Chapter 4 2014

School of Petroleum Engineering, UNSW Open Learning - 2014

4-1

Chapter 4

PROCEDURES


4-2

CHAPTER 4

PROCEDURES

Contents Page No

Table of Illustrations 4 Table of Tables 5 Table of Graphs 6 Objectives 7

1.0 ALARM LIMITS 9

1.1 High And Low Pit Level 9 1.2 Return Flow Sensor 9 1.3 Trip Tank Level 10 1.4 Hydrogen Sulphide & Flammable Gases 10 2.0 PRE-RECORDED WELL CONTROL INFORMATION 14 2.1 Dynamic Pressure Loss 14 2.2 Well Configuration 16 2.3 Fracture Gradient 17 2.4 Initial Maximum Safe Casing Pressures 18 3.0 FLOW CHECKS 21 3.1 When Drilling 21 3.2 When Tripping 22 4.0 SHUT-IN PROCEDURES 23

4.1 Soft Shut-in While Drilling 23 4.2 Hard Shut-in While Drilling 23 4.3 Soft Shut-in While Tripping 23 4.4 Hard Shut-in While Tripping 24 4.5 Soft Shut-in While Running Casing 24 4.6 Hard Shut-in While Running Casing 24 4.7 Soft Shut-in While Cementing 24 4.8 Hard Shut-in While Cementing 25 4.9 Soft Shut-in During Wireline Operations 25 4.10 Hard Shut-in During Wireline Operations 25 4.11 Soft Shut-in While Out of Hole 25 4.12 Hard Shut-in While Out of Hole 25 4.13 Well Divertion with Shallow Set Conductor Pipe 25 4.14 Verification Of Shut-In 25


4-3 5.0 WELL MONITORING DURING SHUT-IN 27

5.1 Record keeping 27 5.2 Volumetric Bleed From A Shut-In Well 27 5.3 Determining SIDPP When Using A Non-Return Valve 28 5.4 Influx Density versus Shut-in Surface Pressures 30 5.5 When SIDPP Is Greater Than SICP 30 5.6 Maximum Allowable Annular Surface Pressure 32

5.7 Pressure Between Casing Strings 32 6.0 RESPONSE TO MASSIVE OR TOTAL LOSS OF CIRCULATION 34

6.1 Signs of Lost Returns 34 6.2 Dealing With Loss 34

7.0 TRIPPING 37

7.1 Procedures For Keeping Hole Filled 37 7.2 Measuring And Recording Hole-Fill Volumes 37 7.3 Wet Trip Calculations 37 7.4 Dry Trip Calculations 38 7.5 Pills 38 7.6 Overbalance & Trip Margin 38 8.0 FORMATION COMPETENCY 40

8.1 Prediction of Fracture Pressure 40 8.2 Formation Integrity Test 51

9.0 STRIPPING OPERATIONS 63

9.1 Controlling Bottom Hole Pressure 63 9.2 Stripping Procedure Through Annular Preventer 70 9.3 Stripping Using Rams 74 9.4 Snubbing Problems 77

10.0 REFERENCES 84


4-4

Table of Illustrations

Page No. Figure 4.01 Surface stack pre-recorded information 13

Figure 4.02 Procedure to establish the SIDPP when a float is in use 29

Figure 4.03 Shoe pressure versus gas location 33

Figure 4.04 Volumetric method 65

Figure 4.05 Volumetric strip 67

Figure 4.06 API strip procedure 69

Figure 4.07 Stripping with the annular preventer 72

Figure 4.08 Stripping out with annular preventer 73

Figure 4.09 Ram to ram strip step 1 79






4-5

Table of Tables

Page No. Table 4.01 Pressure versus pump rate 15

Table 4.02 Blowout preventer ratings 18

Table 4.03 API casing properties 19

Table 4.04 API tubular pressure ratings 20

Table 4.05 Gradient / densities for various formation fluids 30

Table 4.06 Indications of malfunctions during kill process 31

Table 4.07 Gunk plug mix for 300-foot plug 36

Table 4.08 Bulk density versus depth 41

Table 4.09 Deep-water overburden data 43

Table 4.10 Bulk density for various formation types 52


4-6

Table of Graphs Page No.

Graph 4.01 Barite plug mixture 36

Graph 4.02 Average density versus depth below TVD 42

Graph 4.03 Overburden values 44

Graph 4.04 Average density values for overburden 45

Graph 4.05 Average density data for overburden for various water depths 46

Graph 4.06 Poissons ratio for US Gulf of Mexico 49

Graph 4.07 Typical cement channel 57

Graph 4.08 Small cement channel 57

Graph 4.09 Plugged cement channel 58

Graph 4.10 Small propped fracture 58

Graph 4.11 Formation fractured by test 59

Graph 4.12 Cement fracture 59

Graph 4.13 Pre-existing formation fracture 60

Graph 4.14 High permeability 60

Graph 4.15 Unconsolidated formation 61

Graph 4.16 Two-stage crack growth 61


4-7 CHAPTER 4

PROCEDURES

Objectives On successful mastery of the content of this module, you will be able to: Demonstrate the procedures for setting well control monitoring indicators.

Identify appropriate pre-recorded information.

Record standpipe pressure at slow pump rate.

Read at choke consol.

Recognise an error in gauge readings based on discrepancies between readings.

Recognise and measure normal flow back.

Recognise a flow that is different from normal flowback.

Take action based on recognition of flow.

Explain how to establish that well is static before starting trip.

Explain why an absence of flow (flow check) is not an absolute indicator that there

is no influx.

Demonstrate understanding that the primary indicator of influx is the trip sheet, not a

flow check.

Upon observing positive flow indicators, shut-in the well in a timely and efficient

manner to minimise influx, according to a specific procedure which will address the

design of a shut in.

For any shut-in, verify well closure by demonstrating that flow paths are closed.

Explain or demonstrate recommended procedures to use for well monitoring during

well shut-in.

Read, record and report well shut-in record keeping parameters.

Identify at least two causes of trapped pressure.

Describe the effects of trapped pressure on well bore pressure.


4-8 List two consequences on surface pressure resulting from shutting in on a gas versus

liquid kick of equivalent volume.

Perform choke manipulation to achieve specific pressure or volume objectives.

Demonstrate procedure for relieving trapped pressure without creating

underbalance.

If a float is in use demonstrate the procedure to open the float to obtain shut-in drill

pipe pressure.

List two situations in which shut-in drill pipe pressure would exceed shut-in casing

pressure.

Identify a response to approaching maximum safe casing pressure.

Describe at least one method for controlling BHP while gas is migrating.

Identify two causes of pressure between casing strings.

Identify at least two methods of responding to massive or total loss of circulation

during a well kill operation.

Perform hole fill-ups on trips.

Demonstrate, explain and perform procedures during trips.

Describe the steps involved in conducting different types of drills.

Describe or perform a Leak Off Test and Formation Integrity Test.

Describe how formation competency test results may be affected by fluid density

change.

Define the basic purpose of, and method for stripping.

Demonstrate stripping procedures.


4-9 1.0 ALARM LIMITS 1.1 HIGH AND LOW PIT LEVEL All drilling rigs should be equipped with visual and audio alarm systems on the Return Flow Monitors, Pit Volume Totalisers and Pit Deviation Monitors. Fast drilling, the addition of pre-mix drilling fluid and the equalisation of mud tanks can lead to the premature sounding of alarms. Sometime it seems convenient to turn the alarms off and monitor the instrumental readoutss. This approach is subject to error. A small distraction may prevent the driller from noticing a possible change in the drilling parameters. The result of such a lapse in concentration may be a kick. Pit level alarms are located on the Mud Totalisers Instrument display that needs to be located near the driller. Alarms are also located on the pit level graph recorders and made active when the recorder pen crosses over the alarm proximity arm. Pit level monitors have a vernier setting that enables high/low calibrations. Calibration settings are dependent on the volume of influx into the wellbore of loss of drilling fluid volume into the formation that is tolerable. These values are also dependent on instrumental error (both land and offshore operations) and physical variations such as rig heave, rig pitch and rig roll in offshore dynamic drilling vessels. For example, an alarm setting indicating a gain or loss of 5 barrels (0.8 m3) is suitable for an 8-1/2 inch hole (216 mm) using 6-1/4 inch (159 mm) drill collars and 4-1/2 inch (114 mm) drill pipe. This value would not be acceptable in a slimhole operation where a 4 inch (102 mm) hole is being drilled using 3-1/2 inch (89 mm) drill rods. A small annular capacity will allow the influx length to reach true vertical lengths far exceeding those of larger capacity annular. Distribution of an influx over the greater true vertical distance will produce greater annular pressures at surface and at the casing shoe. 1.2 RETURN FLOW SENSOR The return flow sensor, located in the annular return flowline, is positioned between the Bell Nipple or Riser and the Shaker Header Tank. Its purpose is to:

Indicate any increase in flow during drilling operations; Monitor all drilling fluid returns from wellbore.

This instrument, often referred to by their brand name such as Flo-Show (Flo-Show was originally a brand name owned by the Martin Decker Instrument Corporation), have alarms set using toggle limit switches incorporated into a gauge displaying the relative indication of flow. The gauge functions in direct response to the movement of a paddle located in the flowline. When no flow occurs the paddle in the flowline is vertical and the gauge reads 0% flow. At maximum flow the toggle is horizontal and the reading is 100 %. The actual reading while drilling will depend on the relative pump output. Alarm settings slightly over circulation return rates will warn the driller of any positive variation in flow rate.


4-10 During a trip, an alarm setting above the fill-up pump flow rate from the wellbore will indicate a flow from the wellbore due to swabbing or kicking. 1.3 TRIP TANK LEVEL Not all trip tanks have alarm systems. The trip tank is always used in association with a trip sheet. A close observance of correct hole filling quantities must be observed on ALL trips, including wiper trips. If an alarm is available it should be calibrated to signal when the trip tank gains any fluid or is near empty. A loss of trip tank fluid will prevent the hole from being filled when tripping out of the hole. A dangerous situation when fill-up pumps are left on while the collars are being tripped out. The fluid volume required to fill the hole is greater for drill collars because the drill collar displacement is larger than the drill pipe displacement. DANGER! If the trip tank runs dry and the hole is not filled then the BHP will be reduced producing conditions suitable for a kick. Make sure when setting the alarm limits on your trip tank, remote or manual, that you know the limits of the tank. On a slide or gauge, be aware of the range between the full mark and the empty mark. 1.4 HYDROGEN SULPHIDE AND FLAMMABLE GAS SENSORS Equipment used to detect hydrogen sulfide and other flammable and explosive gases may include fixed location monitors, personal detectors, mud monitors with electronic probes, or chemicals for analysis of the drilling fluid. The monitors may be quantitative and may function with chemical or electronic sensors. The most important concern with any Hydrogen Sulphide air detector is proper placement of the sensor units. Since Hydrogen Sulphide is heavier than air, it will settle in low areas. The personal units should be attached to the clothing or carried level with the waist. The electronic rig monitors have portable sensor heads that should be placed in low areas such as the cellar and near the pits. A sensor should also be placed near the shale shaker since it is the first location where the mud will receive exposure to the air. Lead Acetate Paper Detectors Several reasonably semi-quantitative detectors for Hydrogen Sulphide are based on lead acetate paper. As the gas contacts the paper, the lead acetate impregnated in the paper reacts with the gas to form lead sulfide that causes the paper to change colour from white to various shades of brown or black. The degree of colour change depends on the Hydrogen Sulphide concentration that can be roughly estimated by comparing the observed colour to a control chart or table.


4-11 The primary advantage of these detectors is that they are carried by each crew member, enabling him or her to detect the gas wherever he or she may be. This provides an additional measure of safety to each crew member as well as an atmosphere of security. The reaction time required for the detector to function is a disadvantage of the tool. The total of 3 - 5 minutes necessary can be excessive and dangerous when large concentrations of Hydrogen Sulphide are met. Also, it is advisable to consider the lead acetate paper a quantitative indicator rather than as a determination of the concentration. The two paper detectors most often employed are the badge type and the spot check. Colour codes determine the Hydrogen Sulphide concentration.


4-12 Capsule Detector The capsule detector resembles an ammonia type capsule and is filled with chemical granules. The capsule is broken and attached to the clothing with a string. If Hydrogen Sulphide contacts the granules, a brown discolouration will be observed. This detector should be used only as an indicator of Hydrogen Sulphide because of the limitations of the capsule. The life of the tube is approximately 6 days after it is broken. The maximum concentration of the gas that can be measured accurately is 20 parts per million (ppm). Draeger Detector The Draeger (Registered company trade name for the Draeger organisation) unit is one of the most widely used tools for quantitative gas detection. It can be altered to measure almost any type of gas and as a result, is used extensively in Hydrogen Sulphide detection. The tool consists of a calibrated glass tube filled with lead acetate granules. A pump is used to draw gas samples into the tube, and the level of colour change denotes the Hydrogen Sulphide concentration. Several scales are usually presented on the glass tube to denote high and low concentrations. The pump is usually the bellows type. The simple operating procedure increases the utility of the tool. The tips of the detector tube are broken and inserted into the suction outlet of the Draeger unit. Ten compressions of the bellows is required to ensure an accurate reading in low concentrations of Hydrogen Sulphide. As the gas is drawn into the tube by the bulb, the lead acetate granules become discoloured denoting the quantitative measurement of the gas concentration. The accuracy of the measurements depends on the training and practice of the personnel using the unit. As varying amounts of air are drawn into the unit, the measurements will be different form if ten compressions are used. In high concentrations of Hydrogen Sulphide, only one compression is required. The measurement obtained with the Draeger unit are usually reliable. Since there are no electronic parts, the unit is not subject to electronic malfunction. The shelf life of an unbroken tube is approximately two years, and the tube can be used after the tips are broken as long as no indication of Hydrogen Sulphide is present. Belt Detectors The belt type of Hydrogen Sulphide detector is an electronic unit usually attached to the crew members belt. The unit is operated by rechargeable and/or replaceable batteries. The detector has a sensor head that will monitor Hydrogen Sulphide gas and report in a visible readout for concentrations of 5 - 10 parts per million. An audible alarm can be used and is usually pre-set to respond to 20 parts per million. The response time for the unit is approximately 35 seconds.


4-13 Fixed-Location Monitors The rig monitor is a fixed location, quantitative, electronic device designed for permanent, full-time operation. Sensor heads are placed at various locations on the rig and attached to the detection unit that is housed in a hard plastic or metal case. On the monitor, a readout in ppg concentration will be shown on a needle type indicator. A rotating beacon or strobe light attached to the unit will start automatically when a specified amount of gas has been detected. An audible alarm can be used to denote a higher level of gas concentration. The response time for the monitor is approximately 35 seconds for concentrations of 0 - 10 parts per million. The detection unit, depending on brand name and model, can have from 1 to 12 channels to which are attached the sensors. The most common units have 4 to 6 channels. The rig monitor or the belt type detector must be calibrated and tested periodically to insure that it is functionally properly.


4-14 2.0 PRE-RECORDED WELL CONTROL INFORMATION Formation Strength Data:- Current Well Data: Surface Leak-off Pressure:- (A) Mud Data: psi Mud Weight:- (B) Weight ppg ppg Gradient Maximum Allowable Mud Weight:- psi/ft (B) + (A) = (C) Casing Shoe Data: Shoe True Vertical Depth x 0.052 ppg Initial MAASP = Size inch [(C) - Current Mud Weight] x Shoe TVD x 0.052 =

psi MD ft

Pump No. 1 Displacement Pump No. 2 Displacement TVD ft bbls/stroke bbls/stroke Slow Pump Rate Data: Dynamic Pressure Loss (PL) Hole Data:- Pump No. 1 Pump No. 2 Size inch spm psi psi MD ft spm psi psi TVD ft

Figure 4.01 Surface Stack pre-recorded information

2.1 DYNAMIC PRESSURE LOSS Secondary well control calls for the use BOP equipment in combination with hydrostatic pressure to return the well to a controlled state. A dynamic pressure loss for the circulating system is determined by recording standpipe circulation pressures at a reduced pump rate. The slow pump rate (SPR) is determined by slowing the pump to a predetermined rate that will provide an up-hole annular velocity suitable to maintain the laminal flow of the kill fluid. Once pump rate is established standpipe pressures are adjusted to provide a rounded pressure reading compatible to the gauge calibration in use. Several recordings can be taken at different stroke rates and pressures. All pumps are calibrated to the same pressure recordings and not the same stroke rates. The SPR is independently determined for all pumps and the surface pressure and corresponding rates (spm) are entered in the drilling report and kill sheet. These values are sometimes refereed to as the Slow Circulating Rate, Slow Pump Rate or Slow Pump Pressure.


4-15 Slow Pump Pressures must be calibrated on all pumps because pump volumetric efficiency may vary. While each pump is running at the same pressure the fluid in the system is moving at the same velocity. A kill procedure requires an Initial Circulating Pressure and a Final Circulating Pressure not an Initial Circulating Rate and Final Circulating Rate. The remote choke panel gauge should be used to record all pressures. Since gauges vary the remote choke panel gauges are considered the rigs master gauges. A reduced circulating pressure is necessary for the following reasons:

a) It minimises the annular friction pressure on an already pressured wellbore;

b) It allows more reaction time during choke adjustments;

c) It keeps flow rates into the atmospheric degasser within design specifications;

d) It permits the continued lamina flow of the drilling fluid.

Changes to pump rates or drilling fluid density will affect circulating pressures. Changes to fluid density will either increase or decrease circulating pressure and is a function of the ratio of the new to old mud density.

New Pump Pressure = Old Pump Pressure New Mud Density/Old Mud Density

Formula 4.01

Similarly changes to stroke rate will change the circulating pressure as the square of the ratio of new is to old rate. New Pump Pressure = Old Pump Pressure (New SPM/Old SPM)2

Formula 4.02

Changes in the pump kill rate make a big difference in pump pressure, so it is important to get a pressure/rate reading after the pressure has stabilised. The small changes in pump rate or speed will make big changes in pump pressure. The following chart illustrates how a small change in pump rate or speed makes a large change in pump pressure.

Pressure (psi) 800 1027 1567 2133 2687 3198 Pressure (kPa) 5520 7086 10812 14718 18540 22066 Duplex Pump (spm) 30 34 42 49 55 60 Triplex Pump (spm) 60 68 84 97 110 120

Table 4.01 Pressure versus pump rate


4-16 The dramatic effect of pump rate versus circulating pressure also highlights the need for constant and correct kill pump speed during the kill operation. A new slow pump pressure and rate should be taken:

1. Every 500 feet of drilled hole;

2. After each tour change (when applicable);

3. After circulating around following each trip;

4. After any changes in BHA and or bit nozzles;

5. After mud weight changes;

6. After mud pump repairs;

7. Anytime there are good indications of a favourable formation change.

2.2 WELL CONFIGURATION Pump Output (O/P) and Drill Pipe Capacity A vital part of the well killing procedure is to determine the number of strokes required to fill the Drillstem. This can be achieved by dividing the pump output (volume displacement) per full stroke into the Drillstem volume. Volume whether drill stem or annular must be calculated using measured depths. True Vertical Depth (TVD) and Measured Depth (MD) The true vertical depth must be used in all calculations dealing with hydrostatic pressures and mud densities. Hydrostatic pressure is a function of true vertical depth not the length of the drill stem. Using a measured depth instead of a true vertical depth in pressure equations will result in an incorrect kill mud density. The measured depth must be used in all displacement calculations such as the calculation of surface-to-bit volumes. The proper use of true vertical depth and measured depth obviously becomes critical in directional or highly deviated holes. Calculation To Find TVD In A Directional Hole To find the TVD of any deviated section of well apply the following formula:

TVD = Cos (deviation) x MD See Chapter 1 for further explanation. Annular Capacity and Surface Line Capacity or Active Surface Volume


4-17 Annular capacity is used to calculate bit-to-shoe and bit-to-surface volumes. Because the wellbore is very rarely in gauge the bit-to-shoe values may, in reality, be in error. Surface line volume is the amount drilling fluid required to fill the surface lines from pump to Swivel. Surface line volume can be estimated as follows:

Platform/Tender 8 bbls 1.3 m3 Land Rig 2 bbls 0.3 m3 All Others 4 bbls 0.6 m3

The surface line volume must not be included in any Killsheet calculation. This value needs only to be known so that the pump stroke counter can be reset to zero once the surface lines have been filled with kill fluid. The surface lines are continuously flooded and not a part of the wellbore U tube. 2.3 FRACTURE GRADIENT Fracture Gradients are calculated by converting the total pressures required to compromise formation integrity at the shoe into a gradient. The continued destruction of the formation matrix will result in a loss of drilling fluid to the formation and a possible underground blowout. The most common procedure to determine the fracture gradient is called the Pressure Integrity Test or Leak-Off Test. The procedure used in the test is to close a blowout preventer and then gradually apply pressure to the shut-in system until the formation initially accepts fluid. As the casing shoe is the theoretical point in the wellbore of least resistance, a leak-off test is carried out everytime casing is set. In regions where the formation gradients are well known, this test is not necessarily carried out. Once a pressure is obtained it is converted into a mud weight and added onto the existing fluid weight used in the test. The resulting value represents the equivalent mud weight (EMW) of formation breakdown at the shoe. The mud weight in the circulation system must never exceed this value. If mud densitys approach this value, then another string of casing will need to be run and set in the well. The formula for fracture gradient is: Fracture Gradient = ((Test Fluid Density Constant TVD of Shoe) + Leak-Off Pressure) True Vertical Depth of Casing Shoe

Formula 4.03 This facture gradient is then converted to an equivalent mud density at the shoe using the formula:


4-18 EMW @ Shoe = FG / Constant

Formula 4.04 Or the Maximum Allowable Mud Density MAMD = (LOP / Constant / TVD of Shoe) +Test Fluid Density

Formula 4.05 Example:

Casing is set at 600 feet. A LOP test is undertaken using 8.3 ppg water. A LOP of 300 psi is obtained. What is the Fracture Gradient of the formation and the MAMD at the shoe? FG = ((8.3 x 0.052 x 600) + 300)/600 = 0.9316 psi/ft MAMD @ Shoe = (300 / 0.052 / 600) + 8.3 = 17.9 ppg

2.4 INITIAL MAXIMUM SAFE CASING PRESSURES Wellhead Rating When considering the initial maximum safe casing pressures one must first consider the pressure rating of the blowout preventer assemble. The lowest pressure rated component in the assembly hook-up must determine the blowout-prevention assemblys maximum pressure capability. This item may be the casing, casing head or connector, side outlet valves, the preventers itself, or other fittings exposed to pressure. The pressure capability of the casing and the formations exposed below the casing seat are often the determining factors for rating the working pressure of the assembly. Table 4.02 below shows pressure ratings for blowout-preventer equipment, published in API RP 53.

API CLASS WORKING PRESSURE (psi) [kPa] 2M 2,000 [13800] 3M 3,000 [20700] 5M 5,000 [34500] 10M 10,000 [69000] 15M 15,000 [103500]

Table 4.02 Blowout-Preventer Ratings

The maximum anticipated pressure at the Wellhead must consider the assumption that the hole is void of fluid. Therefore, while drilling a well one may penetrate a formation anticipated to contain 5 000 psi (34 500 kPa) of pressure. If this interface was at a depth of 10 000 feet (3 048 m) and a column of gas with a gradient of 0.1 psi/ft (2.26 kPa/m) then this gas column would exert a hydrostatic pressure of 1 000 psi (6 900 kPa). The


4-19 blowout preventer stack would therefore be exposed to a pressure of only 4 000 psi (27 600 kPa). Thus a 5 000 psi working pressure blowout preventer stack and subsequent peripheral equipment would be a reasonable choice. Casing Burst Rating The casing burst rating is the maximum allowable internal working pressure of the casing. Many operating companies impose design safety factors for burst strength, which applied to the minimum yield strength of the casing. The allowable working pressure may be deliberately down-rated because of protracted drilling. The examples in Table 4.03 illustrate predicted bursting strength of select casing.

Size (in) Weight (lb) Grade of Steel Min. Internal Yield Pressure (psi)

20 94.0 J-55 2,110 16 75.0 J-55 2,630

13-3/8 61.0 J-55 3,090 10-3/4 40.5 J-55 & K-55 3,130 9-5/8 40.0 J-55 & K-55 3,950 9-5/8 40.0 C-75 5,390 9-5/8 29.7 N-80 5,750 7-5/8 26.0 N-80 6,890

7 29.0 J-55 & K-55 4,980 7 29.0 N-80 8,160 7 29.0 P-110 11,220

5-1/2 23.0 P-110 14,520

Table 4.03 API Casing Properties Tubular Collapse During drill stem tests, tubulars are run into the well with limited internal fluid volume. When the Drillstem test is initiated the tubulars are subjected to the hydrostatic pressure of the drilling fluid in the annulus, and have been known to collapse. Down graded tubulars can contribute to collapse failures during drill-stem tests. Various production tubulars can experience the same problem if their rating is not chosen in accordance to the hydrostatic pressures being applied to them. Table 4.04 illustrates the collapse pressures of various tubulars.


4-20

Size OD (in)

Nom. Wt. (lb/ft)

Collapse Pressure Based On Minimum Values (psi)

E X-95 G-105 S-135 2-3/8 4.85 11040 13980 15460 19070

6.65 15600 19760 21840 28080 2-7/8 6.85 10470 12930 14010 17060

10.40 16510 20910 23110 29720 3-1/2 9.50 10040 12060 13050 15780

13.30 14110 17880 19760 25400 15.50 16770 21250 23480 30190 4 11.85 8410 9960 10700 12650 14.00 11350 14380 15900 20170 15.70 12900 16340 18050 23210

4-1/2 13.75 7200 8400 8950 10310 16.6 10390 12750 13820 16800 20.00 12960 16420 18150 23330 22.82 14810 18770 20740 26670 5 16.25 6970 8090 8610 9860 19.50 10000 12010 12990 15700 25.60 13500 17100 18900 24300

5-1/2 19.20 6070 6930 7300 8120 21.90 8440 10000 10740 12710 24.70 10460 12920 14000 17050

6-5/8 25.20 4810 5310 5490 6040

Table 4.04 API tubular pressure ratings


4-21 3.0 FLOW CHECKS 3.1 WHEN DRILLING Normal Flow Back Normal flow back occurs as the drilling fluids below the swivel equalise with the top of the flowline. Flow checks should be carried out when a drilling break occurs or if any doubt arises in the mind of the driller as to the well's condition. If in doubt, check! Normal flow back is minimised when the pumps are shut down soon after the bit is raised off bottom. This practise is not recommended due to the possibility of pulling into tight hole. If any tight hole is encountered when elevating the drill stem a pack-off may occur around the bit or stabilisers. It is best to maintain circulation until correct space out in achieved. Normal flow back will slowly decrease as the U tubing effect stabilises. The pit level gain/loss indicators will also show no gain in pit volume if the flow-back is a result of fluid equalisation. For offshore applications all fluid returns should be directed into the trip tank so that return flow can be monitored. Not Normal Flow Back A flow that is not normal will slowly increase in intensity and result in a gain in pit volume. A kick may not occur while circulating because of hydrodynamic pressure. A slight overbalance credited to the annular friction loss will not be lost until all circulation ceases. Slight hydrostatic underbalance may not register on the drill-pipe pressure gauge because of gauge calibrations. If a rig is not equipped with a digital display standpipe pressure gauge or finer calibrated instrument then the state of the well can be ascertained from the return flow from the wellbore. Once the well is confirmed as flowing, then normal shut-in procedures should commence. Loss Of Equivalent Circulating Density With Pumps Off An over pressured formation can resist early detection due to the effects of annular friction loss on bottom hole pressure. During circulation a status quo may be maintained between hydrodynamic pressure and reservoir pressure. If a minimal connection time is achieved then only a short period of time will elapse when the wellbore is not subjected to annular friction pressure. If however an underbalance between hydrostatic and reservoir pressure does exist then the influx will slowly enter the well during the period of each connection. The presence of influx in the wellbore may not be detected until bottoms-up exposes the drilling fluid to surveillance by surface instruments.


4-22 3.2 WHEN TRIPPING Well Is Hydrostatically Balanced When well circulation is suspended a hydrostatic balance exists when no flow is detected leaving the wellbore. Wellbore hydrostatic pressure is sufficient to balance the formation pressure. If an overbalance exists between hydrostatic pressure and formation pressure then this overbalance is called a trip margin. The implementation of a trip margin will depend on the type of drilling being undertaken. Under-balanced drilling operations encourage kicks so that drilling fluids do not enter formation pore spaces and damage formation permeability. During a trip the absence of flow is not an absolute indicator that no influx has entered the wellbore. As the drill stem is elevated the mud level in the annulus should decrease by a volume equivalent to the amount of steel displacement removed. If the well does not accept the calculated volume of mud to bring the annular mud level back to the surface, then it is assumed that a kick has entered the wellbore. Even though an influx may enter the wellbore, the well may not flow while an overbalance exists. Use And Purpose Of A Trip Sheet A Trip Sheet is the primary indicator of a kick during a trip. The purpose is to indicate to the driller that an influx has entering into the wellbore. This is achieved through the correlation of calculated displacements versus actual volumes returned to the well as the Drillstem is removed. If swabbing is taking place then a trip sheet will indicate the volume of influx that has entered the wellbore. If the well does not take the correct amount of drilling fluid then the trip should be suspended, a flow check initiated and if no flow, the Drillstem should be returned to bottom and the annulus fully circulated.


4-23 4.0 SHUT-IN PROCEDURES When one or more of the warning signs of kicks are observed, steps should be taken to shut-in the well. If there is any doubt whether the well is flowing, shut-in and check the pressures. Procedures for well shut-in may vary depending on site- specific issues. The procedures listed below take this into account. The reasons for closing the well are:

Keep the influx to a minimum; Obtain and interpret the shut-in pressures; Re-establish a balance between hydrostatic pressure and formation pressure.

4.1 SOFT SHUT-IN WHILE DRILLING

Pick-up off bottom to space out point Shut down pumps Open BOP side outlet hydraulic controlled valve Close preventer Close adjustable choke Record pressures

Set-up for soft shut-in:

BOP side outlet hydraulic controlled valve closed Line to the remote adjustable choke open Remote adjustable choke open Line to the atmospheric degasser open

4.2 HARD SHUT-IN WHILE DRILLING

Pick-up off bottom to space out point Shut down pumps Close preventer Open BOP side outlet hydraulic controlled valve Record pressures

Set-up for a hard shut-in:

BOP side outlet hydraulic controlled valve closed Line to the remote adjustable choke open Remote adjustable choke closed

4.3 SOFT SHUT-IN WHILE TRIPPING


4-24 Space out Drillstem Install full opening stabbing valve Close full opening stabbing valve Open BOP side outlet hydraulic control valve Close preventer Close adjustable choke Install Kelly or top drive Open full opening stabbing valve Record pressures

4.4 HARD SHUT-IN WHILE TRIPPING

Space out Drillstem Install full opening stabbing valve Close full opening stabbing valve Close preventer Open BOP side outlet hydraulic control valve Install Kelly or top drive Open full opening stabbing valve Record pressures

4.5 SOFT SHUT-IN WHILE RUNNING CASING

Space out casing Open BOP side outlet hydraulic control valve Close ram preventer (fitted with correct inserts) Close adjustable choke Fill casing with fluid Install swedge into casing and head-up onto standpipe Establish pressures

4.6 HARD SHUT-IN WHILE RUNNING CASING

Space out casing Close ram preventer (fitted with correct inserts) Open BOP side outlet hydraulic control valve Fill casing with fluid Install swedge into casing and head-up onto standpipe Establish pressures

4.7 SOFT SHUT-IN WHILE CEMENTING

Space out casing Shut down cement unit pumps Open BOP side outlet hydraulic control valve


4-25 Close ram preventer (fitted with correct inserts) Close adjustable choke

4.8 HARD SHUT-IN WHILE CEMENTING

Space out casing Shut down cement unit pumps Close ram preventer (fitted with correct inserts) Open BOP side outlet hydraulic control valve

4.9 SOFT SHUT-IN DURING WIRELINE OPERATIONS

Notify wire-line operator to stop operation Open BOP side outlet hydraulic control valve Close lubricator packing around wire-line Close remote adjustable choke

4.10 HARD SHUT-IN DURING WIRELINE OPERATIONS

Notify wire-line operator to stop operation Close lubricator packing around wire-line Open BOP side outlet hydraulic control valve

4.11 SOFT SHUT-IN WHILE OUT OF HOLE

Open BOP side outlet hydraulic control valve Close blind ram Close remote adjustable choke

4.12 HARD SHUT-IN WHILE OUT OF HOLE

Close blind ram Open BOP side outlet hydraulic control valve

4.13 WELL DIVERTION WITH SHALLOW SET CONDUCTOR PIPE

Space out Drillstem Shut down pumps Open selected port or starboard vent (blooie) lines Close return line to shakers Close diverter bag Remove non-essential personnel from rig floor Commence pumping into the well at the highest possible rate

4.14 VERIFICATION OF SHUT-IN


4-26 For any shut-in it must be physically demonstrated that the following flow paths are secure. Annulus Once the blowout preventer has been confirmed closed open the flow line to the trip tank. Observe to ensure that flow has ceased from the annulus. If flow continues close another preventer and repeat observation. Drill String

1. Check that the wash-pipe packing on the swivel is secure. 2. Check that the valve on the standpipe is closed and holding back-pressure. 3. Check the pressure sensor hammer unions on the standpipe. 4. Check the mud pump shear relief valves for leaks.

Wellhead/BOP For surface stack configurations inspect all drilling spool flanges for leaks. Observe the BOPs weep holes. If leaking mud then the primary seals have failed. Energise the piston shaft. If leaking hydraulic fluid the secondary seals have failed. Lock BOPs. For Subsea stack configurations deploy remote operating vehicle (ROV). Once ROV is at Subsea stack observe all connectors and flange connections for discharge into the sea. Observe pods for proper Sea Plate Mounted valve discharges on activation of BOP component. Once inspection is complete park ROV at BOP intervention panel. Choke Manifold

1. Check that the return lines to the Atmospheric Degasser are secure. 2. Check that the flare-line boom is secure and ignition source operative. 3. Close pre-choke valves up-stream from the variable choke when aligning

manifold prior to kick. If a positive closing choke is installed, slowly open pre-choke valve and check that choke is holding pressure.


4-27 5.0 WELL MONITORING DURING SHUT-IN 5.1 RECORDKEEPING Time Of Shut-In

Record on the Kill Sheet, Tour Report and Geolograph (Geolograph is a registered trade

name used by the TOTCO corporation) the time of well shut-in. It is also prudent to record pressure build-up in time intervals. The interval should be determined relevant to the speed of pressure build-up. This value can range from 30 second to 5 minute intervals. It will enable the calculation of gas migration rate to surface.

Percolation rate = Increase in Pressure / (Current Mud Density x Constant) Formula 4.06

Drill Pipe And Casing Pressures Enter SIDPP and SICP on the Kill Sheet. Allow the well pressure to stabilise as the rise in pressure is a function of influx type, rock permeability and the amount of underbalance or kick size. Record the pressures at regular intervals. If migration rates are excessive then a time versus pressure graph will need to be drawn to determine SIDPP. Estimate Pit Gain Check the Pit Volume Totalisers for pit gain. The value that is determined may not provide a direct correlation to influx volume. Issue such as compressibility and solubility may mask to true extent of the influx volume especially in oil-based mud.

Volume of a Rectangular Tank = Length x Width x Depth

Formula 4.07 5.2 VOLUMETRIC BLEED FROM A SHUT-IN WELL Pressure Increase At Surface And Downhole In gel based drilling fluids gas migration may range from 500 feet (152 m) to 8 000 feet (2 438 m) per hour depending on the density of the fluid. Gas migration will tend to be stagnant in oil based drilling fluids. As the aim of all well control procedures is to maintain a constant bottom hole pressure one must monitor pressure build-up in the wellbore due to containment and migration. After shut-in pressures have been stabilised, gas migration will cause a pressure increase on both the drill pipe and casing pressure gauges. The delta value between these two gauges will always remain the same as long as the influx is contained at its shut-in volume.


4-28 The simplest and most effective way to control bottom hole pressure (if not float is present in the Drillstem) is to bleed fluid from the annulus and reduce the drill pipe pressure back to its shut-in value. As a consequence of this action the casing pressure will increase due to gas expansion. The principles of Boyles Law is relevant here and will be discussed in more detail in a later chapter. If for some reason the drill stem becomes blocked, and no longer can the drill pipe pressure gauge be used to monitor bottom hole pressure, then an alternative method to control bottom hole pressure must be used. As long as a shut-in drill pipe pressure was determined then a volume of fluid can be calculated and bled from the well to maintain bottom hole pressure.

Formula 3.04 5.3 DETERMINING SHUT-IN DRILL-PIPE PRESSURE WHEN USING A DRILL-

PIPE FLOAT A kick may occur while a drill pipe float valve is in use. Since a float valve prevents fluid and pressure movement up the drill pipe, there will be no drill pipe pressure readings after the well is shut-in. The following method can be used to determine SIDPP.

1. Shut-in well and record SICP. 2. Line up a low volume, high pressure reciprocating pump on the standpipe. 3. Start pumping and fill up all of the lines. 4. Gradually increase the torque on the pump until the pump begins to move fluid

down the drill pipe. 5. Allow the drill pipe pressure to increase until the casing pressure increases

suddenly. 6. Shut down the pump and record the drill pipe and casing pressure. 7. Subtract the casing pressure from the SICP to obtain a delta value. 8. Subtract this delta value from the drill pipe pressure and thus obtain the SIDPP.

Alternatively: Having predetermined your slow pump rate and pressure, circulate the well at this rate while maintaining the casing pressure at its shut-in value. Read the circulating pressure from the standpipe and subtract the slow pump pressure. The value remaining will represent the SIDPP.


4-29

Figure 4.02 Procedure to establish SIDPP when a float is in use.


4-30 5.4 INFLUX DENSITY VERSUS SHUT-IN SURFACE PRESSURES Identifying The Influx From Density Differences A relationship exists between the delta values of the SIDPP and SICP. As long as the true vertical influx height can be determined.

Influx Length = Pit Gain / Annular Capacity Formula 4.10

True Vertical Influx Height = Cos Deviation x Influx Length

Formula 4.08

The equation required to make this kick influx identification calculation is as follows:

Influx Gradient = Mud Gradient - ((SICP -SIDPP)/ True Vertical Influx Height)

Formula 4.09 The influx type can be determined by referring to the table below.

Formation Fluid

Minimum Gradient

PPG Equivalent

Maximum Gradient

PPG Equivalent

Gas 0.05 psi/ft 1.0 ppg 0.15 psi/ft 2.9 ppg Oil 0.26 psi/ft 5.0 ppg 0.37 psi/ft 7.1 ppg

Brine 0.40 psi/ft 7.7 ppg 0.50 psi/ft 9.6 ppg

Table 4.05 Gradients / densities for various formation fluids. 5.5 WHEN SIDPP IS GREATER THAN SICP Cuttings Loading This situation arises during periods of fast drilling. The loading of the annulus with cuttings may produce a lower than expected SICP. If the influx has a density near the value of the drilling fluid one may see a SIDPP that is greater than the SICP. Inaccurate Gauge Readings A ruptured diaphragm in the hydraulic sensor type gauge may result in an inaccurate reading. Pressure can become trapped within the sensor and destabilise the calibration. All gauges need to be calibrated against a master set on the choke manifold. Density Of Influx Fluid Greater Than Drilling Fluid


4-31 An influx of salt water while drilling with a low-density oil based mud can produce a SICP > SIDPP. A heavily saturated Brine solution would produce this effect. Variations In Dynamic Drill Pipe and Casing Pressure During a kill operation various malfunctions can occur which would result in changes in circulating and annular pressures. Identification of these malfunctions is essential if one is to maintain a constant bottom hole pressure. The table below highlights the changes that will occur to drill pipe and casing pressure for each particular malfunction.

Drill Pipe Pressure

Casing Pressure

Drill String Weight

Pit Level Pump SPM

Loss of Circulation

Choke Plugs

Bit Nozzle Plugs

Bit Nozzle Out

Pump Volume Drops

Hole in Drill String

Gas Feeding In

Choke Washes Out

Gas Reaches Surface

Table 4.06 Indications of malfunctions during the kill process

Major Indication Other Indications


4-32 5.6 MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE Procedure's When MAASP is Exceeded. Maximum Allowable Annular Surface Pressure (MAASP) is relevant at initial shut-in and while circulating of the influx across the open-hole section of the well. There is no immediate fix if the MAASP is exceeded at shut-in. No driller has the authority to open the well once the well is secured. To open the choke and lower the casing pressure to posted MAASP values will only allow more influx to enter the wellbore and exasperate the problem. If the casing shoe depth exceeds 1 000 feet (304 m) then the well will not breach to surface. An underground blowout will result where the formation fluids will enter a thief zone and communicate between formations. If the casing shoe depth is less than 1 000 feet (304 m) then the well will breach to surface. A rig evacuation must be considered. If the MAASP is exceeded while circulating the influx across the open hole section ensure that all excess pressure being held above calculated circulating pressures is removed. The reduction of pump rate will also reduce the annular friction loss and thus lower pressures at the shoe without allowing the bottom hole pressure to fall below pore pressure. After the top of the gas influx reaches the casing shoe, the open hole formations below the shoe will be subject to reduced pressures even though the surface casing pressure continues to increase. Figure 4.03 illustrates this situation. 5.7 PRESSURE BETWEEN CASING STRINGS Pressure can exist between casing strings for the following reasons:

1. When the second string of casing was cemented the cement did not seal-off

active zones. These zones have now kicked as the old fluid density breaks down. The formation pressure is held in check by the primary seals in the casing spool. A casing cement bonding log would need to be run to determine what areas are exposed. A perforation and squeeze job would follow.

2. The casing seat has broken down due to a pore cement bond allowing formation

pressure to bypass around the shoe and channel its way up behind the next string.


4-33

Figure 4.03 Shoe pressure versus gas location .

Mud pressure component A does not change until gas hits shoe

Shoe pressure = BHP (constant) less Mud Pressure (constant) so shoe pressure does not change after gas passes

Gas Below Shoe

Pressure @ shoe =

Mud Pressure A +

SICP-1

Gas Hits Shoe

Pressure @ shoe =

Mud Pressure A + SICP-2

If BHP remains constant, SICP-2 is higher than SICP-1 to offset longer bubble.

Gas Above Shoe

Once top of gas hits shoe, shoe pressure begins to decrease. Because gas must continue to expand and expanding gas pressure decreases. Even though SICP-3 is greater than SICP-2, shoe pressure has decreased.


4-34 6.0 RESPONSE TO MASSIVE OR TOTAL LOSS OF CIRCULATION One of the major problems in controlling a well is lost circulation. In highly fractured formations, lost circulation is often an all or nothing situation. This makes well control difficult. In the softer shales in the younger marine basins, partial lost returns are a very common situation. Any time that partial lost returns is encountered it is possible to kill the well with the standard method as long as the loss of fluid does not exceed active fluid system volume. 6.1 SIGNS OF LOSING RETURNS

1. Choke Operation Changes

Most choke adjustments are gradually towards the open side. If the choke operator begins to notice a gradual choke closing to maintain BHP, this indicates either a washed choke or a partial loss of circulation. Pit levels need to be continually monitored by the driller especially while circulating across the open-hole section.

2. Drop in Casing and Drill Pipe Pressure.

A leak in the system will cause both gauges to drop. The casing side drop will probably be more pronounced. Other conditions such as a choke washout might look the same. Pit levels may remain at a constant volume as gas expansion forces drilling fluid into the formation ahead of the influx.

3. Pit Level Changes.

Lost circulation is most likely to occur while circulating out a gas influx. The pit level trend is the most reliable indication of losing returns.

6.2 DEALING WITH LOSS When partial loss of returns occur during a kill one may:

Maintain kill rate speed and proper drill pipe pressure to keep a constant BHP and attempt to keep up with the losses. The gas bubble may be close to the shoe. Once the gas enters the shoe the losses may stabilise.

Pump Loss Circulation Material (LCM) into the annulus.

In most cases, losses occur at the shoe. The LCM will probably reach the shoe sooner

through the annulus and bit plugging is avoided. Pumping into the annulus may also minimise additional influx.


4-35

Placing a Heavy Slug of Mud on Bottom. This procedure is designed to help balance formation pore pressures below the shoe to stop additional influx and then strip above the slug and circulate the influx out, set lost circulation plugs, etc.

Set a Plug

The following describes several different types of plugs that are used if rig abandonment is necessary. There are various types of plugs. The commonest are barite, gunk and cement plugs. There is no guarantee that any plug will work. Cement plugs generally will not set in the presence of any flowing gas or water. It is difficult to set a barite plug in a large water flow and gunk plugs are difficult to set in a gas flow. The best approach is to set a barite or gunk plug and then set a cement plug on top to provide a firm seal.

Barite Plug.

The heavier the barite plug, the more difficult it is to settle. There may be advantages to a

heavy plug. Graph 4.01 shows one type of formulation for a 300-foot (90 m) plug. The operator may use this graph or prefer to mix a maximum plug density of 22 ppg (2.64 g/cm3). Displace the plug so the slurry height in the drill-pipe is approximately 2 bbls (0.32 m3) above the plug. Consider setting a cement plug on top of the barite plug.

Gunk Plug. The gunk plug is a mixture of diesel oil and bentonite. Mix the pill according to Table 4.07. Pump down the drill-pipe with a diesel oil spacer ahead and behind the pill. Twenty barrels (3.2 m3) is a good estimate of the spacer size. As soon as the gunk reaches the bit, start the squeeze. Pump the gunk at about 4 to 5 barrels (0.6 to 0.8 m3) per minute and the mud down the annulus at 2 to 3 barrels (0.3 to 0.5 m3) per minute. Always place a cement plug on top of a gunk plug if there is any pressure in the well. The gunk plug is not very strong and tends to lose its yield strength over time. Cement Plug. A cement plug will generally not set in flowing water or gas, but it can be set on top of barite or gunk plugs for safety. The cement should be slightly heavier than the mud in use. For high weight cements, greater than 16 ppg (1.92 g/cm3), use haematite as a weighting agent. Barite will cause the cement to set too fast.


4-36

Hole Size (in) Diesel Oil (bbl) Bentonite Sacks Total Volume (bbl)

6-1/2 9 27 12 7-7/8 13 40 18 8-3/4 14 49 22 9-7/8 20 62 28 12-1/4 33 98 44

15 50 150 66 17-1/2 66 200 89

Table 4.07 Gunk plug mix for 300 ft plug

A = 15 Hole: 1,000 sx Barite & 150 lb Phosphate B = 12-1/4 Hole: 700 sx Barite & 100 lb Phosphate, For 17-1/2 Hole use Twice Mix C = 9-7/8 Hole: 425 sx Barite & 50 lb Phosphate D = 8-3/4 Hole: 335 sx Barite & 50 lb Phosphate E = 7-7/8 Hole: 270 sx Barite & 35 lb Phosphate F = 6-1/2 Hole: 185 sx Barite & 25 lb Phosphate

Graph 4.01 Barite plug mixture


4-37 7.0 TRIPPING 7.1 PROCEDURES FOR KEEPING HOLE FULL There are different methods available for filling the hole during trips. (Chapter 1). Whatever method is used, the amount of mud required must be measured accurately. The three methods used for measuring hole fill-up are:

1. A trip tank 2. A rig pump 3. Total mud system

The trip tank is any calibrated tank that can be used to monitor accurately the volume of mud being pumped into the well. A centrifugal pump delivers mud to the annulus with the overflow returning to the trip tank. The advantage of this trip tank system is that the hole can be accurately filled and monitored to make sure the well is taking the correct amount of fluid. The recirculating trip tank is one that is placed above the flowline height to allow a gravity feed into the annulus. The rig pump fills the hole by positively displacing fluid into the annulus and registering the amount of stokes taken to fill. A flowline device is installed to indicate when mud returns and automatically shuts off the stroke meter. This method is only viable on mechanical pumps. SCR pumping units using electric charge pumps cause the discharge valves on the pumps to lift during slow pump rates. This factor will cause false displacement readings. 7.2 MEASURING AND RECORDING HOLE-FILL VOLUMES Measuring the mud used to fill the hole when the drill-stem is removed is critical when only a small overbalance exists between formation and hydrostatic pressure. The trip tank measurement is the most advantageous because the exact amount of mud needed to fill the hole, after a given number of stands of pipe pulled, can be accurately observed. Counting the number of pump strokes required to fill the hole, after a given number of stands, depends on the accuracy of the monitoring equipment on the pumps and flowline. In this method the pump volumetric efficiency must be considered. The trip tank pit level changes, usually expressed in inches or barrels per five stands, should be posted on the rig so all concerned can quickly check this information while making a trip. Hole-fill volumes are recorded using a Trip Sheet. (Chapter 1) 7.3 WET TRIP CALCULATIONS


4-38 A wet trip is caused by a blockage in the Drillstem. During a wet trip the mud in the drill-pipe, once broken, can either return to the trip tank, through the use of a mud bucket, or spill over the lease. The volume required to fill the hole is calculated from the full tubular displacement.

MUD LEVEL DROP = VOLUME PULLED / ANNULAR CAPACITY VOLUME PULLED = WET DISPLACEMENT x STAND WET DISPLACEMENT = DP DISPLACEMENT + DP CAPACITY

7.4 DRY TRIP CALCULATIONS

MUD LEVEL DROP = VOLUME PULLED / TOTAL CAPACITY VOLUME PULLED = DISPLACEMENT x STAND DISPLACEMENT (bbl/ft) = (DP OD2 - DP ID2) / Constant TOTAL CAPACITY = PIPE CAPACITY + ANNULAR CAPACITY

7.5 PILLS Pills are used to reduce the mud level inside the drill pipe so as not to allow any spillage of mud from the drill-stem during a trip. Two formulae exist for the calculation of pill drop and pill density required for a particular drop requirement. In both cases, a pre-determined pill volume needs to be determined. The volume of the pill should correspond to the volume of the bottom hole assembly.

Pill Drop = (Pill Density/Current Mud Density x Pill Length) - Pill Length

Formula 4.11 Pill Density = Current Mud Density x ((Pill Drop/Pill Length) + 1)

Formula 4.12 After a pill has been mixed and subsequently pumped into the tubular, due to the U tube effect, an amount of mud will return into the trip tank. This amount is calculated by using the following formula:

Gain in Trip Tank = ((Pill Density/Current Mud Density) - 1) x Slug Volume

Formula 4.13 7.6 OVERBALANCE & TRIP MARGIN


4-39 An overbalance or trip margin is a positive pressure differential added to the hydrostatic pressure. As long as the overbalance is greater than the swab pressures the bottom hole pressures will not drop below formation pressure.

Overbalance = Hydrostatic Pressure Formation Pressure Formula 4.14

Trip Margin = Overbalance / Constant / TVD

Formula 4.15


4-40 8.0 FORMATION COMPETENCY The formation fracture resistance is the force that a formation can sustain without the propagation of a fracture plane. The mud density in the wellbore must be maintained at a value below the Maximum Allowable Mud Weight (MAMW). The hydrostatic pressure generated by the MAMW will produce a force at the casing shoe sufficient to fracture the matrix of a sedimentary rock. Knowledge of the fracture gradient of a formation is essential if casing depths and designs are to adequately withstand abnormal pressures in the wellbore. Formation fracture gradient approximations are used to develop equations that will correctly estimate the fracture pressure of a formation. Techniques to develop these equations include the predictive and verification method. 8.1 PREDICTION OF FRACTURE PRESSURE Fracture gradient has been the subject of much research since 1960. Papers written by Hubert and Willis (1957), Matthew and Kelly (1967) and Eaton (1968) all approach the subject. A survey sponsored by Japex in 1996 (Eaton & Eaton, 1997), Mouchet and Mitchell (1989) and Yoshida et al (1996) all conclude that the Eaton method is currently the most widely used means of predicting the fracture gradient of a formation. 8.1.1 EATON METHOD Fracture gradients are controlled by 3 variables:

1. Overburden gradient; 2. Pore pressure gradient; 3. Horizontal matrix stress to vertical stress ratio.

Vertical stress ratio = v/(1-v)

Where v is the Poissons ratio of the rock (dimensionless). The equation developed by Eaton (1968) relates to these variables.

Fracture Pressure Gradient = (v/(1 v)) * (Overburden Pressure Gradient Pore Pressure Gradient) + Pore Pressure Gradient

Formula 4.16


4-41 This equation may be applied anywhere in the world as long as the following 3 steps are undertaken:

1. Determine overburden pressure gradient; 2. Determine pore pressure gradient; 3. Estimate Poissons ratio for any area.

Overburden Pressure Gradient In order to determine overburden pressure gradients one must first determine the bulk densities beneath the rigs zero datum point. For land, platform or jack-up operations this point is referred to as the top of the Rotary Kelly Bush (RKB) or top of the rotary table. For offshore semi-submersible or drill-ship applications this point is the top of the rotary table calculated using a mean sea level.

TVD Interval (ft-m) Bulk Density (ppg) Bulk Density (g/cm3) Description

RKB to sea level of ground level 0.0083 0.001 Air

Sea level to sea bed or mud line 1.06 0.1272 Sea water

Mud line to 500 feet (152 m) below mud line 1.6 0.192 Clastic material

Intervals of 500 feet (152m) to TVD

Increasing bulk density

Increasing bulk density

Formation lithologies

Total TVD minus 500 feet (152 m) 2.4 0.288 Sand and shale

Table 4.08 Bulk density versus depth (after Eaton)

Accurate results for bulk densities obtained in a 500-foot (152 m) interval will provide accurate results. According to Eaton (1997) longer intervals may be used.


4-42

Graph 4.02 Average density versus depth below mud line (after Eaton, source: AMOCO) The next step is to calculate the pressure exerted by each vertical column using the following calculation:

P = Bulk Density x 0.433 x TVD interval

Formula 4.17 Therefore at any TVD the overburden gradient can be calculated from:

Overburden Pressure Gradient = P / TVD

Formula 4.18 Once the overburden pressure gradients have be calculated the values may be arranged in a table and then plotted on a graph.


4-43

Well Depth in feet Bulk Density g/cm3 Interval Pressure psi Overburden Gradient psi/ft

0 1.060 0 0.459 100 1.060 45.898 0.459 350 1.060 114.745 0.459 500 1.060 68.847 0.459 700 1.060 91.796 0.459 800 1.060 45.898 0.459

1 000 1.060 91.796 0.459 2 000 1.060 458.98 0.459 3 000 1.060 458.98 0.459 4 000 1.060 458.98 0.459 5 000 1.060 458.98 0.459 6 000 1.060 458.98 0.459 7 000 1.060 458.98 0.459

Mud Line Mud Line Mud Line Mud Line 7 100 1.400 60.620 0.461 7 350 1.550 167.788 0.468 7 500 1.640 106.518 0.473 7 700 1.700 147.220 0.480 7 800 1.775 76.858 0.484 8 200 1.840 318.688 0.499 8 500 1.890 245.511 0.510 8 700 1.940 168.004 0.518 9 250 2.000 476.300 0.538 9 750 2.100 454.650 0.557

10 300 2.200 523.930 0.579 11 000 2.200 666.820 0.602 12 000 2.250 974.250 0.633 13 000 2.280 987.240 0.661 14 000 2.310 1 000.230 0.685 15 000 2.330 1 008.890 0.706 16 000 2.380 1 030.540 0.727 17 000 2.400 1 039.200 0.745

Table 4.09 Deepwater overburden data (after Eaton).


4-44

Graph 4.03 Overburden values (after Eaton) Bulk density determinations of sediments below the mud line will pose a problem. Unconsolidated sedimentation can be an issue when drilling in regions such as major river deltas and continental slopes. Gardener et al (1974) developed an equation that relates average interval velocity to bulk density for the same depth interval.

Bulk density = 0.23 * V0.25

Where

Bulk density = g/cm3 V = Seismic interval velocity, ft/sec

Barker and Wood (1997) presented cumulative overburden data points as equivalent mud densities for depths below the mud-line ranging from 2 000 to 7 000 feet. An average overburden gradient versus true vertical distance below the mud-line was calculated. This exercise produced a data distribution that was severely scattered but it did present an average overburden gradient versus TVD below the mud-line. The plot mentioned above is used to reverse extrapolate bulk densities of the sediments and then an average overburden gradient in psi/ft versus TVD below the mud-line was computed and plotted. The results of this determination is shown in graph 4.04.


4-45

Graph 4.04 Average density values for overburden (after AMOCO) Graph 4.04 was computed from an average data across the Gulf of Mexico so therefore the plot should be functional regardless of water depth. Graph 4.05 represents overburden gradient curves for water depths of 1 000 to 7 000 feet. Eaton noted that this data shows a sharp reduction in overburden gradient as water depth increases. He also notes that these curves must be computed for site-specific cases when sediment densities are known or can be calculated.


4-46

Graph 4.05 Average density data for overburden for various water depths (after Amoco) Pore Pressure Gradient Eaton equations for pore pressure prediction are widely used in the drilling industry. These equations are presented as:

p/D = S/D [{(S/D) (P/Dn)} * (Ro/RN)1.2] Formula 4.19

p/D = S/D [{(S/D) (P/Dn)} * (CN/CO)1.2]

Formula 4.20


4-47 p/D = S/D [{(S/D) (P/Dn)} * (tn/to)3]

Formula 4.21

p/D = S/D [{(S/D) (P/Dn)} * (dco/dcn)1.2]

Formula 4.22

The equations above vary only in their exponential terms and can be used according to various data gathering techniques. The most common exponent is 1.2 in Formula 4.19, 4.20 and 4.22 but this can have a range from 0.9 to 2.00. Similarly Formula 4.21 can have a possible range from 2.0 to 4.0. As Eaton states, the important idea is that it is possible to predict pore pressure gradient values with no more than seismic data. Other data from offset wells simply serve to refine the prediction. Poissons Ratio For Any Area The greater the value of Poissons ratio of a sediment the greater the vertical matrix stress is transmitted in the horizontal direction. In other words the higher the value of Poissons ratio the higher the fracture pressure gradients. Eaton does not agree with the hypothesis that pore pressure has no effect on fracture gradients values (Rocha & Bourgoyne, 1996). Let us examine Eatons Fracture Gradient Equation (Eaton, 1997):

F/D = {[v/(1-v)] * [(S/D) (p/D)]} + (p/D) If v = 0.50, then F/D = {[0.5/(1-0.5)] * [(S/D) (p/D)]} + (p/D) = {1 * [(S/D) (p/D)]} + (p/D) F/D = S/D

This is the only example where the fracture gradient equals the overburden gradient due to equal matrix stresses in all directions. Now if p/D = S/D then:

F/D = {[v/(1 v)] * [(S/D) (S/D)]} + (S/D) = [v/(1 v)}* 0] + S/D


4-48 F/D = S/D

This is the only example where pore pressure has no effect on fracture gradient values. To establish a curve showing Poissons ratio as a function of Depth below the mud-line, one must use known fracture gradient data Eatons fracture gradient equation can be transposed to produce:

[v/(1-v)] = [(F/D) (p/D)] / [(S/D) (p/D)]

Formula 4.23 Two curves (Graph 4.06) were therefore developed over time. One curve represented lower values of Poissons ratio and was established in the 1960s while the second curve represents higher Poisson Ratios developed during the 1990s. Equations have been developed to describe these curves at various depths below the mudline.

Formula 4.24

Graph 4.06 Poissons ratio for US Gulf of Mexico (After Eaton)


4-49 8.1.2 HUBBERT AND WILLIS EQUATION Hubbert and Willis equation is used to estimate the pressure required to extend and existing fracture. It is expressed as:

Pfk = min + Pf where min = minimal principal stress Pf = formation fluid pressure It is assumed that minimal principal stress occurs in a horizontal plane and that x and y are equal. It is also assumed that stress concentration near the wellbore is twice the stress away from the wellbore. Thus the extension pressure can be given as:

Pfk = 2*H + Pf From laboratory tests on cylindrical rock specimens at the University of New South Wales School of Petroleum Engineering, it was concluded that minimal matrix stress for shallow sediments is approximately 1/3 of the vertical stress.

min = 1/3 * z We also know that

ma = ob - Pf where ob = overburden pressure through substitution we obtain the equation for fracture pressure as:

Pfk = 1/3 * z + Pf = 1/3 * (ob Pf) + Pf = 1/3 * (ob + 2*Pf)

8.1.2.1 MATHEWS AND KELLY CORRELATION Mathews and Kelly replaced the assumption that


4-50

min = 1/3*z by min = (Ms * z) where Ms is the stress coefficient that was empirically determined from Gulf of Mexico data. To use these correlations the assumption must be made that:

ob = 1 psi/ft and Pf = 0.465*Dn where Dn is the depth at which normally pressured formation would have the same matrix stress as the abnormally pressured formations of interest.

Formula 4.25


4-51 8.2 FORMATION PRESSURE INTEGRITY TEST Two types of formation integrity tests are performed at the casing shoe. The first is known as a pressure integrity test (leak-off test) and the second is known as a formation integrity test. The former permits the evaluation of the effectiveness of the cement bond and strength of the formation at the shoe and the latter tests a formation to the maximum mud density expected. The leak-off test is performed after the casing shoe has been drilled out and tests the effectiveness of the cement seal and strength of the formation at the shoe area. To perform a leak-off test drilling mud known as the test fluid is pumped into the wellbore at a slow rate in a closed BOP system. The pressure build-up is accurately recorded against each volume increment pumped. A volume pumped versus pressure is plotted over which is superimposed a fluid compression gradient line that is established prior to the drilling out of the shoe. The pressure point where the pressure-volume function deviates from the compression gradient is where the formation laminations are beginning to open and accept fluid. This surface pressure when added to the hydrostatic pressure generated by the test fluid at the shoe determines the formation fracture pressure. The formation fracture pressure can therefore by transposed to produce the Maximum Allowable Mud Density. Leak-off tests also evaluate the cement bonding around the shoe area. A leak-off test does not damage the formation integrity if undertaken using a gel based drilling fluid because the formation laminations will heal once the excess pressure being applied to the formation is removed. Oil based drilling fluid can not be used to undertake a leak-off test as the laminations once separated by the oil based fluid will not heal or bond together again due to the lubricating nature of the oil. Formation integrity tests are also known as Limit Tests and provide evidence that the wellbore can sustain the forces generated by a specific mud density. A limit test does not indicate the maximum allowable mud density that can be permitted before a formation matrix commences to break down. 8.2.1 STRESS IN FORMATIONS Weathered material from Igneous or Metamorphic rocks is laid down in sedimentary basins where it is compacted, consolidated and cemented into a sedimentary rock. As the sedimentary material thickens the stresses within the material underneath increases. The vertical stress that is applied to a formation is a function of the density of the material above the formation. When a porous formation containing a confined fluid is subjected to a vertical stress, the stress pressure is transmitted throughout the formation fluid. If a vertical stress is applied to a solid material, the horizontal stress will be less than the vertical stress. The vertical stress applied to a horizontal formation is the force applied by the density of the material above the formation. If the formation is under the ocean, the force generated by the true vertical depth of the ocean as a function of the oceans density will be less


4-52 than that generated by a rock. The vertical stress on a shallow formation will be different in an ocean-drilling environment than it would be at the same depth on land. Vertical stress, z, is the integration of the differential equation:

dz = constant*seawater density.dz + constant*bulk density of formations.dz z ranges from 0 to mud-line in the first term and mud-line to formation in the second term. The bulk density of a formation will depend on the composition of the formation matrix and the density of the liquid within the pore spaces thus a function of porosity.

Formation Type Bulk density (sg) Salt 2.2 2.3

Shale 2.3 2.9 Sand 2.3 2.7

Carbonates 2.6 2.9

Table 4.10 Bulk density for various formation types. Total vertical stress (z) is a sum of the product of varying bulk densities and formation thickness.

Horizontal stress (x) = {v/(1 v)}*z Where v is Poissons ratio. During a leak-off test pressure increases inside the wellbore and the tensile stress in the wellbore increases. When the stress in the wellbore exceeds the tensile strength of the rock a crack will form. In the horizontal direction one horizontal stress is smaller than other horizontal stress. A crack will open in a direction perpendicular to the lower stress. (Zheng et al, 1989) The early pressure build-up recorded during a leak-off test is consistent until fluid commenced to enter the formation. At this point pressure will no longer rise uniformly. Leak-off pressure is a function of crack length, formation stresses, stress concentrations and matrix strength. The first departure from the gradient line is the minimum stress of the formation. The pumps are stopped after confirmation of leak-off is established by observation. The surface pressure will drop due to the decrease in flowing pressure losses in the drill pipe. This value is called initial shut-in leak-off pressure. Slowly the crack will close. When the crack has closed the pressure at the shoe is lower than the formation


4-53 stress. This pressure is called the final shut-in leak-off pressure. By observing this pressure one can confirm that the point of departure of the pressure curve from the gradient line is really the leak-off pressure. The leak-off pressure must be larger than the final shut-in leak-off pressure. If the point of departure is lower than the final shut-in leak-off pressure then the deviation in the initial curve is not the leak-off pressure.


4-54 8.2.2 TEST PROCEDURES AND EQUIPMENT Before the Test

Drill out: A fluid compression graph is obtained before the shoe is drilled out. A casing test is undertaken by drilling out the float collar and some of the cement under the collar. By doing this the casing coupling at the float collar and between the float collar and the shoe is also tested. For the leak-off test drill out the shoe and flush the rat-hole below the casing and then drill a short distance into new formation.

Prepare Test Graph Sheet Record the maximum pressure permitted based on equipment or casing

limitations by drawing a line parallel to the x-axis at this pressure. Circulation Requirements Circulate and condition the drilling fluid to stabilize the drilling fluid properties and clean the wellbore of any contamination caused by the drilling-out process. Ensure that the mud density in and mud density out is within 0.1 ppg (0.012 sg) for three consecutive measurements. This process assists in obtaining a uniform column of mud fluid density, shears the gel structure, deposits a filter wall cake on any exposed permeable formation and removes air bubbles in the circulation system. Rig-Up

Use a high-pressure, low volume positive displacement pump. Shut-in valve is installed between the pump and the pressure gauge. This

valve is used for shut-in instead of relying on the pump to prevent backflow. Bleed value is installed between shut-in valve and the pump. After the test

this valve is used to bleed pressure from the drill pipe after it is connected to a drain line.

Pressure Gauges: Inaccurate gauges or ones with the wrong calibration can inhibit the results of the leak-off test.

Pump down the drill pipe as the fluid is more likely to be free of solids contamination than fluid in the annulus.

Calibrate the pump and do not assume the mechanical stroke counter on the pump is accurate.

Pressure test the circulation system up to the drill pipe prior to undertaking the leak-off test.

During the Test

Pump rate should be slow and steady. For impermeable formations a rate of bbl per minute (40 litres per minute) and for permeable formations a rate of bbl per minute (80 litres per minute) will overcome filtration loss. Do not use


4-55 volumes greater than 1 bbl per minute (160 litres per minute).

Plot data accurately. Near leak-off the plotted data will deviate from the straight gradient line.


4-56

8.2.3 PLOTTING DATA TO OBTAIN A LEAK-OFF PRESSURE General Guidelines To Locate The Leak-Off Point Curving Plot Continue pumping until the pressure remains constant for three consecutive readings. This constant pressure is the leak-off pressure. Plot Leaves Gradient Line Far Below Anticipated Pressure Pump one or two barrels extra and see if pressure will continue to increase. If the pressure resumes to increase continue pumping until the real leak-off pressure is found. Stop pumping when the pressure decreases. Monitor Pressure Decline The shut-in pressure has two distinct areas. The first area is where the shut-in pressure rapidly decreases. If the pressure drops to a value less than of the leak-off pressure, a cement channel is probably indicated. The second area is the region of more gradual decline. If this pressure stabilises to a reasonable constant value just below the leak-off pressure, the wellbore integrity is certified. If the formation has some permeability the pressure will continue to decline slowly. Retest Confirmation of leak-off pressure will result with a similar pressure if the formation is competent. A lower pressure will result if cement channels are opened.


4-57 8.2.4 INTERPRETING FORMATION INTEGRITY GRAPHS

Graph 4.07 Typical cement channel

Typical Cement Channel

Leak-off pressure more than ppg below expected Maximum Allowable Mud Density.

Shut-in pressure not constant bleed-off seen. Repeat tests show no improvement.

Graph 4.08 Small cement channel


4-58 Small Cement Channel

Sudden change in slope while pumping. Shut-in pressure falls below point of slope change. Second test shows similar shut-in pressure decay.

Graph 4.09 Plugged cement channel

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