determined while observing the well. This usually requires returning to bottom and circulating the hole. The frequency of filling the hole during tripping operations is critical in maintaining primary control. The hole should be completely filled at intervals that will prevent an influx of formation fluid. Continuous filling or filling after each stand of drill pipe may be advisable. The hole should be filled after each stand of drill collars. When the hole is filled continuously, an isolated drilling fluid volume measurement facility (such as a trip tank) must be used. 4.5 Tripping In the Hole. In running pipe back in the hole, the drilling fluid volume increase at the surface should be no greater than predicted displacement. Some holes take significant volumes of drilling fluid during trips because of seepage loss. It is necessary to keep a trip book (refer to Para. 10.3 and Table 10.1) for ready comparison to determine if an abnormal condition occurs. The gauging of fluid returns and comparison with prior trip records should provide a warning of possible loss of primary well control. The hole and fluid returns should be checked at frequent intervals. 2 - 15.

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