Thesis

Contents Acknowledgements....................................................................................................................................... 3 Abstract ......................................................................................................................................................... 4 Introduction .................................................................................................................................................. 5 Fundamental Principles of Well Control ....................................................................................................... 7 Pressure ........................................................................................................................................................ 9 Kick .............................................................................................................................................................. 15 Kick Indicators ............................................................................................................................................. 17 Causes of Kicks ............................................................................................................................................ 23 Kick warning signs ....................................................................................................................................... 27 Well Control Equipment ............................................................................................................................. 29 Shut-In ......................................................................................................................................................... 61 Driller’s Method .......................................................................................................................................... 76 Wait & Weight Method or Balanced Method............................................................................................. 88 Volumetric Method..................................................................................................................................... 91 Concurrent Method .................................................................................................................................... 99 Choosing the Best Method ....................................................................................................................... 101 Problem Scenarios and their Solutions ..................................................................................................... 117 Case Studies .............................................................................................................................................. 119 Well Control Physical Model ..................................................................................................................... 121 Well Control Software............................................................................................................................... 125 Formula ..................................................................................................................................................... 126

Acknowledgements We would like to thank the entire Department of Petroleum & Gas Engineering of Baluchistan University of Information Technology Engineering and Management Sciences, Quetta, Pakistan for their support, without which this work would not have been possible. We are deeply grateful to Engnr. Yaqoob Tareen for serving as our Advisor in our Final Year Engineering Project, and for the guidance that he has provided us in this work. We would also like to thank him for the education that he has provided us, and for his willingness to assist us in any way possible.

FYP Group # 5 Muhammad Arsalan Sultan Syed Abdul Wakeel Malik Kaleem Ullah Kasi Abdul Rub Matee ullah Muhammad Younas

Abstract Well control is an important component in a drilling operation. Improper well control procedure might cause blowout and blowouts ought to be controlled for a smooth drilling operation. Most well control incidents occur due to a failure to understand the basic principles involved. So proper training and understanding is indispensable for a drilling engineer. Worldwide every company gives training and overview of different well control operations to every drilling engineer. The purpose of taking well control as an engineering project is to contemplate and visualize the importance of well control in any drilling job. For this purpose we have divided our project into three phases, firstly we did the theoretical study along with understanding of all four prominent methods, secondly we went along practical knowledge through well control simulator , thirdly we are developing a software for kill sheet calculations. During the first phase we developed an understanding of different well control operations. For this sole purpose we have studied following well control methods; Driller Method, Wait & Weight Method, Concurrent Method and Volumetric Method. We went through the pros and cons of the above methods. Consequently we created some scenarios and tried to opt the most suitable method on the basis of the theoretical knowledge. In the second phase we designed a physical well control model for getting practical understanding of first phase. Since such models are in common use now-a-days for a better insight comprehension of well control. We tried our level best to make it as realistic as possible. The theme behind the modeling of this physical model is to apply wait and weight and driller’s method. Various factors such as, Human error factors, equipment limitations and procedures all have been considered in the design of this model. In third phase we are developing a well control software in Visual Basic for generating kill sheets. This software would find required numerical values.

Chapter 1 Introduction During the majority of operations associated with drilling, completing, workover and eventually abandoning a well it is necessary to maintain control over the fluids that occur in the pore spaces of formations being penetrated by the well. These fluids can be subject to extreme pressures and temperatures in-situ although these are not pre-requisites for the fluids to cause well control problems. Failure to maintain control over these fluids can result in a spontaneous and sometimes rapid flow into the wellbore. The rate of flow is determined by the degree of imbalance between the wellbore and reservoir pressures combined with the permeability of the reservoir. In its initial stages, such a flow is called a kick. When such a flow is not controlled and deteriorates in an uncontrolled manner it is described as a blowout. Blowouts can have a very visible environmental impact and, for that reason alone are very damaging for the operator. The initial stages of a blowout can also be very hazardous to personnel and cause major damage to equipment in the vicinity of well. Control and recovery cost can be in the order of $10 to $100 million. However, the blowout can also cause significant damage to the producing reservoir through depletion and creation of preferential gas and water flow paths. It can also have a secondary impact on overlaying formation which may become polluted or abnormally pressurized. These factors impact on operations long after the surface environmental impact has been resolved. It is therefore critical that Well Engineering staff know how to manage this hazardthrough: 

Prevention – using primarycontrol techniques



Controland recovery – if an underbalanced situation does occur; how to control it and regain primary control

The procedures associated with regaining of primary well control are called secondary control measures. These aim to regain control with minimum impact to the immediate and long term integrity and productivity of the well. And if these primary and secondary measures fail then more drastic tertiary well control measures may be applied.

The reasons for promoting proper well control and blowout prevention are overwhelming. An uncontrolled flowing well can cause any or all of the following:  Personal injury and/or loss of life  Damage and/or loss of contractor equipment  Loss of operator investment  Loss of future production due to formation damage  Loss of reservoir pressures  Damage to the environment through pollution  Adverse publicity  Negative governmental reaction, especially near populated areas

Chapter 2 Fundamental Principles of Well Control The function of Well Control can be conveniently subdivided into three main categories, A. Primary well control B. Secondary well control C. Tertiary well control

Primary Well Control (HMUD> PF) This is the process of maintaining of sufficient hydrostatic head of fluid in the wellbore (HMUD) to balance the pressure exerted by the fluids in the formation being drilled (PF). However, it should be noted that balancing formation pressure is a theoretical minimum requirement, good drilling practice dictates that a sufficient excess of hydrostatic head over formation pressure, be maintained at all times to allow for contingencies. This excess head is generally referred to as ‘Trip Margin’ or ‘Overbalanced’.

Secondary Well Control (HMUD< PF) If for any reason the effective head in the wellbore should fall below formation pressure, an influx of formation fluid (kick) into the wellbore would occur. If this situation occurs the Blowout Preventers (BOPs) must be closed as quickly as possible to prevent or reduce the loss of mud from the well. The purpose of Secondary Well Control is to rectify the situation by either: 1. Allowing the invading fluid to vent harmlessly at the surface, or 2. Closing the well in. i.e. providing a surface pressure to restore the balance between pressures inside and outside the wellbore. This latter procedure prevents any further influx of formation fluid and allows any one of a variety of ‘Kick Removal’ methods to be applied thus restoring a sufficient hydrostatic head of fluid in the wellbore. This re-establishes the preferred situation of Primary 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 kick is taken with the kick off bottom.  The drill pipe plugs off during a kill operation.  There is no pipe in the hole.  Hole in drill string.  Lost circulation.  Excessive casing pressure.  Plugged and stuck off bottom.  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.

Figure 2.1 Well Control Principles

Pressure

Chapter 3

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 𝐷𝑒𝑝𝑡𝑕 Note:It is always the vertical height of the column which matters not the shape.

Figure 3.1 TVD Factor vs Different Shapes

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 𝑝𝑝𝑔 ∗ 0.052 𝐻𝑦𝑑𝑟𝑜𝑠𝑡𝑎𝑡𝑖𝑐 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑝𝑠𝑖 = 0.052 ∗ 𝐷𝑒𝑛𝑠𝑖𝑡𝑦 𝑝𝑝𝑔 ∗ 𝑇𝑟𝑢𝑒 𝑉𝑒𝑟𝑡𝑖𝑐𝑎𝑙 𝐷𝑒𝑝𝑡𝑕 (𝑓𝑡) Note: True vertical depth will always be considered is calculations not the measured depth.

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. Note: Normally formation pressure gradient value is between 0.433 psi/ft and 0.465 psi/ft.

Table is with respect to different fluid, Formation Fluid

Pressure (psi/ft)

Gradient (SG)

Fresh Water

0.433

1.00

Brackish Water

0.438

1.01

Salt Water

0.442

1.02

Salt Water

0.452

1.04

Salt Water

0.465

1.07

Salt Water

0.478

1.10

Example Area Rocky Mountains and Mid Continent, USA Most Sedimentary Basins worldwide Most Sedimentary Basins worldwide North Sea, South China Sea Gulf of Mexico, USA Some area of Gulf of Mexico

Abnormal Pressure Every pressure which does not conform to the definition given for normal pressure is abnormal. The principal causes of abnormal pressures are:  Under-compaction in shales  Tectonic Causes  Surcharged Shallow Formations  Faulting  Diapirism  Reservoir Structure

Formation Fracture Pressure Formation fracture pressure, or formation breakdown pressure is the pressure required to rupture a formation, so that whole mud can flow into it. The formation breakdown pressure is usually determined for formations just below a casing shoe by means of a leak-off test. This test of the formation strength, also known as a formation integrity test or FIT, is effected after the casing has been run and cemented in place. This allows formations to be tested after the minimum of disturbance and damage due to drilling, and allows a clear indication of strength to be determined for one isolated zone.

Circulation Pressure The circulating pressure provided by the rig pump represents the total pressure required to move mud from the pump through the surface lines, the drillstring, and the jet nozzles and up the annulus to the surface.

Figure 3.2 Circulating Pressure

A small amount of this pressure loss, or friction loss, is used in moving the mud up the annulus. Since the annular space is quite large, the mud moves relatively slowly, thus using very little energy. Annular pressure or friction loss acts as a ‘back pressure’ on formations exposed to the annulus. This causes a slight increase in the total pressure exerted upon them, whenever the pumps are circulating mud. In effect, the bottom hole pressure exerted when circulating, is increased over the static bottom hole pressure. This increase is equal to the annular pressure loss. 𝐶𝑖𝑟𝑐𝑢𝑙𝑎𝑡𝑖𝑛𝑔 𝐵𝑜𝑡𝑡𝑜𝑚𝑕𝑜𝑙𝑒 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑝𝑠𝑖 = 𝑆𝑡𝑎𝑡𝑖𝑐 𝐵𝑜𝑡𝑡𝑜𝑚𝑕𝑜𝑙𝑒 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑝𝑠𝑖 + 𝐴𝑛𝑛𝑢𝑎𝑙𝑟 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐿𝑜𝑠𝑠 (𝑝𝑠𝑖) This could also be expressed in terms of pressure gradient, or of equivalent mud weight units. The advantage of the above equation is that no precise depth need be stated. Converting the pressures to equivalent mud weights we get the following formula: 𝐸𝐶𝐷 𝑝𝑝𝑔 = 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 𝑝𝑝𝑔 +

𝐴𝑛𝑛𝑢𝑙𝑎𝑟 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐿𝑜𝑠𝑠 (𝑝𝑠𝑖 𝑡𝑜 𝑝𝑝𝑔) 𝑇𝑟𝑢𝑒 𝑣𝑒𝑟𝑡𝑖𝑐𝑎𝑙 𝐷𝑒𝑝𝑡𝑕 ∗ 0.052

In general, ECD will be a slight increase of about two or three tenths of a pound per gallon over static mud weight. The effect is increased in deep, slim holes, with high viscosity mud and high pump rates. The loss of the Annular Pressure Loss when circulation stops means that a well close to balance or under-balance, will go further under-balance and flow more readily. It is for this reason that a flow check may reveal a situation which has been hidden by drilling conditions.

Bottomhole Pressure The term ‘bottom hole pressure’, as used here, means the sum total of all pressures being exerted on a well by our operations. Bottom hole pressure is the sum of the hydrostatic pressures exerted by the fluids in the well, plus any circulating friction loss (e.g. Annular Pressure Loss), plus any surface applied back pressures, where appropriate.

Maximum Allowable Annular Surface Pressure The leak-off pressure, PLO, is determined as the maximum surface pressure which the well could stand, with the hydrostatic load of mud in use at the time of the test. This can be described as the Maximum Allowable Annular Surface Pressure (MAASP) with that particular mud weight in use. 𝑀𝐴𝐴𝑆𝑃 = 𝐹𝑜𝑟𝑚𝑎𝑡𝑖𝑜𝑛 𝐵𝑟𝑒𝑎𝑘𝑑𝑜𝑤𝑛 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 + 𝐻𝑒𝑎𝑑 𝑜𝑓 𝑀𝑢𝑑 𝑖𝑛 𝑢𝑠𝑒 (𝑡𝑜 𝑠𝑕𝑜𝑒) Note: Every time the mud weight is changed, the MAASP changes and must be re-calculated. 𝑀𝐴𝐴𝑆𝑃 = 𝐺𝐹𝐵 − 𝐺𝑀𝑢𝑑 ∗ 𝑆𝑕𝑜𝑒 𝐷𝑒𝑝𝑡𝑕, 𝑇𝑟𝑢𝑒 𝑉𝑒𝑟𝑡𝑖𝑐𝑎𝑙 (𝑓𝑡) If a Maximum Equivalent Mud Weight is quoted for formation strength, then the same formula appears as: 𝑀𝐴𝐴𝑆𝑃 = 𝑀𝑎𝑥 𝐸𝑞𝑢𝑖𝑣𝑎𝑙𝑒𝑛𝑡 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 − 𝐶𝑢𝑟𝑟𝑒𝑛𝑡 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 𝑝𝑝𝑔 ∗ 0.052 ∗ 𝑆𝑕𝑜𝑒 𝐷𝑒𝑝𝑡𝑕 𝑇𝑟𝑢𝑒 𝑉𝑒𝑟𝑡𝑖𝑐𝑎𝑙 (𝑓𝑡) This safety factor gives a margin for error. A leak-off test is not usually a precise or high accuracy test, so it is wise to allow a margin, and operate to a somewhat lower formation fracture figure than obtained on test. For example, a 5% safety margin is a commonly used figure. This 5% should be subtracted from the formation breakdown figure, and MAASP values worked out relative to the reduced formation breakdown figures. A simple 5% reduction in MAASP values does not provide the same margin. A 5% reduction implies only 95% confidence in the demonstrated strength, so this is where any reduction ought to be made.

Figure 3.3 Different Pressure Component

Kick

Chapter 4

Introduction Kick A kick is a well control problem in which the pressure found within the drilled rock is higher than the mud hydrostatic pressure acting on the borehole or rock face. 𝐹𝑜𝑟𝑚𝑎𝑡𝑖𝑜𝑛 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 (𝑝𝑠𝑖) > 0.052 ∗ 𝑇𝑟𝑢𝑒 𝑣𝑒𝑟𝑡𝑖𝑐𝑎𝑙 𝐷𝑒𝑝𝑡𝑕 (𝑓𝑡) When this occurs, the greater formation pressure has a tendency to force formation fluids into the wellbore. This forced fluid flow is called a kick. If the flow of formation fluids is successfully controlled, the kick is considered to have been killed. An uncontrolled kick that increases in severity may result in what is known as a “blowout”. A blowout is the uncontrolled release of crude oil and/or natural gas from an oil well or gas well after pressure control systems have failed.

Factors Affecting Kick Severity Several factors affect the severity of a kick. One factor, for example, is the “permeability” of rock, which is its ability to allow fluids to move through the rock. Another factor affecting kick severity is “porosity.” Porosity measures the amount of space in the rock containing fluids. A rock with high permeability and high porosity has greater potential for a severe kick than a rock with low permeability and low porosity. For example, sandstone is considered to have greater kick potential than shale, because sandstone has greater permeability and greater porosity than shale. Yet another factor affecting kick severity is the “pressure differential” involved. Pressure differential is the difference between the formation fluid pressure and the mud hydrostatic pressure. If the formation pressure is much greater than the hydrostatic pressure, a large negative differential pressure exists. If this negative differential pressure is coupled with high permeability and high porosity, a severe kick may occur.

Kick Labels A kick can be labeled in several ways, including one that depends on the type of formation fluid that enteredthe borehole. Known kick fluids include:  Gas  Oil  Water  Magnesium Chloride Water  Hydrogen Sulphide Gas (Sour Gas)

 Carbon Dioxide If gas enters the borehole, the kick is called a "gas kick." Furthermore, if a volume of 20-bbl (3.2 m3) of gas entered the borehole; the kick could be termed a 20-bbl (3.2-m3) gas kick. Another way of labeling kicks is by identifying the required mud weight increase necessary to control the well and kill a potential blowout. For example, if a kick required a 0.7-lbm/gal (84-kg/m3) mud weight increase to control the well, the kick could be termed a 0.7-lbm/gal (84-kg/m3) kick. It is interesting to note that an average kick requires approximately 0.5 lb./gal (60 kg/m3), or less, mud weight increase.

Difference between Kick and Influx Another important thing to be understood is difference between kick and influx. Kick It is an intrusion of unwanted fluids into the wellbore such that the effective hydrostatic pressure of the wellbore fluid falls below the formation pressure. Influx It 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 recognized as an influx, particularly if the formation fluid is gas.

Chapter 5 Kick Indicators It is highly unlikely that a blowout or a well kick can occur without some warning signals. If the crew can learn to identify these warning signals and to react quickly, the well can be shut-in with only a small amount of formation fluids in the wellbore. Smaller kick volumes decrease the likelihood of damage to the well bore and minimize the casing pressures. Kick indicators are classified into two groups:  Primary  Secondary Anytime the well experiences a primary indicator of a kick, immediate action must be taken to shut-in the well. When a secondary indicator of a kick is identified, steps should be taken to verify if the well is indeed kicking. While drilling we have to know about formation pressure, when we fall below the formation pressure more unpredictable things can be happen. We will try to give you a well kick detection list. This will enable you to recognize the kick and can help you take precautionary measures as soon as possible.

Primary Kick Indicators Pit Volume Gain A gain in the total pit volume at the surface, when there are no mud materials being added at the surface, indicates an influx of formation fluids into the wellbore. Fluid influx at the bottom of the hole shows an immediate gain of surface volume due to the incompressibility of a fluid, (i.e. a barrel in at the bottom pushes out an extra barrel at the surface). The influx of a barrel of gas will also push out a barrel of mud at the surface, but as the gas approaches the surface, an additional increase in pit level will occur due to gas expansion. This is a primary indicator of a kick, and the well should be shut-in immediately any time an increase in pit volume is detected.

Figure 5.1 Level measuring device

Increase in Flow Rate An increase in the rate of mud returning from the well above the normal pumping rate indicates a possible influx of fluid into the wellbore or gas expanding in the annulus. Flow rate indicators like the “FloSho” measures small increments in rate of flow and can give warning of kicks before pit level gains can be detected. Therefore, an observed increase in flow rate is usually one of the indicators of a kick. This is a primary indicator of a kick, and the well should be shut-in immediately any time an increase in flow rate is detected.

Figure 5.2 Flow rate measuring device

Positive readingsof a shut-in drill pipe pressure indicate that the well will have to be circulated using the Driller’s or Engineer’s Kill Procedure. If the increase in flow was due to gas expansion in the annulus, the shut-in drill pipe pressure will read zero because no drill pipe underbalance exists.

Flowing Well With Pumps Off When the rig pumps are not flowingthe mud, a continued flow from the well indicates a kick is in progress. An exception is when the mud in the drill pipe is considerably heavier than in the annulus, such as in the case of a slug. Slug Mud is heavy mud which is used to push lighter mud weight down before pulling drill pipe out of hole.

Improper Hole Fill-up on Trips When the drill string is pulled out of the hole, the mud level should decrease by a volume equivalent to the removed steel. If the hole does not require the calculated volume of mud to bring the mud level back to the surface, it is assumed a kick fluid has entered the hole and partially filled the displacement volume of the drill string. Even though gas or salt water may have entered the hole, the well may not flow until enough fluid has entered to reduce the hydrostatic pressure below the formation pressure.

Figure 5.3

Trip Tanks These are small metal tanks with small capacity about 20-40 bbl. with 1 bbl. divisions inside and it is used to monitor the well. There are several operations that we can use the trip tank to monitor the well as follows;  Tripping out of the hole(TOOH): While tripping out of hole, the trip tank is used to track volume of mud replacing volume of drill string. The volume of mud should be equal to displacement volume of any kind of tubular tripped out of hole.  Trip in Hole (TIH): While tripping in hole, the drilling string (bit, BHA and drill pipe) is ran back in the hole, the trip tank must be used to keep track volume gain. The expected volume gain should be equal to the displacement volume of whole string.  Flow check: The trip tank is utilized to determine well condition in order to see if the well is still under static condition.

Secondary Kick Indicators Decrease in Circulating Pressure A pump pressure change may indicate a kick. Initial fluid entry into the borehole may cause the mud to flocculate and temporarily increase the pump pressure. As the flow continues, the low-density influx will percolate through heavier drilling fluids, and the pump pressure may begin to decrease. As the fluid in the annulus becomes less dense, the mud in the drill pipe tends to fall and pump speed may increase. Other drilling problems may also exhibit these signs. A hole in the pipe, called a “washout,” will cause pump pressure to decrease. To verify the cause, the pump should be shut down and the flow from the well should be checked. If the flow continues, the well should be shut-in and checked for drill pipe pressure to determine whether an underbalanced condition exists.

Gradual Increase in Drilling Rate While drilling in the normally pressured shales, there will be a uniform decrease in the drilling rate. Assuming that bit weight, RPM, bit types, hydraulics and mud weight remain fairly constant, the decrease will be due to the increase in shale density. When abnormal pressure is encountered, the density of the shale is decreased and so is the porosity. Higher porosity shales are softer and can be drilled faster. Therefore, the drilling rate will almost always increase as the bit enters abnormally pressured shale. This increase will not be rapid but gradual. A penetration rate recorder simplifies detecting such changes. 𝑑=

𝑟 ) 60𝑁

log⁡ ( log

12𝑊 10 6 𝐷

∗ (15)

String Weight Change Drilling fluid provides a buoyant effect to the drill string and reduces the actual pipe weight supported by the derrick. Heavier muds have a greater buoyant force than less dense muds. When a kick occurs, and low-density formation fluids begin to enter the borehole, the buoyant force of the mud system is reduced, and the string weight observed at the surface begins to increase.

Drilling Break An abrupt increase in bit-penetration rate, called a “drilling break,” is a warning sign of a potential kick. A gradual increase in penetration rate is an abnormal pressure indicator, and should not be misconstrued as an abrupt rate increase. When the rate suddenly increases, it is assumed that the rock type has changed. It is also assumed that the new rock type has the potential to kick (as in the case of a sand), whereas the previously drilled rock did not have this potential (as in the case of shale). Although a drilling break may have been observed, it is not certain that a kick will occur, only that a new formation has been drilled that may have kick potential. It is recommended when a drilling break is recorded that the driller should drill 3-ft to 5-ft (1 to 1.5 m) into the formation and then stop to check for flowing formation fluids. Unfortunately, many kicks and blowouts have occurred because of this lack of flow checking.

Cut Mud Weight Reduced mud weight observed at the flow line has occasionally caused a kick to occur. Some causes for reduced mud weight are: 

Connection Air



Aerated Mud Circulated From The Pits and Down The Drill Pipe

Fortunately, the lower mud weights from the cuttings effect are found near the surface (generally because of gas expansion), and do not appreciably reduce mud density throughout the hole. Statistics shows that gas cutting has a very small effect on bottom hole hydrostatic pressure. An important point to remember about gas cutting is that, if the well did not kick within the time required drilling the gas zone and circulating the gas to the surface, only a small possibility exists that it will kick. Generally, gas cutting indicates that a formation has been drilled that contains gas. It does not mean that the mud weight must be increased.

Chapter 6 Causes of Kicks Kicks occur as a result of formation pressure being greater than mud hydrostatic pressure, which causes fluids to flow from the formation into the wellbore. In almost all drilling operations, the operator attempts to maintain a hydrostatic pressure greater than formation pressure and, thus, prevent kicks; however, on occasion the formation will exceed the mud pressure and a kick will occur. Reasons for this imbalance explain the key causes of kicks(wellbore influx),which are listed below: 

Inefficiency of personnel(Human Error)



Light density fluid in a wellbore



Abnormal Pressure



Unable to keep the hole full all the time while drilling and tripping



Lost circulation



Swabbing



Surging



Mud properties

Lack of knowledge and experience of personnel (Human error) Lacking of well-trained personnel can cause well control incident because they don’t have any ideas what can cause well control problem. For example, personnel may accidentally pump lighter fluid into wellbore and if the fluid is light enough, reservoir pressure can overcome hydrostatic pressure.

Light density fluid in a wellbore It results in decreasing hydrostatic pressure. There are several reasons that can cause this issue such as • Light pills, sweep, and spacer in hole • Accidental dilution of drilling fluid • Gas cut mud

If a kick occurs while drilling, due to insufficient mud density, it is possible that an oversight has occurred or that poor engineering practices were employed. In any event, pressure trends and plots will have to be re-evaluated. Penetration into a geopressured formation without prior indication may have occurred, or a fault or unconformity may have been crossed. Also changes in lithology or drilling practices may have masked a transition zone.

Abnormal pressure If abnormally high pressure zones are over current mud weight in the well, kick will eventually occur. A subsurface condition in which the pore pressure of a geologic formation exceeds or is less than the expected, or normal, formation pressure. When impermeable rocks such as shales are compacted rapidly, their pore fluids cannot always escape and must then support the total overlying rock column, leading to abnormally high formation pressures. Excess pressure, called overpressure or geo pressure, can cause a well to blowout or become uncontrollable during drilling. Severe under pressure can cause the drill pipe to stick to the under pressured formation.

Unable to keep the hole full all the time while drilling and tripping If hole is not full with drilling fluid, overall bottom hole pressure will be decreased. When hydrostatic pressure provided by drilling fluid is less than pore pressure, reservoir fluid can enter into wellbore casing well bore influx. 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 figure. 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.

Figure 6.1

Severe lost circulation Lost circulation usually caused when the hydrostatic pressure of drilling fluid exceeds formation pressure. There are several factors that can cause lost circulation such as, • Mud properties – mud weight is too heavy and too viscous. • High equivalent circulating density (ECD) • High surge pressure due to tripping in hole so fast • Drilling into weak formation strength zones

Swabbing The swabbing is happened when anything in the hole such as a drill string, a logging tool, a completion sting, etc is pulled causing drilling fluid to be swabbed out of a wellbore. Swabbing effect will result in decreasing hydrostatic pressure. 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, stabilizers, 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. The swabbing can be recognized while pulling out of hole by closely monitoring hole fill by using a trip sheet. 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.

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.

Factors affecting swabbing and surging are, 

Pulling speed of pipe



Mud properties



Viscosity



Hole geometry

Chapter 7 Kick Warning Signs In oil well control, a kick should be able to be detected promptly, and if a kick is detected, proper kick prevention operations must be taken immediately to avoid a blowout

Figure 7.1 Deepwater Horizon drilling rig blowout, 21 April 2010

There are various tell-tale signs that signal an alert crew that a kick is about to start. Knowing these signs will keep a kicking oil well under control, and to avoid a blowout:

Sudden increase in drilling rate A sudden increase in penetration rate (drilling break) is usually caused by a change in the type of formation being drilled. However, it may also signal an increase in formation pore pressure, which may indicate a possible kick.

Increase in annulus flow rate If the rate at which the pumps are running is held constant, then the flow from the annulus should be constant. If the annulus flow increases without a corresponding change in pumping rate, the additional flow is caused by formation fluid(s) feeding into the wellbore or gas expansion. This will indicate an impending kick.

Gain in pit volume If there is an unexplained increase in the volume of surface mud in the pit (a large tank that holds drilling fluid on the rig), it could signify an impending kick. This is because as the formation fluid feeds into the wellbore, it causes more drilling fluid to flow from the annulus than is pumped down the drill string, thus the volume of fluid in the pit(s) increases.

Change in pump speed/pressure A decrease in pump pressure or increase in pump speed can happen as a result of a decrease in hydrostatic pressure of the annulus as the formation fluids enters the wellbore. As the lighter formation fluid flows into the wellbore, the hydrostatic pressure exerted by the annular column of fluid decreases, and the drilling fluid in the drill pipe tends to U-tube into the annulus. When this occurs, the pump pressure will drop, and the pump speed will increase. The lower pump pressure and increase in pump speed symptoms can also be indicative of a hole in the drill string, commonly referred to as a washout. Until a confirmation can be made whether a washout or a well kick has occurred, a kick should be assumed.

Improper fill on trips Improper fill on trip occurs when the volume of drilling fluid to keep the hole full on a Trip (complete operation of removing the drillstring from the wellbore and running it back in the hole) is less than that calculated or less than Trip Book Record. This condition is usually caused by formation fluid entering the wellbore due to the swabbing action of the drill string, and, if action is not taken soon, the well will enter a kick state.

Well Control Equipment

Chapter 8

Blowout Preventer Introduction A blowout preventer is a large, specialized valve or similar mechanical device, usually installed redundantly in stacks, used to seal, control and monitor oil and gas wells. Blowout preventers were developed to cope with extreme erratic pressures and uncontrolled flow (formation kick) emanating from a well reservoir during drilling. Kicks can lead to a potentially catastrophic event known as a blowout. In addition to controlling the down hole (occurring in the drilled hole) pressure and the flow of oil and gas, blowout preventers are intended to prevent tubing (e.g. drill pipe and well casing), tools and drilling fluid from being blown out of the wellbore (also known as bore hole, the hole leading to the reservoir) when a blowout threatens. Blowout preventers are critical to the safety of crew, rig (the equipment system used to drill a wellbore) and environment, and to the monitoring and maintenance of well integrity; thus blowout preventers are intended to be fail-safe devices. The term BOP (pronounced B-O-P, not "bop") is used in oilfield vernacular to refer to blowout preventers. The abbreviated term preventer, usually prefaced by a type (e.g. ram preventer), is used to refer to a single blowout preventer unit. A blowout preventer may also simply be referred to by its type (e.g. ram). The terms blowout preventer, blowout preventer stack and blowout preventer system are commonly used interchangeably and in a general manner to describe an assembly of several stacked blowout preventers of varying type and function, as well as auxiliary components. A typical subseadeepwater blowout preventer system includes components such as electrical and hydraulic lines, control pods, hydraulic accumulators, test valve, kill and choke lines and valves, riser joint, hydraulic connectors, and a support frame. Two categories of blowout preventer are most prevalent: ram and annular. BOP stacks frequently utilize both types, typically with at least one annular BOP stacked above several ram BOPs.

Uses Blowout preventers come in a variety of styles, sizes and pressure ratings. Several individual units serving various functions are combined to compose a blowout preventer stack. Multiple blowout

preventers of the same type are frequently provided for redundancy, an important factor in the effectiveness of fail-safe devices. The primary functions of a blowout preventer system are to:  Confine well fluid to the wellbore  Provide means to add fluid to the wellbore  Allow controlled volumes of fluid to be withdrawn from the wellbore Additionally, and in performing those primary functions, blowout preventer systems are used to:  Regulate and monitor wellbore pressure  Center and hang off the drill string in the wellbore  Shut in the well (e.g. seal the void, annulus, between drill pipe and casing)  “Kill” the well (prevent the flow of formation fluid, influx, from the reservoir into the wellbore)  Seal the wellhead (close off the wellbore)  Sever the casing or drill pipe (in case of emergencies)

Types Ram blowout preventer A ram-type BOP is similar in operation to a gate valve, but uses a pair of opposing steel plungers, rams. The rams extend toward the center of the wellbore to restrict flow or retract open in order to permit flow. The inner and top faces of the rams are fitted with packers (elastomeric seals) that press against each other, against the wellbore, and around tubing running through the wellbore. Outlets at the sides of the BOP housing (body) are used for connection to choke and kill lines or valves. Rams, or ram blocks, are of four common types: 1. Pipe 2. Blind 3. Shear 4. Blind shear

Figure 8.1 Cameron Ram-type Blowout Preventer

Pipe rams Close around a drill pipe, restricting flow in the annulus (ring-shaped space between concentric objects) between the outside of the drill pipe and the wellbore, but do not obstruct flow within the drill pipe. Variable-bore pipe rams can accommodate tubing in a wider range of outside diameters than standard pipe rams, but typically with some loss of pressure capacity and longevity.

Blind rams Also known as sealing rams, which have no openings for tubing, can close off the well when the well does not contain a drill string or other tubing, and seal it.

Shear rams Cut through the drill string or casing with hardened steel shears.

Blind shear rams Also known as shear seal rams, or sealing shear rams are intended to seal a wellbore, even when the bore is occupied by a drill string, by cutting through the drill string as the rams close off the well. The upper portion of the severed drill string is freed from the ram, while the lower portion may be crimped and the “fish tail” captured to hang the drill string off the BOP.

In addition to the standard ram functions, variable-bore pipe rams are frequently used as test rams in a modified blowout preventer device known as a stack test valve. Stack test valves are positioned at the bottom of a BOP stack and resist downward pressure (unlike BOPs, which resist upward pressures). By closing the test ram and a BOP ram about the drill string and pressurizing the annulus, the BOP is pressure-tested for proper function.

Figure 8.2 Blowout Preventer diagram showing different types of rams: (a) standard ram (b) pipe ram and (c) shear ram

Annular blowout preventer The annular blowout preventer was invented by Granville Sloan Knox in 1946; a U.S. patent for it was awarded in 1952.Often around the rig it is called the "Hydril", after the name of one of the manufacturers of such devices.

Introduction An annular-type blowout preventer can close around the drill string, casing or a non-cylindrical object, such as the kelly. Drill pipe including the larger-diameter tool joints (threaded connectors) can be "stripped" (i.e., moved vertically while pressure is contained below) through an annular preventer by careful control of the hydraulic closing pressure. Annular blowout preventers are also effective at maintaining a seal around the drillpipe even as it rotates during drilling. Regulations typically require that an annular preventer be able to completely close a wellbore, but annular preventers are generally

not as effective as ram preventers in maintaining a seal on an open hole. Annular BOPs are typically located at the top of a BOP stack, with one or two annular preventers positioned above a series of several ram preventers.

Principle An annular blowout preventer uses the principle of a wedge to shut in the wellbore. It has a donut-like rubber seal, known as an elastomeric packing unit, reinforced with steel ribs. The packing unit is situated in the BOP housing between the head and hydraulic piston. When the piston is actuated, its upward thrust forces the packing unit to constrict, like a sphincter, sealing the annulus or openhole. Annular preventers have only two moving parts, piston and packing unit, making them simple and easy to maintain relative to ram preventers.

Working The original type of annular blowout preventer uses a “wedge-faced” (conical-faced) piston. As the piston rises, vertical movement of the packing unit is restricted by the head and the sloped face of the piston squeezes the packing unit inward, toward the center of the wellbore. In 1972, Ado N. Vujasinovic was awarded a patent for a variation on the annular preventer known as a spherical blowout preventer, so-named because of its spherical-faced head. As the piston rises the packing unit is thust upward against the curved head, which constricts the packing unit inward. Both types of annular preventer are in common use.

Figure 8.3 Annular BOP

Subsea BOP Stack The biggest difference between the more conventional rigs (land, platform and jackup) and floaters (drillships and semi-submersible) is the location and installation of the BOP stack, instead of the stack directly below the rig floor, the BOP’s used on floating rigs are located on the ocean floor. With the stack located on the ocean floor it is not subjected to wave action. When operation commence with a floating rig, first a temporary guide base is installed on the ocean floor. The temporary guide base is connected to the rig by means of four guide lines. The conductor hole is often drilled through the temporary guide base taking returns on the ocean floor, and monitored with TV cameras. After surface casing is set and hung off at the ocean floor (using the mud line

suspension

equipment),

a

permanent guide base is installed. The permanent guide base has four posts sticking up with the guide lines reaching from the top of the posts to the rig. The BOP stack is thoroughly tested at the surface, run down the guide lines and mounted on the permanent guide base. Hydraulic connectors are used to provide a seal between the bottom of the stack and the subsea wellhead. Subsea BOP stack might include, 

Pipe ram preventer



Drilling spool



Blind/shear ram preventer



Casing head housing

Marine Riser A marine riser system is used to provide a return fluid flow path from the wellbore to either a floating drilling vessel (semi-submersible or hull type) or a bottom supported unit, and to guide the drill string and tools to the wellhead on the ocean floor. The floating rigs does not support the casing to be run from ocean floor to sea level. Casing would have tendency to collapse under its own weight and would be subjected to tremendous shear loads. High pressure slip joints and ball joints would have to be manufactured to compensate for heaving of the ship and slight movements off-location. So by placing the stack at ocean floor allows the mud to be circulated to the surface through a low pressure riser and slip joints assembly instead of unsupported casing. All casing strings are hung off on the ocean floor using mud line suspension equipment. A riser is a large diameter pipe connected from the subsea BOP stack to the rig. The riser package includes small diameter chokes and kill lines, control lines of the BOP stack, a ball joint (flexible joint) just above the stackis used in the marine riser system to minimize bending moments, stress concentrations, and problems of misalignment engagement. The angular freedom of a flexible joint is normally 10 degrees from vertical. A flexible joint is always installed at the bottom of the riser system either immediately above the remotely operated connector normally used for connecting/disconnecting the riser from the blowout preventer stack, or above the annular preventer when the annular preventer is placed above the remotely operated connector. A telescoping joint just below the vessel (to compensate for the heave of the ship, a tensioning device to keep the riser in the tension, and sometimes Buoyancy cans to add additional support to the riser in deep water. Often a low pressure diverter system is also attached at the very top of the riser package. Another design feature of the riser system that is important in emergency situations, is the ability to quickly disconnect from the BOP stack. This disconnect feature is used for hurricane evacuation where the seas can render the ball joint and telescoping joint useless. Disconnecting from above the BOP stack leaves the stack in place while the rig is off-location. In the event of uncontrolled blowout, the decision may be made to get the rig location due to fire hazards or aerated water. The risk can be discounted, and the rig moved out of danger. A remotely operated connector (hydraulically actuated) connects the riser pipe to the blowout preventer stack and can also be used as an emergency disconnect from the preventer stack, should conditions warrant.

The marine riser system should have adequate strength to withstand: 

Dynamic loads while running and pulling the blowout preventer stack



Lateral forces from currents and acceptable vessel displacement



Cyclic forces from waves and vessel movement



Axial loads from the riser weight, drilling fluid weight, and any free



Standing pipe within the riser



Axial tension from the riser tensioning system at the surface (which may be somewhat cyclic) or from buoyancy modules attached to the exterior of the riser.

Riser Collapse Since most casing strings and large diameter tools are run through the risers, it has to be constructed of large diameter pipe which has low burst and collapse ratings. It is not necessary to design the riser to withstand high pressures due to the position of BOP stack on the floor. The riser would not be subjected to high pressure since the containment of kick is below the BOP stack.

Subsea Control System The subsea control system operate the subsea BOP stack. Every component of BOP stack operated hydraulically by moving piston up and down or back and forth. Thus the function of BOP control system is to direct the hydraulic fluid to the appropriate side of operating piston and to provide the means for the fluids on the other side to be expelled. On land, jack-up or platform drilling rig the operations of control of the BOP is achieved in a conventional manner by coupling each BOP function to a source of hydraulic power situated at a safe location away from the wellhead. So each BOP function is performed or accomplished by directing the hydraulic power from the control unit back and forth along two large bore lines to the appropriate operating piston. This system uses the minimum number of controlling valves to direct the hydraulic fluid to the required function. It also enables the returning fluid to return to control unit for further use. In subsea the operation becomes much difficult, now it is necessary to control the BOP functions which are located in shallow or deep level seabed. In this conventional method of control lines can’t be applied

since the resulting control lines connecting the BOP to surface would be prohibitively large to handle. Reaction time would also be unacceptable and the consequent pressure drop. That is why, for subsea BOP control systems, indirect operating systems have been developed. There are two types, 1. Indirect Hydraulic System (most common) 2. Multiplex Hydraulic System  Indirect Hydraulic System: In this system the size of control umbilical is reduced by splitting the hydraulic control functions into two,  Transmitting hydraulic power to the BOP down a large diameter line.  Transmitting hydraulic signals down the smaller lines to pilot valves which in turn direct the operating power fluid to the appropriate BOP function. The pilot valves are located in control pods on the BOP stack. In order to provide a complete back-up of the subsea equipment there are two control pods – usually referred to as the blue and yellow pods. No attempt will be made to recover the hydraulic power fluid once it has been used to operate a function since this would increase the number of lines required in the umbilical. Instead the fluid is vented subsea from the control pod.  Multiplex Hydraulic System As greater depths were encountered the problems of umbilical handling and reaction times becomes significant. In order to overcome them, hydraulic lines controlling the pilot valves were replaced by separate electric cables which operate solenoid valves. These valves then send a hydraulic signal to the relevant pilot valve which in turns is actuated and directs power fluid to its associated BOP function. The time division multiplexing system provides simultaneous execution of commands and results in a relatively compact electrical umbilical. This typically consider four power conductors, five conductors for signal transmission and additional backup and instrumentation lines. With the protective coating umbilical has a resulting diameter of 1.5 inches with a weight of 3 lb/ft in air.

Acoustic System: In addition to either of the primary control methods mentioned above, the subsea BOP stack can also be equipped with an acoustic emergency back-up system. In principle this is similar to the other two systems, but with the hydraulic or electric commands to the pilot valves being replaced with acoustic signals. Being a purely back-up system the number of commands is limited to those which might be required in an absolute emergency.

Figure 8.4

Figure shows the general arrangement. Fluid used to operate the functions on the BOP stack is delivered from the hydraulic power unit on command from the central hydraulic control manifold. This contains the valves in the subsea control pods and which are operated either manually or by solenoid actuated air operators. In this way the manifold can be controlled remotely via actuators from the master electric panel (usually located on a rig floor) or from an electric mini-panel (located in a safe area). The system may include several remote mini-panels if desired. An electric power pack with battery back-up provides an independent supply to the panels via the central control manifold. The pilot fluid is sent to the subsea control pods through individual, small diameter hoses bundled around the larger diameter hose which delivers the power fluid. In order to provide complete redundancy for the subsea portion of the control system there are two independent hydraulic hose bundles and two independent control pods. The hydraulic hose bundles (or umbilical) are stored on two hose reels, each of which is equipped with a special manual control manifold so that certain stack functions can be operated whilst the stack is being run. Hydraulic jumper hose bundles connect the central hydraulic control manifold to the two hose reels. Each umbilical is run over a special sheave and terminates in its control pod. For repair purposes each pod along with its umbilical can be retrieved and run independently of the BOP stack. In order to do this, the pod and umbilical is run on a wireline which is usually motion compensated. In some designs of control system, the umbilical is run attached to the riser in order to give it more support and reduce fatigue at hose connections. The pod is still attached to a wireline for retrieval purposes. The design has the advantage of not having to handle the umbilical whenever the pod is pulled but has the disadvantage of requiring more subsea remote hydraulic connections. Guidance of the pod is provided by the guidance frame and guidance wires as shown.

Figure 8.5 Subsea Stack and Choke Manifold Arrangement

Choke Line Friction Losses (CLFL) If shut-in casing pressure (SICP) is held constant until kill rate is achieved, BHP will be increased by an amount equal to CLFL. To accomplish constant BHP, a method must be used while bringing the mud pump to kill rate.If CLFL is not accounted for, casing pressure varies from SICP at pump start up to SICP + CLFL with the pump at kill rate. This results in BHP increasing by an amount equal to CLFL. Another method in case Driller don’t have CLFL reading is keeping the Kill Line gauge constant while bringing the pump up to speed eliminates the effect of CLFL. No pre calculated CLFL information is required. There are four recognized methods of recording choke line friction losses at slow circulating rates of 1 5 bbl/min.

First Method: Record the pressure required to circulate the well through the marine riser with the bop open. Record the pressure required to circulate through a full open choke. CLFL = First pressure reading – Second pressure reading 700 - 500 = 200 psi

Second Method:

Circulate the well through a full open choke with the bop closed and recording the pressure on the (static) kill line. The kill line pressure will reflect the choke line pressure loss. 200 psi in this case

Third Method:

Circulate down the choke line and up the marine riser with the bop open. The pressure required for circulation is a direct reflection of the choke line friction loss. 200psi in this case

Fourth Method:

Circulate down the kill line taking returns through a full open choke with the well bore and riser isolated by closing the BOP’s. Pressure observed is double the CLFL. In this case 400 psi / 2 CLFL = 200 psi

Manifold An arrangement of piping or valves designed to control, distribute and often monitor fluid flow. Manifolds are often configured for specific functions, such as a choke manifold used in well-control operations and a squeeze manifold used in squeeze-cementing work.

Types of Manifold Different Manifolds are configured for different functions, In each case, the functional requirements of the operation have been addressed in the configuration of the manifold and the degree of control and instrumentation required. 

Choke Mnifold



Standpipe Manifold



Kill Manifold



Pump Manifold



Squeeze Manifold



Flowline Manifold

Choke Manifold The choke manifold is an arrangement of valves, fittings, lines and chokes which provide several flow routes to control the flow of mud, gas and oil from t h e annulus during a kick. A set of high-pressure valves and associated piping that usually includes at least two adjustable chokes, arranged such that one adjustable choke may be isolated and taken out of service for repair and refurbishment while well flow is directed through the other one.

Choke Manifold may be referred as, a manifold assembly incorporating chokes, valves and pressure sensors used to provide control of flow back or treatment fluids. Figure shows a typical choke manifold for 5000 psi working pressure Service-Surface Installation.

Standpipe Manifold The standpipe manifold is a series of lines, gauges and valves used for routing mud from the pumps to the standpipe.

The Standpipe Manifold is made of plastic valves and pipes under typical structure of standpipe manifold in drilling field. It controls the path of drilling fluid flow. It allows the flow to be directed to different places. Normally while drilling, the standpipe manifold is set up to direct the flow down the drillstring. Also on the standpipe manifold are positioned pressure gauges that allow the driller to monitor the pump output pressure. This is very important to make sure that drilling continues efficiently and safely.

Kill Manifold In case of increase in well head pressure, the kill manifold can provide a mean of pumping heavy drilling fluid into the well to balance bottom hole pressure so that well kick and blowout can be prevented. In this case, by using blow down lines connected to the kill manifold, the increasing well head pressure also can be released directly for bottom hole pressure release, or water and extinguishing agent can be injected into the well by means of the kill manifold. The check valves on the kill manifold only allow injection of kill fluid or other fluids into the well bore through themselves, but do not allow any backflow so as to perform the kill operation or other operations.

The kill manifold consists of check valves, gate vales, pressure gauges and pipelines. The one end of the kill manifold is connected to the drilling spool and the other end is connected to the pump. Kill manifolds are designed and manufactured in accordance with API 6A&API 16C standards. They are specifically made for injecting heavy mud, water and extinguishant during drilling.

Pump Manifold The arrangement of lines and valves used to direct and control fluid on a pumping unit. Pump Manifold is usually referred as 

Low-pressure Manifold



High-pressure Manifold

The manifold on the pump suction is generally known as the inlet or low-pressure manifold. The corresponding manifold located on the pump discharge is commonly known as the high-pressure or discharge manifold. In most cases, reference to the pump manifold relates to the high-pressure manifold.

Flowline Manifold A pipe fitting with several lateral outlets for connecting flow lines from one or more wells. This connection directs flow to heater-treaters, separators or other devices.

Squeeze Manifold A manifold connected within the surface treating lines that is configured to enable control and routing of fluids during a squeeze operation. Most squeeze manifolds have treating line connections with the tubing string, annulus, pit line and pump unit. Isolation valves enable the appropriate flow path to be selected, and pressure sensors included in tubing and annulus lines monitor the key treatment pressures. In some squeeze treatments, such as squeeze cementing, it may be desirable to reversecirculate excess cement from the tubing string. The squeeze manifold enables a change in fluid routing to be quickly and easily achieved from one station.

Diverter

The diverter is installed on top of the wellhead to enable flow from shallow formations to be diverted away from the work area in case of a shallow gas kick. However, current diverter equipment is not yet designed to withstand an erosive shallow gas kick for a prolonged period. The diverter system is still seen as a means of "buying time" to evacuate the drilling site.Diverters are not used for land operations, unless there is risk of shallow gas. For offshore drilling operations diverters are used when drilling 17.1/2in and 16in hole, any hydrocarbon returns shall be directed away from the rig via a dedicated line, configured to have the minimum elbows, bends and tees that are practically possible. In principle, a diverter system must be installed on each well when both of the following conditions apply: 1. There is a possibility of losing primary well control which may result in a kick situation. 2. The well cannot be closed-in with a BOP stack, because the formation below the stove pipe/marine conductor, conductor string, or surface string is too weak. Fracturing of the formation will occur if the well is closed-in.

Diverter equipment specifications: Flow restrictions in diverter systems should be avoided where possible, because they may lead to formation breakdown and cratering of the well in case of a shallow gas blowout. The minimum required nominal ID of diverter outlets/lines is considered to be 304.8 mm (12"). In principle two outlets are required on the diverter spool. They should face opposite directions to be able to vent flow downwind of the rig. However, one outlet only may be considered, in case there is a prevailing wind direction and the vent line extends a sufficient distance from the rig to permit safe venting. Rigs which can 'weather vane' (i.e. dynamically positioned or turret moored rigs) can have just one diverter line. Diverter lines should be as short as possible, but long enough to conduct flow past the extremity of the offshore drilling structure, or away from any obstacle in land operations. Rig structure and/or cellar design may have to be modified to accommodate straight diverter lines. The minimum rated working pressure of diverter equipment is based on the anticipated backpressure during a shallow gas blowout and therefore largely depends on the size of the diverter lines. The minimum rated working pressure of the recommended large bore diverter line system should be 3450 kPa (500 psi) WP. One must remember that dynamic forces are much higher in the initial stage of diverting a well, when the expanding gas is forcing the mud out of the diverter system.

Diverter Selection Criteria The following considerations should be made when selecting diverter equipment:  The equipment shall be selected to withstand the maximum anticipated surface pressures.  Welded flange or hub connections are mandatory on diverter systems; quick connections in diverter lines are not allowed. Diverter lines should be straight, properly anchored (especially at the end of the lines) and sloping down to avoid blockage of the lines with cuttings, etc.  Installation requirements for wellhead and BOP equipment also apply to diverter equipment.  A diverter system can be a BOP stack system with diverter spool, or a specifically designed and developed diverter system, although the faster closing diverter unit is preferred above a large and slowly closing annular preventer. In any case, the diverter and mud return lines should be separate lines, not partial integrated lines, to avoid gas entering the rig system in case the separating valve between both lines fails to operate properly.  Diverter valves shall be full opening valves with an actuator (pneumatic or hydraulic). The bore of the diverter valves shall be equal to the bore of the diverter lines.

 Each diverter system should incorporate a kill line facility (including a check valve) to be able to pressure- and function test the system and to be able to pump water through the diverter system.  The diverter control system should preferably be self-contained or may be an integral part of the BOP accumulator unit and control system. It shall be located in a safe area away from the drilling floor and have the control functions clearly identified.  When a surface diverter system and a subsea BOP stack are employed, two separate control/accumulator systems are required. This will allow the BOPs to be operated and the riser disconnected in case the diverter control system gets damaged and looses pressure. The diverter control system should be capable of operating the diverter system from two or more locations, one to be located near the driller's position.  It should contain the minimum of functions. Preferably, a one-button or lever-activated function should operate the entire diverter system.  A 1 1/2" hydraulic operating line should be used for diverter systems with a 1 1/2" NPT closing chamber port side. The hydraulic line for the opening chamber port may be 1".  All spare operating lines of the control system and connections which are not used should be properly plugged off.  Control systems of diverters/annular preventers and BOPs should be capable of closing the diverter and annular preventers smaller than 508 mm (20") within 30 seconds, and annular preventers of 508 mm (20") or larger within 45 seconds. Diverter valves should be opened before the diverter element is completely closed.  It should be possible to control pumping operations at the pumps as well as on the drilling floor.  Telescopic joints should incorporate double seals, to improve the sealing capability when gas has to be circulated out of the marine riser.  All fans should be stopped automatically in case of a gas alarm, including the fans inside the accommodation.

 At least one windsock should be installed at any drilling location prior to spudding a well.

Gaskets A. R TYPE OVAL RING GASKET R type oval ring gaskets have the greatest application of all ring gaskets used in industry today. These gaskets fit API 6B and ASME B16.5 flanges. Oval type R gaskets fit all current specification ring grooves, as well as "round bottom" ring grooves found in some older flanges.

B. R TYPE OCTAGONAL RING GASKET: R type octagonal ring gaskets offer an alternative to the more common (for wellheads) R type oval ring gasket. These gaskets also fit API 6B and ASME B16.5 flanges. R type octagonal ring gaskets fit all current specification ring grooves, but operators must use care to avoid their use in "round bottom" ring grooves found in some older flanges.

C. R TYPE COMBINATION RING GASKET: R type combination ring gaskets have different designations on each side. Combination ring gaskets allow the connection of flanges, with the same bolt circle measurement and number of bolt holes that have different designated gaskets. (Such connected flanges may or may not require specially dimensioned bolts).

D. RX TYPE PRESSURE ENERGIZED RING GASKET: RX type ring gaskets have a non-symmetrical octagonal cross-section. This non-symmetrical geometry provides an unbalanced contact with the flange ring groove resulting in coining and sealing on the O.D. of the gasket only. The RX type ring gasket geometry provides a pressure-energized self-sealing effect. RX type ring gaskets increase the stand-off between flange faces and flange bolt length must accommodate this additional stand-off.

E. SRX TYPE PRESSURE ENERGIZED SUBSEA RING GASKET: SRX type ring gaskets have dimensions identical to RX type ring gaskets. SRX type ring gaskets have a special "vent" hole allowing the underwater assembly of flanges. This "vent" hole permits water trapped behind the ring gasket to escape into the assembled equipment bore. All RX gasket sizes may accept modification to the SRX design to facilitate under water assembly of flanges, or retightening should a flange connection leak on first test.

F. BX TYPE PRESSURE ENERGIZED RING GASKET: BX type ring gaskets fit only API flanges designated as 6BX specified in API Spec 6A or 17D flanges specified in Spec 17D. Flanges that utilize BX type ring gaskets have designs that allow face to face contact of the made-up flange connection.

G. SBX TYPE PRESSURE ENERGIZED SUBSEA RING GASKET: SBX type ring gaskets have dimensions identical to BX type ring gaskets. SBX type ring gaskets have a special "vent" hole allowing the underwater assembly of flanges. This "vent" hole permits water trapped behind the ring gasket to escape into the assembled equipment bore.

Wellhead When a well is drilled on land, an interface is required between the individual casing strings and the blowout preventer (BOP) stack. This interface is required for four main reasons. 1. To contain pressure through the interface with the BOP stack. 2. To allow casing strings to be suspended so that no weight is transferred to the drilling rig.

3. To allow seals to be made on the outside of each casing string to seal off the individual annulus. 4. To provide annulus access to each intermediate casing string and the production casing string. 5. We will address each of these points in turn and describe in more detail how this is achieved with the wellhead.

Pressure Containment When drilling a well on land, a spool wellhead system is traditionally used, as shown in Fig. This wellhead is considered a "build as you go" wellhead system that is assembled as the drilling process proceeds.

The spool system consists of the following main components:  Starting casing head.  Intermediate casing spools.  Slip casing hanger and seal.  Tubing spool (if well is to be tested and/or completed).

 Studs, nuts, ring gaskets, and associated accessories required to assemble the wellhead

StartingCasingHead The starting casing head attaches to the surface casing (conductor) by either welding or threading on to the conductor. The top of the starting casing head has a flange to mate with the bottom of the BOP. The flange must meet both size and pressure requirements. The starting casing head has a profile located in the inside diameter (ID) that will accept a slip-and-seal assembly to land and support the next string of casing. The slip-and-seal assembly transfers all of the casing weight to the conductor while energizing a weight-set elastomeric seal.

Intermediate casing spool The intermediate casing spool is typically a flanged-by-flanged pressure vessel with outlets for annulus access. The intermediate casing spool (or spools) is installed after each additional casing string has been run, cemented, and set.

The intermediate casing spool also incorporates a profile located in the ID, which accepts a slip-and-seal assembly similar to the one installed in the starting casing head. This slip and seal will be sized in accordance with the casing program.

Slip casing hanger and seals The bottom section of each intermediate casing spool seals on the outside diameter (OD) of the last casing string that was installed. The bottom flange will mate with the starting casing head or the previous intermediate casing spool. The top flange will have a pressure rating higher than the bottom flange to cope with expected higher wellbore pressures as that hole section is drilled deeper. The slipand-seal casing-hanger assembly Figurehas an OD profile that mates with the internal profile of the starting casing head and intermediate casing spools. Integral to this casing-hanger assembly is a set of slips with a tapered wedge-type back and serrated teeth that bite into the OD of the casing being suspended.

When the casing has been run and cemented, the BOP is disconnected from the casing spool and lifted up to gain access to the spool bowl area. After the slip-and-seal casing-hanger assembly is installed, the traveling block will lower the casing and set a predetermined amount of casing load onto the slip-andseal casing-hanger assembly. The teeth on the slips will engage the pipe OD and transfer the suspended weight of the casing to the starting casing head. As the slips travel down, they are forced in against the casing, applying greater and greater support capacity. As the slips continue to engage the pipe, a load is placed on the automatic weight-set elastomeric seal assembly, sealing the annulus between the casing and the casing head. This installation creates a pressure barrier and isolates the annular pressure below the slip-and-seal casing hanger from the wellbore. Traditionally, mandrel hangers Figureare used only to suspend tubing from the tubing head. Occasionally, they can also be used in intermediate casing spools as an alternative to the slip-and-seal

casing-hanger assembly. The mandrel hanger is a solid body with a through-bore ID similar to that of the tubing or casing run below, and it also has penetrations for downhole safety valve line(s) and temperature and pressure gauges, if required. Traditionally in spool wellheads, elastomeric seals are used to seal the annulus between the casing-spool body and the casing or tubing hanger.

Tubing spool (if well is to be tested and/or completed) The tubing spool, as shown in Fig is the last spool installed before the well is completed. The tubing spool differs from the intermediate spool in one way: it has a profile for accepting a solid body-tubing hanger with a lockdown feature located around the top flange. The lockdown feature ensures that the tubing hanger cannot move because of pressure or temperature. The flange sizes vary in accordance with pressure requirements.

Shut-In

Chapter 9

Early recognition of a kick and rapid shut-in are the keys to effective well control. The well must be shut in immediately when there is a positive indicator of a kick in the form of an increase in pit volume or flow rate. If a secondary indicator of a kick is recognized then the well should be checked for flow before shutting in. It is important to remember that there is no difference between a low flowing well and a full flowing well, because low flow can also rapidly turn into a full flow and blowout. There is some concern about fracturing the well and creating an underground blowout resulting from shutting in the well when a kick occurs. If the well is allowed to flow, it will eventually become necessary to shut in the well, at which time the possibility of fracturing the well will be greater than if the well had been shut in immediately after the initial kick detection. An example is shown, how higher casing pressures results from continuous flow because of failure to close in the well.3 Effect of continuous influx on the casing pressure resulting from failure to close in the well Volume of gas gained (bbl) 20 30 40

Casing Pressure (psi) 1468 1654 1796

If there are any uncertainties, a flow check shall be carried out before starting the shut-in procedures.

Flow Check The flow check procedure can be done during drilling or during tripping.

•

During Drilling, 1. 2. 3.

•

Raise the Kelly and the first tool joint with pumps on Stop the pumps Check any possible flow inside the well During Tripping,

1. 2.

Stop tripping Check any possible flow from the well by means of the possum belly

The check for any flow from the well may be determine by two situations,  Well flows: Carry out the shut-in procedures  Well does not flow: Resume the operation in compliance with the operator’s instructions After shut-in the well has been ascertained, one of the two recommended procedures can be chosen, A. Hard Shut-in B. Soft Shut-in The two shut-in procedures differ for the sequence of the following operations: 

Closing the BOP



Opening of the hydraulic valve on the choke line



Possible closing of the power choke on the choke manifold

The primary argument for the hard shut-in is that it minimizes influx volume, and influx volume is critical to success. Before the advent of modem equipment with remote hydraulic controls, opening choke lines and chokes was time consuming and could permit significant additional influx. With modern equipment, all hydraulic controls are centrally located and critical valves are hydraulically operated. Therefore, the shut-in is simplified and the time reduced. In addition, blowout preventers, like valves, are made to be open or closed while chokes are made to restrict flow. In some instances, during hard shut-in, the fluid velocity through closing blowout preventers has been sufficient to cut out the preventer before it could be closed effectively. The type of procedure is chosen in advance by the company and it depends on how the power choke has been set at the beginning of the operations. Hard Shut-in

Closed Power Choke

Soft Shut-in

Partially open Power Choke

Hard Shut-in

Soft Shut-in

Soft Shut-in Procedure Before starting any operation makesure that the choke manifold is set to circulate the mud to the shale shaker through the half opened power choke and that the internal mechanical valve is open. This is the operational sequence which must be followed, I.

Opening of hydraulic valve on the choke line

II.

Closing of BOP

III.

Closing the power choke

IV.

Recording of the stabilized SIDPP and SICP values and of the pit gain

Hard Shut-in Procedure This is the operational sequence which must be followed, I.

Closing of BOP

II.

Opening of hydraulic valve on the choke line

III.

Recording of the stabilized SIDPP and SICP and pit gain (The choke must be set in the close position)

It

Soft Shut-in

Hard Shut-in

Advantages

Advantages

allows

an It requires less

easier control of time to carry out

the

casing the

pressure

necessary

by operations

reducing

the less

danger

with

formation

of fluid in the well.

fracture

below

the casing shoe. The opening of A

lower

fluid

the

hydraulic volume results in

valve

on

the lower

choke

SICP

line reading.

allows,

on

certain

choke

panels, to keep the

automatic

opening of choke working. Reduction

in It is easier and

water

quicker.

hammering phenomena due to

immediate

shut-in. Disadvantage A

Disadvantage

bigger Greater risk of

formation

fluid fracturing

the

volume will enter formation below intothe well.

the casing shoe.

Shut-in Pressures When a kick sets in, the pressure values within the well are modified and stabilize at values which assure a new equilibrium between bottomhole pressure and formation pressure.

Once the well has been closed and the pressure values have been stabilized, two specific pressure must be read in order to carry out the well control: 1. Shut-in Drill Pipe Pressure (SIDPP) 2. Shut-in Casing Pressure (SICP)

Shut-in Drill Pipe Pressure The shut-in drill pipe pressure is the pressure read (at the drill string) after stabilization, with the well closed and during a kick. Read and record the shut-in drill pipe pressure. If no float is in the drill string, this pressure can be read directly from a pressure tap on the standpipe manifold. Since it is recommended practice however, most drill strings should have floats installed, which will require bumping in order to determine the SIDP. 𝑆𝐼𝐷𝑃𝑃 = 𝑃𝐹 + 𝑃𝐻

Shut-in Casing Pressure The shut-in casing pressure is the pressure read in the casing after stabilization, with the well closed during a kick. Read and record the shut-in casing pressure. Valves on the drilling spool and choke manifold will need to be lined-up so that wellbore pressure is transmitted to the closed drilling choke. The shut-in casing pressure should be read from a gauge installed upstream of the closed choke. 𝑆𝐼𝐶𝑃 = 𝑃𝐹 + 𝑃𝐻𝐺 + 𝑃𝐻

Pit Gain Read and record the pit gain. The amount of influx is important for accurate calculation of the maximum casing pressure. Pit level charts or other volume totalizers can be examined to determine the pit gain.

Time Make a note of the time the kick occurred. Also, keep an accurate log of the entire kill operation as it progresses.

Closing Pressure The proper amount of closing pressure will depend on the size and make of the preventer and the wellbore pressure underneath. The closing pressure should be high enough to prevent wellbore fluid from leaking by the element.

Bit Depth Determine the bit depth from the Driller’s pipe figures. This number is important for a variety of calculations and determinations discussed later in this section.

Example: While drilling at 15,000 ft, the driller observed several primary warning signs of kicks and proceeded to shut in the well. After the shut-in was completed (note: the well was shut in at 6 a.m.), he called company personnel and began recording the pressures and pit gains in Table.3 Shut-in Pressure and Pit Gain Shut-in Time

Shut-in Drillpipe

Shut-in Casing Pressure

Pit Gain

Pressure --

Psi

psi

bbl

6:00 a.m.

50

950

20

6:05 a.m.

750

1000

20

6:10 a.m.

775

1040

20

6:15 a.m.

780

1040

20

Results: After 15 minutes, the final shut-in pressures were recorded as follows: PSIDPP = 780 psi PSICP = 1,040 psi Pit gain = 20 bbl

Well Shut-in Procedure While Drilling

Increase in flow rate out of hole

Increase in penetration rate

Pit volume increase

Procedure 1) Stop drilling 2) Raise the kelly 3) Stop the circulation 4) Perform the flow check and inform the drilling contractor and company representatives

Well does not flows

Well flows

Circulate bottom up for analysis of cuttings and mud characteristics

Open the hydraulic valve on the choke line Close annular BOP Close power choke Record balanced SIDPP and SICP and pit gain

Note: The soft shut-in procedure has been chosen.

Well Shut-in Procedure While Tripping with Drill Pipes

If the mud level in the possum belly doesn’t correspond to the volume of steel pulled out or run in. Procedure

1. Stop trip 2. Perform flow check and inform the drilling contractor and company representative

The well does not flow,  Go back to bottom  Repeat flow check

The well flows       

Install an inside BOP in open position and then close it Open hydraulic valve on the choke line Close annular BOP Close power choke Install the Kelly Open inside BOP if kelly cock has been installed Record balanced SIDPP and SICP and pit gain

The well does not flow Circulate to the surface the bottom influx with well open at normal rate.

Note: The soft shut-in procedure has been chosen.

WellShut-inProcedure While Tripping with Drill Collars

If the mud level in the possum belly doesn’t correspond to the volume of steel pulled out or run in.

Procedure Stop tripping and inform the drilling contractor and the company team

The well flows        

Install the x-over to be connected to inside BOP Install the inside BOP in open position and then close it Opening of hydraulic valve on choke line Closing of annular BOP Closing of power choke Install kelly Opening of inside BOP if lower kelly cock kept as spare has been installed Recording of balanced SIDPP and SICP and pit gain

Note: The soft shut-in procedure has been chosen.

Chapter 10 Driller’s Method A kick must be circulated out of the well, after the initial kick response and the formation flow is stopped, to allow routine operations to be resumed. The kick must be circulated to the surface while wellbore pressure is maintained constant to avoid additional kicks. Well control experts are often strongly opinionated on selecting the better method to circulate an influx out of the wellbore. Driller’s Method is one of the eldest methods for circulation of kick out of well. It is the easiest method. The Driller’s Method is a widely used kick circulation method. It requires almost no calculations, and that makes it practical for application during conventional drilling. Two circulations are necessary for the removal of kick in this method. Kick is taken out of the wellbore in first circulation by use of existing mud. During the first circulation, calculations are done, kill sheets are completed and the mud is weighted up to the required kill weight. In the second circulation, the original mud is replaced by kill mud and further drilling process continues. DM circulates the kick by maintaining the bottomhole pressure constant or, preferably, slightly above the formation pressure, which is controlled based on the pump pressure. This is achieved by adjusting the choke opening.

Advantages 

Circulation begins immediately. It starts as soon as the stabilized pressures are recorded. The driller has no need to follow a drill pipe schedule, since the pump pressure is always held constant as the mud weight is changed. There are also less hole problems related to stopping circulation. The Driller’s Method more easily responds to nozzle plugging problems as there is no break in circulation.



It requires less arithmetic calculations. Simple calculations related to ICP, FCP and new kill mud weight. Especially favorable in case of deviated hole and tapered drill string because complex calculations are needed in other methods.



Mostly used in gas kick cases. As it provide less time for gas migration to surface. As the circulation stop in other methods so there are chances of gas to expand and due to its low

density it will move upward. It will try to pass through the mud and continues to expand while moving up.



It is commonly followed in ballooning formations. Ballooning is a phenomenon occasionally encountered in some formations. Ballooning can be defined as flowback from the well after shutting the pumps off, which is preceded by losses while the pumps were running. Ballooning is often misinterpreted as a kick. If it is decided to kill the well with the Wait & Weight Method, mud weight may be increased due to incorrect measurement of formation pressure. Due to the additional mud weight, BHP increases even further. This can induce more losses and worsen the ballooning problem. Since the Driller’s Method does not require any increase in mud weight during the first circulation, no additional BHP is exerted on the formation. After the first circulation of the Driller’s Method, the situation can be assessed and further course of action can be decided (i.e., drilling ahead with no mud weight increase if ballooning continues).



It provides best features in rigs having slow fluid mixing capability. It provides us more time for making of Kill Mud. If we have to arrange heavy density additives or chemicals then it is useful as it provide us more time for this operation. Especially in cases of offshore wells.



Deepwater wells as chances of hydrates formation due to stop circulation. If gas kicks are taken in deepwater wells, there is a possibility of hydrate formation in the BOP’s or choke/kill lines. The high pressure and low temperature conditions in deepwater are ideal for formation of hydrates when free water comes into contact with gas. Possible long periods of non-circulation with the Wait & Weight Method will make conditions more favorable for hydrate formation due to cooling of mud. Hence, non-circulating times in deepwater wells with a gas influx should be minimized. By establishing circulation as soon as possible with the Driller’s Method, the mud can be kept warm, and hydrate formation may be prevented.

Disadvantages 

More time is required for two circulations.The Wait & Weight Method involves only one circulation while the Driller’s Method involves two circulations. This sounds as if we can always save time by following the Wait & Weight Method. But other factors need to considered. If the time required to mix kill mud is significant, we may not save any time with the W&W Method. We may not be able to circulate all the influx out with just one circulation due to hole conditions, such as gas remaining in the high pockets of the well, poor hole cleaning and bad mud properties. Additional circulations are almost always required for complete removal of the influx and the addition of safety factors in the mud weight. Therefore, the time element may not be significant, and most experts agree that doing it right is more important than doing it faster.



Maximum choke pressure when the top of the influx reaches the surface will be higher if the influx is gas. More wear on surface equipment. The Driller’s Method has a higher risk of surface equipment failure, because a higher surface pressure is expected during Driller’s Method. Maximum casing pressure during the circulation is observed when the top of the gas bubble gets to surface. This may be defined as PMax. The gas flow rate through the mud gas separator is maximum at the same time when PMax is observed. Peak Gas Flow Rate must not exceed the gas handling capacity of the mud gas separator. PMax and peak gas flow rate will be lower with the Wait & Weight Method if kill mud gets into the annulus before the top of the bubble gets to surface. If the Wait & Weight Method is followed, there is a good chance that kill mud will enter the annulus before the top of the bubble gets to surface, and we will likely have lower surface pressures compared with the Driller’s Method.



It produces maximum on-choke time. As Choke operator will have to continuously operate choke for making constant SICP and ICP value and for making constant BHP.

Mud Circulation The Driller’s Method requires two circulations,

First Circulation During the first circulation, the influx is circulated out with the original mud weight. Constant BHP is maintained by holding circulating drill pipe pressure constant through the first circulation (Pump the kick out of the well, using existing mud weight).

Second Circulation If the original mud weight is insufficient to balance the formation pressure, the well is killed by circulating a heavier mud (kill mud) in a second circulation (Pump the kill mud into the well).

Steps for Driller’s Method: Step 1 Upon indication of kick, calculate shut-in drill pipe pressure constant (SIDPP) and shut-in casing pressure constant (SICP). Important! If in doubt at any time during the entire procedure, shut in the well, read and record the shut-in drill pipe pressure and the shut-in casing pressure and proceed accordingly. It is not uncommon for the surface pressures to fluctuate slightly due to temperature, gas migration, or gauge problems. The second statement is extremely important to keep in mind. When in doubt, shut in the well! It seems that the prevailing impulse is to continue circulating regardless of the consequences.

Step 2 Set the pump rate. The mud is not weighted up for the first circulation; therefore, the pump rate is not limited by the weighting material mixing capacity of the rig. However, the maximum pump rate is limited by other factors such as the increased SIDPP, the need for choke adjustment, and surface gas handling equipment. Also, if the choke starts blocking-off, pressure surges will be less at reduced circulating rates.

Experience has shown that one of the most difficult aspects of any kill procedure is bringing the pump to speed without permitting an additional influx or fracturing the casing shoe. This problem is compounded by attempts to achieve a precise kill rate. There is nothing magic about the kill rate used to circulate out a kick. In the early days of pressure control, surface facilities were inadequate to bring an influx to the surface at a high pump speed. Therefore, one-half normal speed became the arbitrary rate of choice for circulating the influx to the surface. However, if only one rate such as the one-half speed is acceptable, problems can arise when the pump speed is slightly less or slightly more than the precise one-half speed. The reason for the potential problem is that the circulating pressure at rates other than the kill rate is unknown. The best procedure is to record and graph several flow rates and corresponding pump pressures as illustrated in Figure.

First Circulation, Step 3 Calculate the Initial Circulating Pressure (ICP) the pressure required on the drill pipe for the first circulation of the well. Initial Circulating Pressure (psi) = Slow Circulation Rate (psi) + Shut-in Drill Pipe Pressure (psi) 𝐼𝐶𝑃 = 𝑃𝑆𝐶𝑅 + 𝑆𝐼𝐷𝑃𝑃

Step 4 Open choke about one quarter, start pump, and break circulation. Adjust the choke opening until the choke pressure equals the closed-in annulus pressure plus the overbalance margin. Record the choke pressures throughout the first circulation.

Step 5 Driller brings pump rate up to Kill Rate. Choke operator should operate the choke so as to keep the casing pressure at or near the shut-in casing pressure (SICP) reading. This step should require less than 5 minutes. Bringing the pump up to speed is one of the most difficult problems in any well control procedure. Experience has shown that the most practical approach is to keep the casing pressure constant at the shut-in casing pressure while bringing the pump to speed. The initial gas expansion is negligible over the allotted time of five minutes required to bring the pump to speed. It is not important that the initial volume rate of flow be exact. Any rate within 10% of the kill rate is satisfactory. This procedure will establish the correct drill pipe pressure to be used to displace the kick. Practically, the rate can be lowered or raised at any time during the displacement procedure. Simply read and record the circulating casing pressure and hold that casing pressure constant while adjusting the pumping rate and establishing a new drill pipe pressure. No more than one to two minutes can be allowed for changing the rate when the gas influx is near the surface because the expansion near the surface is quite rapid.

Step 6 After the pump is at satisfactory Kill Rate, Choke operator should transfer his attention to maintain the initial circulating pressure (ICP) reading on the drill pipe pressure gauge. Displace the influx, keeping the recorded drill pipe pressure constant. ICP should be held constant throughout the whole first circulation by adjusting the choke throughout the whole first circulation, until all of the kick fluid has been circulated out of the well. Pump rate is held constant to Kill Rate during first circulation.

Step 7 Once the influx has been displaced, record the casing pressure and compare with the original shut-in drill pipe pressure (SIDPP) recorded in Step 2.It is important to note that, if the influx has been

completely displaced, the casing pressure should be equal to the original shut-in drill pipe pressure (SIDPP). Consider the U-Tube Model presented in Figure 1 and compare with the U-Tube Model illustrated in Figure 2. If the influx has been properly and completely displaced, the conditions in the annulus side of Figure 1 are exactly the same as the conditions in the drill pipe side of Figure 2. If the frictional pressure losses in the annulus are negligible, the conditions in the annulus side of Figure 1 will be approximately the same as the drill pipe side of Figure 2. Therefore, once the influx is displaced, the circulating annulus pressure should be equal to the initial shut-in drill pipe pressure.

Figure 1

Figure 2

Step 8 If the casing pressure is equal to the original shut-in drill pipe pressure recorded in Step 2, shut in the well by keeping the casing pressure constant while slowing the pumps. If the casing pressure is greater than the original shut-in drill pipe pressure, continue circulating for an additional circulation,

keeping the drill pipe pressure constant and then shut in the well, keeping the casing pressure constant while slowing the pumps.

Step 9 If the shut-in casing pressure is greater than the shut-in drill pipe pressure, repeat Steps 3 through 8.

Step 10 If the kick is out of the hole, shut-in the well and start preparing the kill mud. This assumption is usually made, prior to start of the second circulation.

𝐾𝑖𝑙𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 = 𝑂𝑟𝑖𝑔𝑛𝑎𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 +

SIDP, SICP = 0

SIDP, SICP both are equal and > 0

SIDP > SICP

𝑆𝐼𝐷𝑃𝑃 𝑇𝑉𝐷 ∗ 0.052

The well is dead and the mud density is sufficient to balance the well. The mud weight must be increase to balance the formation pressure. There is still influx from the annulus has occurred during the initial circulation.

Second Circulation, Step 11 Prepare Kill Mud. Raise the mud weight in the suction pit to the density determined in step 10.

Step 12 Determine the number of strokes to the bit by dividing the capacity of the drill string in barrels by the capacity of the pump in barrels per stroke. 𝑉𝑜𝑙𝑢𝑚𝑒 (𝑃𝑖𝑝𝑒) = 𝐿𝑒𝑛𝑔𝑡𝑕 ∗ 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝐹𝑎𝑐𝑡𝑜𝑟 (𝐷𝑃, 𝐻𝑊𝐷𝑃, 𝐷𝐶) 𝑉𝑜𝑙𝑢𝑚𝑒 𝐴𝑛𝑛𝑢𝑙𝑢𝑠 = 𝐿𝑒𝑛𝑔𝑡𝑕 ∗ 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝐹𝑎𝑐𝑡𝑜𝑟 𝐶𝑎𝑠𝑖𝑛𝑔, 𝑂𝑝𝑒𝑛 𝑕𝑜𝑙𝑒

𝑃𝑢𝑚𝑝 𝑆𝑡𝑟𝑜𝑘𝑒𝑠 =

𝑇𝑖𝑚𝑒 =

𝑉𝑜𝑙𝑢𝑚𝑒 𝑃𝑢𝑚𝑝 𝐷𝑖𝑠𝑝𝑙𝑎𝑐𝑒𝑚𝑒𝑛𝑡

𝑃𝑢𝑚𝑝 𝑆𝑡𝑟𝑜𝑘𝑒𝑠 𝑆𝑙𝑜𝑤 𝑃𝑢𝑚𝑝 𝑅𝑎𝑡𝑒

Step 13 Open the choke about one quarter, start the pump and break circulation.

Step 14 Bring the pump to the Kill Rate. As Driller’s is bringing the pump up, Choke operator should maintain the casing pressure to a value at or near to shut-in casing pressure (SICP) reading. Warning!Once the pump rate has been established, no further adjustments to the choke should be required. The casing pressure should remain constant at the initial shut-in drillpipe pressure. If the casing pressure begins to rise, the procedure should be terminated and the well shut in. Again, consider the U-Tube Model in Figure 1. While the kill weight mud is being displaced to the bit on the drill pipe side, under dynamic conditions no changes are occurring in any of the conditions on the annulus side. Therefore, once the pump rate has been established, the casing pressure should not change and it should not be necessary to adjust the choke to maintain the constant drill pipe pressure. If the casing pressure does begin to increase, with everything else being constant, in all probability there is some gas in the annulus. If there is gas in the annulus, this procedure must be terminated. Since the density of the mud at the surface has been increased to the kill, the proper procedure under these conditions would be the Wait and Weight Method. Therefore, the Wait and Weight Method would be used to circulate the gas in the annulus to the surface and control the well.

Step 15 After pumping the number of strokes required for the kill mud to reach the bit, read and record the drill pipe pressure.

Step 16 When Drill Pipe is filled with mud then two options are applied for constant BHP,  Casing pressure is held constant while pumping kill mud from surface to bit and drill pipe pressure is held constant thereafter until kill mud is observed returning to the surface.

 Alternately, during second circulation, a drill pipe pressure schedule can be calculated and followed while pumping kill mud from surface to bit, and drill pipe pressure is held constant thereafter. Usually a graph is made from ICP to FCP for checking how the drill pipe pressure drop, as Kill Mud moves down to bit, without the choke being moved. As Kill Mud is added into the pipe, it moves down toward bit. As it reaches bit (bottom), the drill pipe pressure is just that require circulating the Kill Mud around the well. The drill pipe pressure starts dropping below the initial circulating pressure, as the kill mud starts down the drill pipe, reaching the final circulating pressure when the kill mud reaches the bit. Thereafter the drill pipe pressure is held at the final circulating pressure by controlled opening the choke, as the kill mud moves up the annulus. This FCP value is equal to SCR pressure and increase slightly for the addition of Kill Mud. 𝐹𝐶𝑃 = 𝑃𝑠𝑐𝑟 +

𝐾𝑖𝑙𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 𝑂𝑟𝑖𝑔𝑛𝑎𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡

Step 17 Once Kill Mud reaches surface through bit, stop pumping, shut-in the well and confirm that it is dead. Shut in the well by keeping the casing pressure constant while slowing the pumps. Read and record the shut-in drill pipe pressure and the shut-in casing pressure. Both pressures should be 0.Open the well and check for flow. If the well is flowing, repeat the procedure. If no flow is observed, raise the mud weight to include the desired trip margin and circulate until the desired mud weight is attained throughout the system.

Chapter 11 Wait & Weight Method or Balanced Method Wait & Weight method which is also referred as one circulation method consists of circulating the kick fluid out while the original mud is being displaced simultaneously with the kill mud. It is also commonly known as ‘Engineer’s Method’. It does, at least in theory, kill the well in one circulation. The well is shutin while the mud is weighted up to the required kill weight, calculations are done and kill sheets are prepared.

Advantages 

It kills the well in one circulation.



Minimum on-choke time (as less time for removal of kick is required).



This method is generally faster since kick is circulated out of the well in a minimum of one circulation.



When compared to driller’s method, the wait and weight will generate lower pressure at casing shoe while circulating (Subjects the casing shoe to the minimum amount of pressure due to additional hydrostatic pressure from the mud weight increase).

.



It will generate the lowest pressure on surface equipment.



The annular pressure will usually be lower and the chance of formation breakdown is therefore reduced.



The hole and the wellhead equipment are subjected to high pressures for the shortest possible time since the influx is circulated out and the well is killed in one circulation.

Disadvantages 

The well is shut in for a long period of time with no circulation



Take time to wait for mixing kill weight mud. It may not good idea for waiting if you have weak formations because gas migration will cause increase in bottom hole pressure. You may end up with loss circulation.



The well control process must wait until the kill mud is ready.



Complex calculation is required for deviated wells.



Sufficient weighting material is required to make kill weight mud.



Problems related to stop circulation.



Gas migration (Gas migration in the mud can cause confusion while the kill weight mud is being mixed because bottom pressure, casing and drill pipe pressure will increase)..



In ballooning formations.



Availability of facilities for making of high density mud.



If large increase in mud density required then difficulty to do in one stage.



Requires more calculations than the Driller’s Method.

Steps for Wait & Weight Method 1. Well is closed in and necessary information is recorded. 2. Prepare Kill Mud and calculate Initial Circulating Pressure. 𝐼𝐶𝑃 = 𝑃𝑆𝐶𝑅 + 𝑆𝐼𝐷𝑃𝑃 𝐾𝑖𝑙𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 = 𝑂𝑟𝑖𝑔𝑛𝑎𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 +

𝑆𝐼𝐷𝑃𝑃 𝑇𝑉𝐷 ∗ 0.0522

3. The choke is cracked open and start pump to break circulation. 4. Bring pump to Kill Rate. 5. Choke operator maintains the casing pressure at or near the SICP during which Driller is pumping up. 6. After the pump is at Kill Rate, Choke operator should maintain the ICP on drill pipe pressure gauge. 7. As Kill Mud proceeds down through drill pipe, drill pipe pressure is allowed to drop from ICP to FCP by choke adjustment. 𝐹𝐶𝑃 =

𝐾𝑖𝑙𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 ∗ 𝑆𝐶𝑃 𝑂𝑟𝑖𝑔𝑛𝑎𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡

8. Adjust the choke to maintain this pressure for remaining operation. A reduction in SICP will be seen as kill mud enters annulus, increasing the overall hydrostatic in the annulus. 9. As the influx reaches the surface both SICP and pit volume will increase. 10. When the kill mud reaches surface through bit, stop pumping and shut-in the well. 11. If some value of SICP is still recorded then continue to circulate mud until all the remaining influx remove from the well.

Chapter 12 Volumetric Method The volumetric control method is not a kill method, but rather, it is a method of controlling the bottom hole pressure until provisions can be made to circulate or bullhead kill mud into the well. The essence of volumetric control is to allow controlled expansion of the gas bubble as it migrates up the hole. We allow the gas bubble to expand by bleeding-off mud at the surface while holding casing pressure constant. Casing pressure is held constant only while the mud is being bled-off; at other times it is allowed to increase naturally. Each barrel of mud that we bleed-off at the surface changes the wellbore environment in four ways.  The gas bubble to expand by one barrel  The hydrostatic pressure of the mud in the annulus to decrease  The bottom hole pressure to decrease  The surface casing pressure to stay the same

Volumetric Control Volumetric control is accomplished in a series of steps that causes the bottom hole pressure to rise and fall in succession. We let the gas bubble rise and the bottom hole pressure goes up. Then we bleed mud from the annulus and the bottom hole pressure goes down. Then we let the gas bubble rise, and then bleed mud, and so on. In this way, bottom hole pressure is held within a range of values that is high enough to prevent another influx and low enough to prevent an underground blowout.

Step 1 - Calculations There are three calculations which need to be performed before a volumetric control procedure can be executed. 1. Safety Factor 2. Pressure Increment 3. Mud Increment

Safety Factor The safety factor is an increase in the bottom hole pressure which we allow to occur naturally as gas migrates up the annulus. By allowing the gas bubble to rise in the annulus, we are allowing the bottom hole pressure to increase. It is important that we allow the bottom hole pressure to increase to a value

which is well above the formation pressure to insure that we don't go underbalanced when we bleed mud from the annulus in later steps. An appropriate value for the safetyfactor is in the range of 200 psi in most cases. Depending on the depth, angle and fluid in the well, it may take several hours for the gas bubble to rise sufficiently to increase the casing pressure by 200 psi.Sometimes, depending on how close the shoe is to exceeding its fracture pressure under initial shut-in conditions, it will be advisable to select a safety factor smaller than 200 psi. Any increase in the bottom hole pressure will be reflected as an equal increase in the shoe pressure as well. If the shoe is close to its fracture pressure, then the safety factor will have to be appropriately reduced. If you calculate that a 200 psi safety factor will break the shoe down, then a 100 psi safety factor would be more suitable.

Pressure Increment The pressure increment is the reduction in hydrostatic pressure which occurs each time we bleed a given volume of mud from the annulus. The Drilling Foreman should select a pressure increment which produces a reduction in hydrostatic pressure equal to one-third of the value of the initial safety factor (rounded to the nearest 10 psi). For example, if a 150 psi safety factor was chosen, then the pressure increment should produce a reduction in hydrostatic pressure of 50 psi (i.e., one-third of 150 psi).

𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐼𝑛𝑐𝑟𝑒𝑚𝑒𝑛𝑡 = 𝑆𝑎𝑓𝑒𝑡𝑦 𝑓𝑎𝑐𝑡𝑜𝑟/3 Mud Increment The mud increment is the volume of mud which must be bled from the annulus in order to reduce the annular hydrostatic pressure by the amount of the pressure increment determined above. The mud increment can be calculated with the equation given to the right. It is very important that some means be available to measure the small volumes of mud which are bled off from the annulus.

𝑀𝑢𝑑 𝐼𝑛𝑐𝑟𝑒𝑚𝑒𝑛𝑡 =

𝑃𝐼 ∗ 𝐴𝐶𝐹 𝑀𝑊 ∗ 0.007

PI = Pressure Increment (psi) ACF = Annulus Capacity Factor (bbl/ft) MW = Mud Weight (pcf) For example, if a hydrostatic reduction (pressure increment) of 50 psi is desired and the annulus capacity factor is 0.0714 bbl/ft with a mud weight of 85 pcf, then the proper mud increment is 6 bbls.

Step 2 - Allow Casing Pressure to Increase Establish Safety Factor After the calculations are completed, the next step in Volumetric Control is to wait for the gas bubble to migrate up the hole and cause an increase in the shut-in casing pressure. (In reality, this would be occurring as you were performing your calculations). You should allow the gas bubble to rise until the casing pressure has increased by an amount equal to the safety factor. No mud has been bled off from the annulus, so the hydrostatic.

While Gas Bubble Migrates 𝐵𝑜𝑡𝑡𝑜𝑚 𝐻𝑜𝑙𝑒 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑔𝑜𝑒𝑠 𝑢𝑝 = 𝐻𝑦𝑑𝑟𝑜𝑠𝑡𝑎𝑡𝑖𝑐 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑠𝑡𝑎𝑦𝑠 𝑠𝑎𝑚𝑒 + 𝑆𝑢𝑟𝑓𝑎𝑐𝑒 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 (𝐺𝑜𝑒𝑠 𝑈𝑝) At this point, the bottom hole pressure has also increased by the amount of the safety factor and the well should be safely overbalanced.

Step 3 - Hold Casing Pressure Constant by Bleeding Off the Mud Increment After the safety factor overbalance is applied to the well, the first mud increment can be bled from the well. The manner in which the mud is bled off from the annulus is very important - it must be bled in such a way that the casing pressure remains constant throughout the entire bleeding. This is done to insure that the bottom hole pressure is reduced only by a loss in the mud hydrostatic pressure, and not by an additional loss in surface pressure. During the bleeding process, the hydrostatic pressure is reduced by the pressure increment while the surface pressure is held the same, so the bottom hole pressure is also reduced by the pressure increment.

While Bleeding Mud from the Annulus 𝐵𝑜𝑡𝑡𝑜𝑚 𝐻𝑜𝑙𝑒 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑔𝑜𝑒𝑠 𝑑𝑜𝑤𝑛 = 𝐻𝑦𝑑𝑟𝑜𝑠𝑡𝑎𝑡𝑖𝑐 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑔𝑜𝑒𝑠 𝑑𝑜𝑤𝑛 + 𝑆𝑢𝑟𝑓𝑎𝑐𝑒 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 (𝑠𝑡𝑎𝑦 𝑠𝑎𝑚𝑒) Each time we bleed mud from the annulus, the gas bubble expands to fill the volume vacated by the mud. As the gas bubble expands, the pressure in the bubble decreases according to Boyle's Law.

Step 4 - Wait for Casing Pressure to Rise as the Gas Bubble Migrates Each bleeding of mud from the annulus reduces the bottom hole pressure by the amount of the pressure increment. This decreases our safety factor overbalance. In order to get the full value of overbalance back on the well, we simply wait for the gas bubble to migrate up the annulus. As the gas bubble migrates, both surface pressure and bottom hole pressure increase just as when the safety factor was applied. We wait for the gas bubble to rise until the surface casing pressure has increased by an amount equal to the pressure increment. At this point, we have also increased bottom hole pressure by the amount of the pressure increment, and the well is back at full overbalance.

Step 5 - Hold Casing Pressure Constant by Bleeding Mud from the Annulus Once we have our full overbalance back on the well, we can safely bleed another mud increment from the annulus. As with the first bleeding, this step is accomplished while holding casing pressure constant. This reduces the bottom hole pressure by the amount of the pressure increment because a like amount of mud hydrostatic pressure has been bled from the well. This has also caused the gas bubble to expand by the volume of the mud increment.

Step 6 - Wait for Casing Pressure to Increase as the Gas Bubble Migrates After the bleed step we again wait for the gas bubble to migrate with the well shut in. The bottom hole pressure will rise back to its full overbalanced condition. We know when this has occurred because the casing pressure will have risen by the amount of the pressure increment.

Step 7 - Alternate Holding Casing Pressure Constant and Letting It Rise The remainder of the volumetric control procedure is simply a succession of bleeding and migrating, bleeding and migrating, bleeding and migrating, until the gas has finally migrated all the way to the surface. Each time we bleed we lower the bottom hole pressure, and each time we migrate we raise the bottom hole pressure. During each bleed step we allow the gas bubble to expand which lowers the pressure in the bubble. By the time the gas reaches the surface, it has expanded.

Step 8 - Lubricate Mud into the Well The casing pressure should stop increasing after the gas has reached the surface. The well is stable at this point, but in most cases, you will want to bleed the gas from the well and replace it with mud before attempting further well work. This step involves bleeding gas from the well to reduce the casing pressure by a predetermined increment. Then, a measured volume of mud should be pumped into the well to increase the hydrostatic pressure in the annulus by the amount of surface pressure which was

lost when the gas was first bled off. These steps should be repeated until gas can no longer be bled from the well.

Volumetric Control Example Ali, the ENI Drilling Foreman, was glad that he had been to a well control school last week on his days off; he knew he would need it now. Kicks were common while drilling through "The Trend", but this one had just turned ugly. Just moments after he started pumping using the Engineer's Method, something had plugged him off at the bit. He noticed one of the roustabouts searching for a glove out by the pipe racks. He knew he would have to use Volumetric Control. Ali gathered up the following information and jotted it down in his tally book: Hole Size: 8-1/2" Kick Size: 24 bbl Drill Pipe: 5" X-Hole Mud Weight; 114 pcf Ann. Capacity 0.0459 bbl/ft SICP: 640 psi TD: 14,400' MD/TVD SIDP: 520 psi Shoe Test: 126 pcf EMW Casing Shoe: 12,220' MD/TVD Ali knew the first thing to do was to determine the safety factor, pressure increment and mud increment. He knew he had to check the shoe pressures first. Under shut-in conditions he calculated his shoe pressure as:

𝑆𝑕𝑜𝑤 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 = 𝑇𝑉𝐷 ∗ 𝑀𝑊 ∗ 0.0007 + 𝑆𝐼𝐶𝑃 = (12,220' x 114 pcf x 0.007) + 640 psi = 10,391 psi He knew his shoe would break down at a pressure of,

𝑆𝑕𝑜𝑤 𝐹𝑟𝑎𝑐𝑡𝑢𝑟𝑒 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 = 𝑇𝑉𝐷 ∗ 𝑆𝑕𝑜𝑒 𝑇𝑒𝑠𝑡 ∗ 0.0007 + 𝑆𝐼𝐶𝑃 = (12,220 x 126 pcf x 0.007) = 10,778 psi Ali saw that the casing pressure could rise another 387 psi (10,778 psi - 10,391 psi = 387 psi) before breaking the shoe down, so he decided on a safety factor of 200 psi. His pressure increment was quickly calculated by dividing the safety factor by 3, as such,

Pressure increment = 200psi/3 = 67 psi (or 70 psi) Ali then had to calculate his mud increment (or the volume of mud to generate 70 psi of hydrostatic pressure in his annulus).

𝑀𝑢𝑑 𝐼𝑛𝑐𝑟𝑒𝑚𝑒𝑛𝑡 = 𝑃𝐼 ∗

𝐴𝐶𝐹 ∗ 0.007 𝑀𝑊

=70*0.0459/114*.007 = 4.0 bbls Ali then knew that for every 4.0 bbls of mud he bled from the annulus, the hydrostatic pressure would be reduced by 70 psi. With these calculations completed, he was ready to proceed. Ali had a roughneck bring a chair up to the rig floor because he knew that the operation was going to take a long time. He then told the rig welder to weld a bead in a small tank at the 4.0 barrel mark up from the bottom (Ali had determined that he would use the small tank to measure the mud volume which he bled from the well). Ali sat and waited for the casing pressure to rise. In less than an hour, the casing pressure rose 200 psi, from the initial shut-in value of 640 psi to 840 psi. Ali knew that his well was now safely overbalanced, so he was ready for the first bleed step. The choke manifold was lined up to bleed directly into the small tank through the blooey line out near the reserve pit. He had a roughneck with a walkietalkie out there to measure the volume. Ali cracked the choke and bled-off the first little bit of mud from the annulus; the drop on the casing pressure gauge was imperceptible. He bled a little more mud and the casing pressure gauge dropped five psi. Ali closed the choke and in a little while, the pressure had risen back to 840 psi. He continued to bleed mud in small increments trying to keep the casing pressure as close to 840 psi as possible. Over an hour later, the roughneck finally had 4.0 bbls in the small tank.Ali knew that he had lowered the bottom hole pressure by 70 psi as he had bled the 4.0 bbls from the annulus, so he waited while the gas bubble migrated up the hole and watched as the casing pressure gauge rose an additional 70 psi to 910 psi (840 psi + 70 psi = 910 psi). By this time in the operation, nearly three hours had elapsed. Now that he had his full 200 psi of bottom hole overbalance back on the well, it was time to bleed another 4.0 barrels of mud from the annulus. This time he held the casing pressure as best he could at 910 psi. The roughneck told him when the tank was full.

For the next seven hours, Ali bled mud and then waited, bled more mud and waited some more, and then bled and waited again for a total of fourteen bleed steps. On the fifteenth bleed, with the casing pressure at 1820 psi, Ali started getting gas through the choke. He stopped bleeding and checked to make sure the pipe rams weren't leaking. Everything was in order and he felt fine. Just then the perforating truck pulled up to location to shoot some holes in his drill collars. He'd be circulating within the hour. A plot of Ali's volumetric control procedure is shown in the above Figure You can see that on each bleed step the bottom hole pressure decreased, and on each migrate step the bottom hole pressure increased. Casing pressure rose during each migrate step and was held constant during each bleed step. The gas bubble volume increased by 4.0 bbls during each bleed step and rose from its initial volume of 24 bbls to 84 bbls when it finally reached the surface (24 bbl kick + 60 bbls bled = 84 bbls).

Chapter 13 Concurrent Method This is the most complicated and unpredictable method of the three. Its main value lies in the fact that it combines the driller's and engineer's methods, so that kill operation may be initiated immediately upon receipt of the shut-in pressures. Instead of waiting until all the surface mud has been weighted up, pumping begins immediately at the kill rate and the mud is pumped down as the density is increased. The rate at which the mud density is raised is dependent upon the mixing facilities available and the capability of the crew. The main complication of this method is that the drill pipe can be filled with muds of different densities, making calculation of the bottom hole hydrostatic pressure (and drill pipe pressure) difficult. Provided there is adequate supervision and communication, and the method is completely understood, this can be a very effective way of killing a kick. Figure illustrates the irregularities in drill pipe pressure with kill mud volume, caused by the different densities of the mud. The shut-in procedure is the same as that outlined previously. When all the kick information has been recorded the pumps are activated slowly until the initial circulating pressure has been reached at the designated kill rate. The mud should be weighted up as fast as possible, and, as the mud density changes in the suction pit, the choke operator is informed. The total pump strokes are checked on the drill pipe pressure chart when the new density is pumped and the choke is adjusted to suit the new drill pipe conditions.

With this method, circulation commences immediately and the mud is gradually weighted up as circulation proceeds. This will continue until the final required kill mud reaches surface and the well is dead.

Disadvantages 1. Higher pressures are imposed on the annulus.

2. Barite mixing and mud weight may not be consistent throughout.

Procedure 

With the well shut in, calculate the ICP, the kill mud weight and the FCP.



Rather than stroke increments from surface to bit, determine the pressure reduction required in terms of incremental mud weight until the final kill mud is being circulated. Increasing the mud weight and reducing drill pipe pressure will take place over several circulations.



Bring the pump up to the slow circulation rate, ensuring the drill pipe pressure is equal to the ICP by adjusting the choke.



As the mud density reaches each incremental increase, the drill pipe pressure is reduced through the choke, following the step down chart.



When kill mud reaches surface, the well is dead.



For each incremental increase in mud weight, drill pipe pressure is reduced. When the final kill mud is at the bit, the drill pipe pressure should be at the FCP.

Choosing the Best Method

Chapter 14

Determining the best well control method for most situations involves several considerations including the time required to execute the kill procedure, the surface pressures from the kick, the complexity relative to the ease of implementation, and the downhole stresses applied to the formation during the kick killing process. All points must be analyzed before a procedure can be selected. The following list briefly summarizes the general opinion in the industry regarding these methods, 

The Driller (one circulation) method should be used in most cases.



The Wait & Weight (two circulation) method should be used if a good casing shoe exists and there is going to be a delay in weighting up the system.



The Concurrent method should be used only in rare cases, such as for a severe (1.5 lbm/gal or greater) kick with a large influx and a potential problem with developing lost circulation.

Time Two important considerations relative to time are required for the kill procedure,initial wait time and overall time required. The first concern with time is the amount required to increase the mud density from the original weight to the final kill weight mud. Because some operators are very concerned with pipe sticking during this time, the well-control procedure that minimizes the initial wait time is often chosen. These are the Concurrent method and the Drillers (two circulation) method. In both procedures, pumping begins immediately after the shut-in pressures are recorded. The other important time consideration is the overall time required for the complete procedure to be implemented. Figure 14.1 shows that the one-circulation method requires one complete fluid displacement (i.e., within the drillpipe and the annulus), while the two-circulation method,Figure 14.2, requires the annulus to be displaced twice, in addition to the drillpipe displacement. In certain situations, extra time for the two-circulation method may be extensive with respect to hole stability or preventer wear.

Figure 14.1 Wait & Weight (One Circulation) Method

Figure 14.2 Driller (Two Circulation) Method

Surface Pressures During the course of well killing, surface pressures may approach alarming heights. This may be a problem in gas volume expansion near the surface. The kill procedure with the least surface pressure required to balance the bottomhole formation pressure is important. Figure 14.3and 14.4 show the different surface pressure requirements for several kick situations. The first major difference is noted immediately after the drillpipe is displaced with kill mud. The amount of casing pressure required begins to decrease because of the increased kill mud hydrostatic pressure during the one-circulation procedure. This decrease is not seen in the Drillers (two circulation) method because this procedure does not circulate kill mud initially. In fact, in the Drillers (two circulation) method, the casing pressure increases as the gas-bubble expansion displaces mud from the hole.

Figure 14.3—Static annular pressures for one-circulation method vs. two-circulation method for 10000ft Well

Figure 14.4—Static annular pressure for one-circulation method vs. two-circulation method for 15000ft Well

The second difference in pressure occurs as the gas approaches the surface. The Drillers (two circulation) procedure has higher pressures resulting from the lower density original mud weight. It is interesting to note these high casing pressures that are necessary to suppress the gas expansion to a small degree result in a later arrival of gas at the surface.

Procedure Complexity Process suitability partially depends on the ease with which the procedure can be executed. The same principle holds true for well control. If a kick killing procedure is difficult to comprehend and implement, its reliability diminishes. The concurrent method is less reliable because of its complexity. To perform this procedure properly, the drillpipe pressure must be reduced according to the mud weight being circulated and its position in the pipe. This implies that the crew will inform the operator when a new mud weight is being pumped, that the rig facilities can maintain this increased mud-weight increment, and that the mud-weight position in the pipe can be determined by counting pump strokes. Many operators have stopped using this complex method entirely. One and two circulation methods are used more prominently because of their ease of application. In both procedures, the drillpipe pressure remains constant for long intervals of time. In addition, while displacing the drillpipe with kill mud, the drillpipe pressure decrease is virtually a straight-line relationship, not staggered, as in the concurrent method (Figure14.5).

Figure 14.5Static drillpipe pressure of the Concurrent method

Downhole Stresses Although all considerations for choosing the best method are important, the primary concern should always be the stresses imposed on the borehole wall. If the kick imposed stresses are greater than the formation can withstand, an induced fracture occurs, creating the possibility of an underground blowout. The procedure that imposes the least downhole stress while maintaining constant pressures on the kicking zone is considered the most conducive to safe kick killing. One way to measure downhole stresses is by use of "equivalent mud weights," or the total pressures to a depth converted to lbm/gal mud weight. For example,

𝑒 = 19.23𝑝∑/𝐷𝑒 where, ρe = equivalent mud weight, lbm/gal. The equivalent mud weights for the systems in Figure 14.3 & 14.4 are presented in Figure 14.6 & 14.7. The one circulation method has consistently lower equivalent mud weights throughout the killing process after the drillpipe has been displaced. The procedures generally exhibit the same maximum equivalent mud weights. They occur from the time the well is shut in until the drillpipe is displaced.

Figure14.6 Equivalent mud weight comparison for the Wait & Weight (one circulation) vs. the Drillers (two circulation) kills procedure (0.5-lbm/gal kick at 10,000 ft)

Figure14.7 Equivalent mud-weight comparison for the Wait & Weight (one circulation) vs. Drillers (two circulation) kills procedure (0.5-lbm/gal kick at 15,000 ft)

Figures illustrate an important principle: maximum stresses occur very early in circulation for the deeper depth, not at the maximum casing pressure intervals. The maximum lost-circulation possibilities will not occur at the gas-to-surface conditions, as might seem logical. If a fracture is not created at shut-in, it probably will not occur throughout the remainder of the process. A full understanding of this behavior may calm operators’ concerns about formation fracturing as the gas approaches the surface.

Variables Affecting Kill Procedure Although variables that affect kick-killing do not necessitate a change in the basic procedural structure, they may cause unexpected behaviors that can mislead an operator into choosing the wrong procedure. The one-circulation method will be used in this section to demonstrate the effect of these variables.

Influx Type The influx type entering the wellbore plays a key role in casing pressure behavior. The influx can range from heavy oil to fresh water. The most common is gas or salt water; each has a pronounced casing pressure curve and different downhole effects.

Gas Kick Gas kicks are generally more dramatic than other influx types. Reasons for this include the rate at which gas enters the wellbore, the high casing pressures resulting partially from the low-density fluid, gas expansion as it approaches the surface, fluid migration up the wellbore and fluid flammability. A typical gas-kick casing-pressure curve is shown in Figure 14.8.

Figure14.8 Typical gas-kick casing-pressure curve for the one-circulation method

Gas expanding from a decrease in confining pressures while the fluid is pumped up the wellbore affects the kick killing process. As the gas begins to expand, the previously decreasing casing pressure begins to increase at an accelerating rate. This higher casing pressure may give the false impression that another kick influx is entering the well. Immediately after the gas-to-surface conditions, the casing pressure decreases rapidly, which may give the impression that lost circulation has occurred. Both casing pressure changes are expected behaviors and do not indicate an additional influx or lost circulation. The possibility of lost circulation is smaller at the gas-to-surface conditions than at the initial shut-in conditions.

Figure 14.9 Typical representation of flow rates in and flow rates out of the well during a kick killing operation

Gas migration may cause special problems. There have been numerous recent studies of gravitysegregation phenomena in an effort to quantify a migration rate. Field data from one professional wellkilling corporation suggests a rate of 7 to 15 ft/min in mud systems. Regardless of the rate, the migration effect must be considered because of the potential for gas expansion. If the fluid is not allowed to expand properly during the migration period, trapped pressure will be generated at the surface. If unnecessary expansion occurs, additional formation gas will enter the well.

Example illustrates the gas-migration phenomenon with an actual field case.

Example While drilling a development well from an offshore platform, a kick was taken. The psidp was 850 psi, and the psic was 1,100 psi. Storm conditions forced the tender (barge) to be towed away from the platform to avoid damage to the tender or platform legs. The removal of the tender caused all support services to the platform to be severed, including the mud and pumps.

Solution The engineer on the platform knew the kick would become a problem from gas migration up the annulus. To rectify the situation, he allowed the migration to build pressure on the drillpipe, up to 900 psi, which he used as a 50-psi safety margin. Thereafter, the migration was allowed to build the psidp up to 950 psi before he bled a small volume of mud from the annulus to reduce the drillpipe pressure down to 900 psi. Because bottomhole pressure was still 50 psi more than formation pressure, no additional influx occurred. This procedure was continued until the gas reached the surface, at which time the pressures ceased to increase and remained at 900 psi. After support services were restored to the rig, the gas was pumped from the well, and kill procedures were initiated.

Conclusion This example points out the manner in which gas migration can be safely controlled with the drillpipe pressure acting as a bottomhole pressure indicator.

Saltwater Kicks Saltwater-kick problems differ from gas kick problems. Volume expansion does not occur. Because salt water is denser than gas, casing pressures are lower than for a comparable volume of gas. Shut-in pressures for the 50 bbl (7.9 m3) saltwater kick are approximately the same as those seen in for a 20 bbl (3.2 m3) gas kick under the same conditions.

Figure 14.10 Typical salt water kick casing pressure curve

Hole stability and pipe sticking are generally more severe with a saltwater kick than a gas kick. The saltwater fluid causes a freshwater mud-filter cake to flocculate and create pipe-sticking tendencies and unstable hole conditions. The severity increases with large kick volumes and extended waiting periods before the fluid is pumped from the hole.

Volume of Influx The fluid volume entering the well is a variable controlling the casing pressure throughout the kill process. Increased influx volumes give rise to higher initial psic, as well as greater pressure differences at

the gas-to-surface conditions. Figure 14.11 depicts the importance of quick closure over closure with hesitation.

Figure14.11 Comparison of casing-pressure curves for 10, 20, and 50 bbl kick volumes

Kill Weight Increment Variations The original mud density must be increased in most kick situations to kill the well. The incremental density increase has some effect on casing pressure behavior. In Figure 14.12, the gas-to-surface

pressure conditions are higher than the original shut-in pressures for 0.5 lbm/gal (60 kg/m3) and 1.0 lbm/gal (120 kg/m3) kicks. The 2.0 lbm/gal (240 kg/m3) and 3.0 lbm/gal (360 kg/m3) mud weight increases do not show this tendency. The 3.0-lbm/gal (360-kg/m3) kick has a lower gas-to-surface pressure than at the initial closure. This is caused by suppressed gas expansion, which minimizes the associated pressures. This is generally observed in kicks requiring greater than a 2.0 lbm/gal (240kg/m3) incremental increase.

Figure14.12 Comparison of different required kill-mud weight increments

An important mud-weight variation is the difference between the kill-mud weight necessary to balance bottomhole pressure and the mud weight actually circulated. If the circulated mud is less than the killmud weight, the casing pressure is higher than if kill mud had been used because it was necessary to maintain a balanced pressure at the hole bottom. The equivalent mud weights will then be greater, increasing formation fracture possibility.

Hole Geometry Variations In practical kick-killing situations, hole and drillstringsize changes cause the kick fluid geometry to be altered. This is particularly a problem in deep tapered holes in which several pipe and hole sizes are

used. The influx may occupy a large vertical space at the bottomhole, creating a high casing pressure. As the fluid is pumped into the larger annular spaces, the vertical height is decreased, thus increasing the mud column height and resulting in lower casing pressures. Figs. 4.18a through 4.18c show a typical tapered hole and the associated casing and drillpipe pressure curves.

Figure 14.13 Tapered hole diagram

Figure 14.14 Static drillpipe pressure for a typical tapered string

Figure 14.15 Effect of holesize changes on casing pressure

Problem Scenarios and their Solutions Scenario 1 Gas kick

Solution Driller’s Method

Explanation In case of gas kick we should start killing procedure immediately because if we wait more influx will enter and we would be needing high pressure to remove it and we cannot afford to dos because of MAASP limitation (pressure at the casing shoe is weak).

Scenario 2 Larger gas influx at deeper zones

Solution Wait and Weight method

Explanation Wait and weight method will not allow the gas to expand much and besides it will also save time as it comprises of only one circulation. One thing more this method will exert greater pressure to avoid further entry of influx.

Scenario 3 Larger gas influx at shallow depths

Solution Concurrent method

Explanation Because of large influx we cannot use driller’s method because of lesser hydrostatic pressure and gas will keep entering more. And due to MASSP limitation we cannot use wait and weight method. So the good choice is concurrent method as it will not directly exert greater pressure and will keep removing the influx as the mud is gradually weighted up.

Scenario 4 When bit is off-bottom Solution Volumetric Method Explanation The theory of constant bottom hole pressure fails when the bit is off-bottom so driller’s, wait and weight, concurrent method fails. So the choice is volumetric method

Case Studies Case 1 Hole Size

=

8.5 inch

Hole Depth

=

12336 feet TVD/MD

Casing

=

9-5/8 casing set at 9875 feet TVD/MD

Drill Pipe

=

5 inch, capacity 0.0178 bbl/ft

Heavy Weight Pipe

=

5 inch, 489 feet long, capacity 0.0088 bbl/ft

Drill Collars

=

6-1/4 inch, 902 feet long, capacity 0.006 bbl/ft

Mud Density

=

14.1 ppg

Drill Collars in open hole

=

0.0322 bbl/ft

Drill Pipe/HWDP in open hole

=

0.0473 bbl/ft

Drill Pipe in casing

=

0.0493 bbl/ft

Pumps Displacement

=

0.102 bbl/stroke

Slow Circulation Rate

=

650 psi at 30 spm

Capacities

Fracture mud Density at the casing shoe 16.6 ppg The well has been shut in after a kick Kick Data SIDP

=

530 psi

SICP

=

720 psi

Pit gain

=

10 bbl

The well will be killed using the Driller’s method at 30 spm

Case 2 Hole Size

=

12-1/4 inch

Hole Depth

=

10040 feet TVD, 10300 feet MD

Casing

=

13-3/8 casing set at 7580 feet TVD, 7740 feet MD

Drill Pipe

=

5 inch, capacity 0.0178 bbl/ft

Heavy Weight Pipe

=

5 inch, 490 feet long, capacity 0.0088 bbl/ft

Drill Collars

=

8*3 inch, 575 feet long, capacity 0.0087 bbl/ft

Mud Density

=

11.5 ppg

Drill Collars in open hole

=

0.0836 bbl/ft

HWDP in open hole

=

0.1215 bbl/ft

Drill Pipe in open hole

=

0.1215 bbl/ft

Drill Pipe in casing

=

0.1292 bbl/ft

Pumps Displacement

=

0.102 bbl/stroke

Slow Circulation Rate

=

500 psi at 30 spm

Capacities

A Leak-off test was carried out with a mud density of 10.8 ppg and a surface pressure of 2050 psi was recorded The well has been shut in after a kick Kick Data SIDP

=

600 psi

SICP

=

700 psi

Pit gain

=

10 bbl

The well will be killed using the Wait and Weight method at 30 spm

Well Control Physical Model Introduction Well control model is almost available in every foreign petroleum engineering universities. This initiative was first taken by many oil tycoon companies. The reason for taking this initiative was to give better training to their engineers who will be facing these real situations in field. ExxonMobil, Shell, Eni, were the first companies who built this model. Under the guidance of our Advisor Engnr . Yaqoob Tareen, we also started to work on this model and we provided our department with the “Physical Well Control Model’. The most difficult part in the development of this model was designing, in which our advisor Engnr . Yaqoob Tareen helps us a lot. Still some limitations are remaining in this model which will be modified by the new groups working on this project.

Equipment Following are the list of equipment in physical well control model,  Drill Pipe (Dia 1in, Depth 4.9 ft)  Casing Pipe (Dia 4in, Depth 5 ft)  Pressure Gauges  Valves  Nipple  Pump(0.25 hp)  Mud Tank(Dia 8in., Depth 3 ft)  Air Compressor

Designing The first step in developing of this model was the designing. Some modifications were also done. And then in the end, our final design was presented before our advisor. After his approval we start building model.

Procedure This is the procedure which should be follow, 1. Initially close all the valves 2. Fill the mud tank with low density mud 3. Make the connection of pump with low density mud tank by opening the required valve 4. Now open the valves which are on drill pipe and return line 5. Start the pump and check the flow 6. Reading will be shown on all gauges. Change in reading can be observe by opening or closing of valve on return line, observe the reading after maintaining the position of valve 7. Now start the compressor and build the pressure init 8. Open the valve on compressor for injecting gas kick Note: Remember extra pressure may be created if the valve is completely open for flow. So proper care should be taken before performing this operation 9. Close valves on drill pipe and return line 10. Take the increase in pressure on drill pipe gauge and casing gauge

11. Now perform the kill sheet calculations 12. Prepare the kill mud 13. Close valve which is connecting low density mud tank with pump and open valve of high density mud tank 14. Now perform well control method

Calculations Case 1, The values of first case are, Shut-in Drill Pipe Pressure Shut-in Casing Pressure Orignal Mud Weight

SIDP SICP MW

𝐾𝑖𝑙𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 = 𝑂𝑟𝑖𝑔𝑛𝑎𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 + 𝐾𝑖𝑙𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 = 8.33 +

𝑆𝐼𝐷𝑃 𝑇𝑉𝐷 ∗ 0.052

12 psi 15 psi 8.33

12 5 ∗ 0.052

𝐾𝑖𝑙𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 = 54 𝑝𝑝𝑔

Case 2, The values of second case are, Shut-in Drill Pipe Pressure Shut-in Casing Pressure Orignal Mud Weight

SIDP SICP MW

𝐾𝑖𝑙𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 = 𝑂𝑟𝑖𝑔𝑛𝑎𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 + 𝐾𝑖𝑙𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 = 8.33 +

𝑆𝐼𝐷𝑃 𝑇𝑉𝐷 ∗ 0.052

2 psi 4 psi 8.33

2 5 ∗ 0.052

𝐾𝑖𝑙𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 = 16 𝑝𝑝𝑔

Case 3, The values of third case are, Shut-in Drill Pipe Pressure Shut-in Casing Pressure Orignal Mud Weight

SIDP SICP MW

𝐾𝑖𝑙𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 = 𝑂𝑟𝑖𝑔𝑛𝑎𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 + 𝐾𝑖𝑙𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 = 8.33 +

𝑆𝐼𝐷𝑃 𝑇𝑉𝐷 ∗ 0.052

1 5 ∗ 0.052

𝐾𝑖𝑙𝑙 𝑀𝑢𝑑 𝑊𝑒𝑖𝑔𝑕𝑡 = 12 𝑝𝑝𝑔

1 psi 2 psi 8.33

Well Control Software

Formula 1. 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑔𝑟𝑎𝑑𝑖𝑒𝑛𝑡 (𝑝𝑠𝑖/𝑓𝑡) = 𝑀𝑢𝑑 𝑤𝑒𝑖𝑔𝑕𝑡(𝑝𝑝𝑔) × 0.052 2. 𝑀𝑢𝑑 𝑤𝑒𝑖𝑔𝑕𝑡 (𝑝𝑝𝑔) = 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑔𝑟𝑎𝑑𝑖𝑒𝑛𝑡 (𝑝𝑠𝑖/𝑓𝑡) ÷ 0.052 3. 𝐻𝑦𝑑𝑟𝑜𝑠𝑡𝑎𝑡𝑖𝑐 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 (𝑝𝑠𝑖) = 𝑀𝑢𝑑 𝑤𝑒𝑖𝑔𝑕𝑡 (𝑝𝑝𝑔) × 0.052 × 𝑇𝑉𝐷 (𝑓𝑡. ) 4. 𝐹𝑜𝑟𝑚𝑎𝑡𝑖𝑜𝑛 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒(𝑝𝑠𝑖) = 𝐻𝑦𝑑𝑟𝑜𝑠𝑡𝑎𝑡𝑖𝑐 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑖𝑛 𝑑𝑟𝑖𝑙𝑙 𝑠𝑡𝑟𝑖𝑛𝑔(𝑝𝑠𝑖) + 𝑆𝐼𝐷𝑃𝑃(𝑝𝑠𝑖)

(With bit on bottom) 5. 𝐸𝑞𝑢𝑖𝑣𝑎𝑙𝑒𝑛𝑡 𝑚𝑢𝑑 𝑤𝑒𝑖𝑔𝑕𝑡(𝑝𝑝𝑔) = 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 (𝑝𝑠𝑖) ÷ 𝑇𝑉𝐷(𝑓𝑡) ÷ 0.052 6. 𝐼𝑛𝑖𝑡𝑖𝑎𝑙 𝑐𝑖𝑟𝑐𝑢𝑙𝑎𝑡𝑖𝑛𝑔 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒(𝑝𝑠𝑖) = 𝑆𝐶𝑅(𝑝𝑠𝑖) + 𝑆𝐼𝐷𝑃𝑃 (𝑝𝑠𝑖) 7. 𝐹𝑖𝑛𝑎𝑙 𝑐𝑖𝑟𝑐𝑢𝑙𝑎𝑡𝑖𝑛𝑔 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 (𝑝𝑠𝑖) = 𝑆𝐶𝑅(𝑝𝑠𝑖) × (𝑘𝑖𝑙𝑙 𝑚𝑢𝑑 𝑤𝑒𝑖𝑔𝑕𝑡(𝑝𝑝𝑔) ÷ 𝑜𝑟𝑖𝑔𝑖𝑛𝑎𝑙 𝑚𝑢𝑑 𝑤𝑒𝑖𝑔𝑕𝑡(𝑝𝑝𝑔)) 8. 𝐾𝑖𝑙𝑙 𝑚𝑢𝑑 𝑤𝑒𝑖𝑔𝑕𝑡 (𝑝𝑝𝑔) = (𝑆𝐼𝐷𝑃𝑃(𝑝𝑠𝑖) ÷ 𝑇𝑉𝐷(𝑓𝑡) ÷ 0.052) + 𝑜𝑟𝑖𝑔(𝑖𝑛𝑎𝑙 𝑚𝑢𝑑 𝑤𝑒𝑖𝑔𝑕𝑡(𝑝𝑝𝑔) 9. 𝑆𝑕𝑢𝑡 𝑖𝑛 𝑐𝑎𝑠𝑖𝑛𝑔 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒(𝑝𝑠𝑖) = [(𝑚𝑢𝑑 𝑔𝑟𝑎𝑑(𝑝𝑠𝑖/𝑓𝑡) − 𝑖𝑛𝑓𝑙𝑢𝑥 𝑔𝑟𝑎𝑑(𝑝𝑠𝑖/𝑓𝑡) × 𝑖𝑛𝑓𝑙𝑢𝑥 𝑕𝑒𝑖𝑔𝑕𝑡] + 𝑆𝐼𝐷𝑃𝑃(𝑝𝑠𝑖𝑎) 10. 𝐸𝑞𝑢𝑖𝑣𝑎𝑙𝑒𝑛𝑡 𝑐𝑖𝑟𝑐𝑢𝑙𝑎𝑡𝑖𝑛𝑔 𝑑𝑒𝑛𝑠𝑖𝑡𝑦(𝑝𝑝𝑔) = (𝐴𝑛𝑛𝑢𝑙𝑢𝑠 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑙𝑜𝑠𝑠(𝑝𝑠𝑖) ÷ 𝑇𝑉𝐷(𝑓𝑡) ÷ 0.052) + 𝑜𝑟𝑖𝑔𝑖𝑛𝑎𝑙 𝑚𝑢𝑑 (𝑝𝑝𝑔) 11. 𝐻𝑒𝑖𝑔𝑕𝑡 𝑜𝑓 𝑖𝑛𝑓𝑙𝑢𝑥(𝑓𝑡) = 𝑘𝑖𝑐𝑘 𝑠𝑖𝑧𝑒 (𝑏𝑏𝑙𝑠) ÷ 𝑎𝑛𝑛𝑢𝑙𝑢𝑠 𝑣𝑜𝑙𝑢𝑚𝑒 (𝑏𝑏𝑙𝑠/𝑓𝑡)

𝑆𝐼𝐶𝑃 𝑝𝑠𝑖 −𝑆𝐼𝐷𝑃𝑃 (𝑝𝑠𝑖 ) ) 𝑖𝑛𝑓𝑙𝑢𝑥 𝑕𝑒𝑖𝑔 𝑕𝑡(𝑓𝑡)

12. 𝐺𝑟𝑎𝑑𝑖𝑒𝑛𝑡 𝑜𝑓 𝑖𝑛𝑓𝑙𝑢𝑥 (𝑝𝑠𝑖/𝑓𝑡) = (𝑚𝑢𝑑 𝑤𝑒𝑖𝑔𝑕𝑡(𝑝𝑝𝑔) × 0.052)(

13. 𝑇𝑟𝑖𝑝 𝑚𝑎𝑟𝑔𝑖𝑛 = (𝑠𝑎𝑓𝑒𝑡𝑦 𝑓𝑎𝑐𝑡𝑜𝑟(𝑝𝑠𝑖) ÷ 𝑇𝑉𝐷 ÷ 0.052) + 𝑚𝑢𝑑 𝑤𝑒𝑖𝑔𝑕𝑡 (𝑝𝑝𝑔) 14. 𝑀𝑎𝑥. 𝐴𝑙𝑙𝑜𝑤𝑎𝑏𝑙𝑒 𝑚𝑢𝑑 𝑤𝑒𝑖𝑔𝑕𝑡(𝑝𝑝𝑔) = (𝑠𝑢𝑟𝑓𝑎𝑐𝑒 𝑙𝑒𝑎𝑘 𝑜𝑓𝑓 (𝑝𝑠𝑖) ÷ 𝑠𝑕𝑜𝑒 𝑇𝑉𝐷(𝑓𝑡) ÷ 0.052) + 𝑡𝑒𝑠𝑡 𝑚𝑢𝑑 (𝑝𝑝𝑔) 15. 𝑁𝑒𝑤 𝑀𝐴𝐴𝑆𝑃(𝑝𝑠𝑖) = (𝑀𝐴𝑋. 𝐴𝑙𝑙𝑜𝑤𝑎𝑏𝑙𝑒 𝑚𝑢𝑑 𝑤𝑑𝑒𝑖𝑔𝑕𝑡 (𝑝𝑝𝑔) − 𝑐𝑢𝑟𝑟𝑒𝑛𝑡 𝑚𝑢𝑑 𝑤𝑒𝑖𝑔𝑕𝑡(𝑝𝑝𝑔))

16. 𝐵𝑎𝑟𝑖𝑡𝑒 𝑡𝑜 𝑟𝑎𝑖𝑠𝑒 𝑚𝑢𝑑 𝑤𝑒𝑖𝑔𝑕𝑡 (𝑙𝑏𝑠/𝑏𝑏𝑙) =

17. 𝐾𝑖𝑐𝑘 𝑡𝑜𝑙𝑒𝑟𝑎𝑛𝑐𝑒 (𝑝𝑝𝑔) =

(𝑘𝑖𝑙𝑙 𝑚𝑢𝑑 𝑤𝑒𝑖𝑔 𝑕𝑡(𝑝𝑝𝑔 )−𝑜𝑙𝑑 𝑚𝑢𝑑 𝑤𝑒𝑖𝑔 𝑕𝑡(𝑝𝑝𝑔 ) (35.8−𝑘𝑖𝑙𝑙 𝑚𝑢𝑑 𝑝𝑝𝑔 )

× 1500

(𝑀𝐴𝐴𝑆𝑃 −(𝑚𝑢𝑑 𝑔𝑟𝑎𝑑 (𝑝𝑠𝑖 /𝑓𝑡 )−𝑖𝑛𝑓 𝑙𝑢𝑥 𝑔𝑟𝑎𝑑 (𝑓𝑡 ))×(𝑖𝑛𝑓𝑙𝑢𝑥 𝑕𝑒𝑖𝑔 𝑕𝑡(𝑓𝑡 ) 𝑇𝑉𝐷(𝑓𝑡)×0.052

18. 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑑𝑟𝑜𝑝 𝑝𝑒𝑟 𝑓𝑡 𝑡𝑟𝑖𝑝𝑝𝑖𝑛𝑔(𝑑𝑟𝑦 𝑝𝑖𝑝𝑒)(𝑝𝑠𝑖) =

𝑚𝑢𝑑 𝑔𝑟𝑎𝑑 (𝑝𝑠𝑖 /𝑓𝑡 )×𝑚𝑒𝑡𝑎𝑙 𝑑𝑖𝑠𝑝 (𝑏𝑏𝑙𝑠 /𝑓𝑡 ) 𝑐𝑎𝑠𝑖𝑛𝑔 𝑐𝑎𝑝

𝑏𝑏𝑙𝑠 𝑓𝑡

−𝑚𝑒𝑡𝑎 𝑙 𝑑𝑖𝑠𝑝 (

𝑏𝑏𝑙𝑠 𝑓𝑡

)

𝑚𝑢𝑑 𝑔𝑟𝑎𝑑 (𝑝𝑠𝑖 /𝑓𝑡 )×(𝑚𝑒𝑡𝑎𝑙 𝑑𝑖𝑠𝑝 (𝑏𝑏𝑙𝑠 /𝑓𝑡 )

19. 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑑𝑟𝑜𝑝 𝑝𝑒𝑟 𝑓𝑡 𝑡𝑟𝑖𝑝𝑝𝑖𝑛𝑔(𝑤𝑒𝑡 𝑝𝑖𝑝𝑒)(𝑝𝑠𝑖) =

20. 𝐶𝑜𝑛𝑣𝑒𝑟𝑠𝑖𝑜𝑛 𝑜𝑓 𝑝𝑖𝑝𝑒 𝑑𝑖𝑎𝑚𝑒𝑡𝑒𝑟 𝑡𝑜 𝑏𝑏𝑙𝑠/𝑓𝑡 =

21. 𝑂𝑝𝑒𝑛 𝑕𝑜𝑙𝑒 𝑐𝑎𝑝𝑎𝑐𝑖𝑡𝑦(𝑏𝑝𝑓) =

22. 𝐶𝑎𝑠𝑖𝑛𝑔 𝑐𝑎𝑝𝑎𝑐𝑖𝑡𝑦(𝑏𝑝𝑓) =

𝐷2 1029.4

𝑎𝑛𝑛𝑙𝑢𝑠

= 𝑏𝑏𝑙𝑠/𝑓𝑡 𝑜𝑟

(𝑂𝐻 𝑑𝑖𝑎 (𝑖𝑛𝑐 𝑕𝑒𝑠))2 1029.4

(𝑐𝑎𝑠𝑖𝑛𝑔 𝑖𝑑 (𝑖𝑛𝑐 𝑕𝑒𝑠))2 1029.4

23. 𝐷𝑟𝑖𝑙𝑙 𝑠𝑡𝑟𝑖𝑛𝑔 𝑐𝑎𝑝𝑎𝑐𝑖𝑡𝑦(𝑏𝑝𝑓) =

𝑏𝑏𝑙𝑠 ) 𝑓𝑡 𝑏𝑏𝑙𝑠 𝑣𝑜𝑙𝑢𝑚𝑒 ( 𝑓𝑡

+𝑝𝑖𝑝𝑒 𝑑𝑖𝑠𝑝 (

(𝑝𝑖𝑝𝑒 𝑑𝑖𝑎 (𝑖𝑛𝑐 𝑕𝑒𝑠))2 1029.4

24. 𝑂𝑝𝑒𝑛 𝑕𝑜𝑙𝑒 𝑣𝑜𝑙𝑢𝑚𝑒(𝑏𝑏𝑙) = 𝑜𝑝𝑒𝑛 𝑕𝑜𝑙𝑒 𝑐𝑎𝑝 × 𝑙𝑒𝑛𝑔𝑡𝑕 (𝑓𝑡)

𝐷 2 −𝑑 2 1029.4

)

= 𝑏𝑏𝑙𝑠/𝑓𝑡

25. 𝐶𝑎𝑠𝑖𝑛𝑔 𝑣𝑜𝑙𝑢𝑚𝑒(𝑏𝑏𝑙) = 𝐶𝑎𝑠𝑖𝑛𝑔 𝑐𝑎𝑝𝑎𝑐𝑖𝑡𝑦 × 𝐿𝑒𝑛𝑔𝑡𝑕 (𝑓𝑡) 26. 𝐷𝑟𝑖𝑙𝑙 𝑠𝑡𝑟𝑖𝑛𝑔 𝑣𝑜𝑙𝑢𝑚𝑒(𝑏𝑏𝑙) = 𝐷𝑟𝑖𝑙𝑙 𝑝𝑖𝑝𝑒 𝑐𝑎𝑝𝑎𝑐𝑖𝑡𝑦 × 𝐿𝑒𝑛𝑔𝑡𝑕 (𝑓𝑡)

𝑷𝒖𝒎𝒑 𝒐𝒖𝒕𝒑𝒖𝒕:

𝑇𝑟𝑖𝑝𝑙𝑒𝑥 𝑝𝑢𝑚𝑝𝑠:

𝑂𝑢𝑡𝑝𝑢𝑡 𝑏𝑏𝑙/𝑠𝑡𝑘 = 0.000243 × (𝑙𝑖𝑛𝑒𝑟 𝐼𝐷 𝑖𝑛𝑐𝑕𝑒𝑠)2 × 𝑠𝑡𝑟𝑜𝑘𝑒 (𝑖𝑛𝑐𝑕𝑒𝑠) × 𝐸𝐹𝐹 %

𝐷𝑢𝑝𝑙𝑒𝑥 𝑝𝑢𝑚𝑝:

𝑂𝑢𝑡𝑝𝑢𝑡 𝑏𝑏𝑙/𝑠𝑡𝑘 = 0.000162 × [2 × (𝑙𝑖𝑛𝑒𝑟 𝐼𝐷 𝑖𝑛𝑐𝑕𝑒𝑠)2 − (𝑅𝑜𝑑 𝑂𝐷 𝑖𝑛𝑐𝑕𝑒𝑠)2 ] × 𝑠𝑡𝑟𝑜𝑘𝑒 (𝑖𝑛𝑐𝑕𝑒𝑠) × 𝐸𝐹𝐹%

𝑷𝒖𝒎𝒑 𝒓𝒂𝒕𝒆𝒔:

𝑅𝑎𝑡𝑒 (𝑏𝑝𝑚) = 𝑜𝑢𝑡𝑝𝑢𝑡 𝑏𝑏𝑙/𝑠𝑡𝑘 × 𝑆𝑃𝑀

𝑷𝒖𝒎𝒑 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆:

𝑵𝒆𝒘 𝒑𝒖𝒎𝒑 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝒇𝒐𝒓 𝒓𝒂𝒕𝒆 𝒄𝒉𝒂𝒏𝒈𝒆

𝑛𝑒𝑤 𝑟𝑎𝑡𝑒 𝑏𝑝𝑚 2 𝑁𝑒𝑤 𝑃𝑃 (𝑝𝑠𝑖) = ( ) × 𝑜𝑙𝑑 𝑃𝑃(𝑝𝑠𝑖) 𝑜𝑙𝑑 𝑟𝑎𝑡𝑒 𝑏𝑝𝑚

𝑵𝒆𝒘 𝒑𝒖𝒎𝒑 𝒑𝒓𝒆𝒔𝒔𝒖𝒓𝒆 𝒇𝒐𝒓 𝒅𝒆𝒏𝒔𝒊𝒕𝒚 𝒄𝒉𝒂𝒏𝒈𝒆

𝑁𝑒𝑤 𝑃𝑃 (𝑝𝑠𝑖) =

𝑛𝑒𝑤 𝑚𝑤(𝑝𝑝𝑔) × 𝑜𝑟𝑖𝑔𝑖𝑛𝑎𝑙 𝑃𝑃(𝑝𝑠𝑖) 𝑜𝑟𝑖𝑔𝑖𝑛𝑎𝑙 𝑚𝑤(𝑝𝑝𝑔)