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

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.

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

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 (H

> P

)

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 (H

< P

)

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.

Pressure

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) Example Area

Fresh Water 0.433 1.00 Rocky Mountains and

Mid Continent, USA

Brackish Water 0.438 1.01 Most Sedimentary

Basins worldwide

Salt Water 0.442 1.02 Most Sedimentary

Basins worldwide

Salt Water 0.452 1.04 North Sea, South China

Sea

Salt Water 0.465 1.07 Gulf of Mexico, USA

Salt Water 0.478 1.10 Some area of Gulf of

Mexico

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

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.

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

𝑇𝑟𝑢𝑒 𝑣𝑒𝑟𝑡𝑖𝑐𝑎𝑙 𝐷𝑒𝑝𝑡𝑕 ∗ 0.052 (𝑝𝑠𝑖 𝑡𝑜 𝑝𝑝𝑔)

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 = 𝐺_𝐹𝐵− 𝐺_𝑀𝑢𝑑 ∗ 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.

Kick

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)



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.

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.

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.

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 = log⁡(

𝑟 60𝑁) log 12𝑊

106_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.

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

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

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.

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 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.

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.

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.

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



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 reverse-circulate 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.

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).