Oil Well Planning

Drilling optimization requires detailed engineering in all aspects of well planning, drilling implementation, and post-run evaluation Effective well planning optimizes the boundaries, constraints, learning, nonproductive time, and limits and uses new technologies as well as tried and true methods. Use of decision support packages, which document the reasoning behind the decision-making, is key to shared learning and continuous improvement processes. It is critical to anticipate potential difficulties, to understand their consequences, and to be prepared with
contingency plans. Post-run evaluation is required to capture learning.
Drilling Planning

Many of the processes used are the same as used during the well planning phase, but are conducted using new data from the recent drilling events. Depending on the phase of planning and whether you are the operator
or a service provider, some constraints will be out of your control to alter or influence (e.g., casing point selection, casing sizes, mud weights, mud types, directional plan, drilling approach such as BHA types or new technology
use). There is significant value inbeing able to identify alternate possibilities for improvement over current methods, but well planning must consider future availability of products and services for possible well interventions.
When presented properly to the groups affected by the change, it is possible to learn why it is not feasible or to alter the plan to cause improvement. Engineers must understand and identify the correct applications for technologies to reduce costs and increase effectiveness.Acorrect application understands the tradeoffs of risk versus rewardandcosts versus benefits.

Boundaries Boundaries are related to the “rules of the game” established by the company or companies involved. Boundaries are criteria established by management as “required outcomes or processes” and may relate to
behaviors, costs, time, safety, and production targets.
Constraints Constraints during drilling may be preplanned trip points for logs, cores, casing, and BHA or bit changes. Equipment, information, human resource knowledge, skills and availability, mud changeover, and dropping balls for downhole tools are examples of constraints on the plan and its implementation.
The Learning Curve Optimization’s progress can be tracked using learning curves that chart the performance measures deemed most effective for the situation and then applying this knowledge to subsequent wells.
Learning curves provide a graphic approach to displaying the outcomes. Incremental learning produces an exponential curve slope. Step changes may be caused by radically new approaches or unexpected trouble. With
understanding and planning, the step change will more likely be in a positive direction, imparting huge savings for this and future wells. The curve slope defines the optimization rate. The learning curve can be used to demonstrate the overall big picture or a small component that affects the overall outcome. In either case, the curve measures the rate of change of the parameter you choose, typically the “performance measures” established by you and your team. Each performance measure is typically plotted against time, perhaps the chronological order of wells drilled as shown in figure below:

Cost Estimating Oneof the mostcommonand critical requests of drilling engineers is to provide accurate cost estimates, or authority for expenditures (AFEs). The key is to use a systematic and repeatable approach that takes
into account all aspects of the client’s objectives. These objectives must be clearly defined throughout the organization before beginning the optimization and estimating process. Accurate estimating is essential to maximizing a company’s resources. Overestimating a project’s cost can tie up capital that could be used elsewhere, and underestimating can create budget shortfalls affecting overall economics.
Integrated Software Packages With the complexity of today’s wells, it is advantageous to use integrated software packages to help design all aspects of the well. Examples of these programs include

• Casing design
• Torque and drag
• Directional planning
• Hydraulics
• Cementing
• Well control
Decision Support Packages Decision support packages document the reasoning behind the decisions that are made, allowing other people to understand the basis for the decisions. When future well requirements change, a decision trail is available that easily identifies when new choices may be needed and beneficial.
Performance Measures Common drilling optimization performance measures are cost per foot of hole drilled, cost per foot per casing interval, trouble time, trouble cost, and AFEs versus actual costs.
Systems Approach Drilling requires the use of many separate pieces of equipment, but they must function as one system. The borehole should be included in the system thinking. The benefit is time reduction, safety improvement, and production increases as the result of less nonproductive time and faster drilling. For example, when an expected average rate of penetration (ROP) and a maximum instantaneous ROP have been identified, it is possible to ensure that the tools and borehole will be able to support that as a plan. Bit capabilities must be matched to the rpm, life, and formation. Downhole motors must provide the desired rpm and power at the flow rate being programmed. Pumps must be able to provide the flow rate and pressure as planned.
Nonproductive Time Preventing trouble events is paramount to achieving cost control and is arguably the most important key to drilling a cost-effective, safe well. Troubles are “flat line” time, a terminology emanating from the days versus depth curve when zero depth is being accomplished for a period of days, creating a horizontal line on the graph. Primary problems invariably cause more serious associated problems. For example, surge pressures can cause lost circulation, which is the most common cause of blowouts. Excessive mud weight can cause differential sticking, stuck pipe, loss of hole, and sidetracking. Wellbore instability can cause catastrophic loss of entire hole sections. Key seating and pipe washouts can cause stuck pipe and a fishing job.
When a trouble event leads to a fishing job, “fishing economics” should be performed. This can help eliminate emotional decisions that lead to overspending. Several factors should be taken into account when determining
whether to continue fishing or whether to start in the first place.
The most important of these are replacement or lost-in-hole cost of tools and equipment, historical success rates (if known), and spread rate cost of daily operations. These can be used to determine a risk-weighted value of
fishing versus the option to sidetrack.
Operational inefficiencies are situations for which better planning and implementation could have saved timeandmoney. Sayings such as“makin’ hole” and “turnin’ to the right” are heard regularly in the drilling business.
These phases relate the concept of maximizing progress. Inefficiencies which hinder progress include
• Poor communications
• No contingency plans and “waiting on orders” (WOO)
• Trips
• Tool failure
• Improper WOB and rpm (magnitude and consistency)
• Mud properties that may unnecessarily reduce ROP (spurt loss, water loss and drilled solids)
• Surface pump capacities, pressure and rate (suboptimum liner selection and too small pumps, pipe, drill collars)
• Poor matching of BHA components (hydraulics, life, rpm, and data acquisition rates)
• Survey time
Limits Each well to be drilled must have a plan. The plan is a baseline expectation for performance (e.g., rotating hours, number of trips, tangibles cost). The baseline can be taken from the learning curves of the best experience that characterizes the well to be drilled. The baseline may be a widely varying estimate for an exploration well or a highly refined measure in a developed field. Optimization requires identifying and improving on the limits that play the largest role in reducing progress for the well being planned. Common limits include
1. Hole Size. Hole size in the range of 7 7/8 – 8 1/2 in. is commonly agreed to be the most efficient and cost-effective hole size to drill, considering numerous criteria, including hole cleaning, rock volume drilled, downhole tool life, bit life, cuttings handling, and drill string handling. Actual hole sizes drilled are typically determined by the size of production tubing required, the required number of casing points, contingency strings, and standard casing decision trees. Company standardization programs for casing, tubing, and bits may limit available choices.
2. Bit Life. Measures of bit life vary depending on bit type and application. Roller cones in soft to medium-soft rock often use KREVs (i.e., total revolutions, stated in thousands of revolutions). This measure fails to consider the effect ofWOBon bearing wear, but soft formations typically use medium to high rpm and low WOB; therefore, this measure has become most common. Roller cones in medium to hard rock often use a multiplication of WOB and total revolutions, referred to as the WR or WN number, depending on bit vender. Roller cone bits smaller than 7 7/8 in. suffer significant reduction in bearing life, tooth life, tooth size, and ROP. PDC bits, impregnated bits, natural diamond bits, and TSP bits typically measure in terms if bit hours and KREVs. Life of all bits is severely reduced by vibration. Erosion can wear bit teeth or the bit face that holds the cutters, effectively reducing bit life.
3. Hole Cleaning. Annular velocity (AV) rules of thumb have been used to suggest hole-cleaning capacity, but each of several factors, including mud properties, rock properties, hole angle, and drill string rotation, must be considered. Directional drilling with steerable systems require “sliding” (not rotating) the drill string during the orienting stage; hole cleaning can suffer drastically at hole angles greater than 50. Hole cleaning in large-diameter holes, even if vertical, is difficult merely because of the fast drilling formations and commonly low AV.
4. Rock Properties. It is fundamental to understand formation type, hardness, and characteristics as they relate to drilling and production. From a drilling perspective, breaking down and transporting rock (i.e., hole cleaning) is required. Drilling mechanics must be matched to the rock mechanics. Bit companies can be supplied with electric logs and associated data so that drill bit types and operating parameters can be recommended that will match the rock mechanics. Facilitating maximum production capacity is given a higher priority through the production zones. This means drilling gage holes,minimizing formation damage (e.g., clean mud, less exposure time), and facilitating effective cement jobs.
5. Weight on Bit. WOB must be sufficient to overcome the rock strength, but excessive WOB reduces life through increased bit cutting structure and bearing wear rate (for roller cone bits). WOB can be expressed in terms of weight per inch of bit diameter. The actual range used depends on the “family” of bit selected and, to some extent, the rpm used. Families are defined as natural diamond, PDC, TSP (thermally stable polycrystalline), impregnated, mill tooth, and insert.
6. Revolutions per Minute (rpm). Certain ranges of rpm have proved to be prudent for bits, tools, drill strings, and the borehole. Faster rpm normally increases ROP, but life of the product or downhole assembly may be severely reduced if rpm is arbitrarily increased too high. A too-low rpm can yield slower than effective ROP and may provide insufficient hole cleaning and hole pack off, especially in high-angle wells.
7. Equivalent Circulating Density (ECD). ECDs become critical when drilling in a soft formation environment where the fracture gradient is not much larger than the pore pressure. Controlling ROP, reducing pumping flow rate, drill pipe OD, and connection OD may all be considered or needed to safely drill the interval.
8. Hydraulic System. The rig equipment (e.g., pumps, liners, engines or motors, drill string, BHA) may be a given. In this case, optimizing the drilling plan based on its available capabilities will be required.
However, if you can demonstrate or predict an improved outcome that would justify any incremental costs, then you will have accomplished additional optimization. The pumps cannot provide their rated horsepower
if the engines providing power to the pumps possess inadequate mechanical horsepower. Engines must be down rated for efficiency.
Changing pump liners is a simple cost-effective way to optimize the hydraulic system. Optimization involves several products and services and the personnel representatives.This increases the difficulty to achieve an optimized parameter selection that is best as a system.

New Technologies

Positive step changes reflected in the learning curve are often the result of effective implementation of new technologies:
1. Underbalanced Drilling. UBD is implemented predominantly to maximize the production capacity variable of the well’s optimization by minimizing formation damage during the drilling process. Operationally, the pressure of the borehole fluid column is reduced to less than the pressure in the ZOI. ROP is also substantially increased. Often,
coiled tubing is used to reduce the tripping and connection time and mitigate safety issues of “snubbing” joints of pipe.
2. Surface Stack Blowout Preventer (BOP). The use of a surface stack BOP configurations in floating drilling is performed by suspending the BOP stack above the waterline and using high-pressure risers (typically 13 3/8 in. casing) as a conduit to the sea floor. This method, generally used in benign and moderate environments, has saved considerable time and money in water depths to 6,000 ft.
3. Expandable Drilling Liners. EDLs can be used for several situations. The casing plan may startwith a smaller diameter than usual, while finishing in the production zone as a large, or larger, final casing diameter. Future advances may allow setting numerous casing strings in succession, all of the exact same internal diameter. The potential as a step change technology for optimizing drilling costs and mitigating risks is phenomenal.
4. Rig Instrumentation. The efficient and effective application of weight to the bit and the control of downhole vibration play a key role in drilling efficiency. Excessive WOB applied can cause axial vibration, causing destructive torsional vibrations. Casing handling systems and top drives are effective tools.
5. Real-Time Drilling Parameter Optimization. Downhole and surface vibration detection equipment allows for immediatemitigation. Knowing actual downhole WOB can provide the necessary information to perform improved drill-off tests .
6. Bit Selection Processes. Most bit venders are able to use the electric log data (Sonic,GammaRay, Resistivity as aminimum)and associated offset information to improve the selection of bit cutting structures. Formation
type, hardness, and characteristics are evaluated and matched to the application needs as an optimization process.

OilWell Drilling Books Page.4


the biggest collection of oil well drilling books such as Drilling bits, Managed Pressure drilling known as MDP, wireline, casing and well testing, all you have to do is to press on Download to get any book.

  Basics in Drilling in Oil and Gas Fields

  Drilling and Completion Note  75 MB

   Drilling Reference Series

  Choke Performance

  WireLine Logging

Wireline Log

 Casing and Liners for Drilling and Completion

Standard Slickline Tools

 Drilling Equipment

 How the well is Drilled on Land?  PowerPoint

  Advanced Drilling System

  Drilling Process

  Well Intervention Pressure Control IWCF   76 MB

  Casing Design & Hand Calculation Example


Drilling Bits Books

  Drilling Bit – Rotary Drilling Series IADC

   Rotary Drilling Bits

   Drilling Bits   5.3 MB

   Drilling Bits    7.6 MB

    Casing Drilling

  Casing Drilling Technology

Managed Pressure Drilling MPD

  Managed Pressure Drilling 67 MB

 what is Managed Pressure Drilling

  Managed Pressure Drilling – Drill the Un-Drillable

  Managed Pressure Drilling Techniques and Options

  Managed Pressure Drilling (MPD) Systems & Applications

  Managed Pressure Drilling from Weatherford

  Managed Pressure Drilling – Systems & Applications

  Managed Pressure Drilling from SPE

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Well Testing Books

Well Testing 82 MB

Well Testing rar

Well Testing pdf

Well Testing and Well Performance 271 MB

Well Testing – John Lee

Well Testing Analysis

Well testing Note

Well Testing Equipment

Well Testing Courses  94 MB

Well Testing zip

Oil Well Testing – Chaudri    19 MB

Gas Well Testing – Chaudri   25 MB

Oil Well Testing Handbook

   Gas Well Testing


Introduction to Well Testing

Well Testing Interpretation Methods

Introduction to Well testing from Schlumberger

  Formulas and Calculations for Drilling Production and Workover

  Completion Hydraulics Handbook from Schlumburger

    Beam Pumping Operations from SPE

Under balance Drilling PowerPoint

    Managing Drilling Operations – Ken Fraser  42 MB

    Drilling Rig Components Illustrated Glossary

   Advanced Oil Well Drilling Engineering

  Pressure Control During Oil Well Drilling

  Drilling Engineering Workbook

   Drilling, a source book on oil and gas well drilling from exploration to completion

  Managing Drilling Operations

  the Drilling Manual   101 MB

     Permanent Well Abandonment
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  Well Test Analysis – the Use of Advanced Interpretation Models
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   Introduction to Oil and Gas Well Drilling and Operations
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    Defining Directional Drilling
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Subsurface Safety Equipment from Halliburton
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Surface Safety Valve
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Applied Drilling Calculation
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Rotary Drilling Series   206 MB

Rotary Drilling Series Questions and Answers

Natural Gas Industry

Natural Gas Terminology:

Reservoir: Porous & permeable underground formation containing an individual bank of H.C.s confined by impermeable rock or water barriers characterized by a single natural pressure system.

read also What is Natural Gas

Field: Area of one or more reservoirs related to same structural feature.

Pool: Contains one or more reservoirs in isolated structures.

Wells can be classified as gas wells, condensate wells, and oil wells.

Gas wells: Wells with producing gas-oil ration (GOR)>100,000 scf/stb.

Condensate wells: Producing GOR < 100,000 scf/stb but > 5,000 scf/stb.

Oil wells: Wells with producing GOR < 5,000 scf/stb

Because NG is petroleum in a gaseous state, it is always accompanied by oil that is liquid petroleum. There are 3 types of NG: nonassociated gas, associated gas & gas condensate.

Nonassociated gas: Gas from reservoirs with minimal oil.

Associated gas: Gas dissolved in oil under natural conditions in the oil reservoir.

Gas condensate: Gas with high content of liquid H.C. at reduced P & T.

Utilization of Natural Gas

–  Natural gas is one of the major fossil energy sources.

– Combustion of 1 scf of NG generates 700 → 1,600 Btu of heat, depending upon gas composition.

– NG provided close to 24% of U.S. energy sources over 2000-2002.

– NG is used as a source of energy in all sectors of the economy.

– Natural gas was once a by-product of crude oil production.

– Since its discovery in 1821 in U.S.A. in Fredonia, New York, NG has been used as fuel in areas immediately surrounding the gas fields.

– In the early years of NG industry, when gas accompanied crude oil, it had to find a market or be flared; in the absence of effective conservation practices, oil-well gas was often flared
in huge quantities.

Consequently, gas production at that time was often short-lived, and gas could be purchased as low as 1 or 2% per 1,000 ft3 in the field.

– Consumption of NG in all end-use classifications (residential , industrial, commercial & power generation) increased rapidly since World War II.

– This growth resulted from several factors, including:

– Development of new markets.

– Replacement of coal as fuel for providing space & industrial process heat.

– Use of NG in making petrochemicals and fertilizers.

– Strong demand for low-sulfur fuels.

– The rapidly growing energy demands of Western Europe, Japan & U.S.A. couldn’t be satisfied without importing gas from far fields.

– Natural gas, liquefied by a refrigeration cycle, can now be transported efficiently and rapidly across the oceans by insulated tankers.

– The use of refrigeration to liquefy NG, and hence reduce its volume to the point where it becomes economically attractive to transport across oceans by tanker.

– It was first attempted on a small scale in Hungary in 1934 and later used in U.S.A. for moving gas in liquid form Louisiana up the Mississippi River to Chicago in 1951.

– The first use of a similar process on a large scale outside U.S.A. was the liquefaction by a refrigerative cycle of some of the gas from the Hassi R’Mel gas field in Algeria and the export
from 1964 onward of the resultant liquefied natural gas (LNG) by specially designed insulated tankers to Britain & France.

– NG is in this way reduced to about 1/600 of its original volume and the non-methane components are largely eliminated.

– At the receiving terminals, LNG is re-gasified to a gaseous state, whence it can be fed as required into the normal gas distribution grid of the importing country.

– Alternatively, it can be stored for future use in insulated tanks or subsurface storages.

– Apart from its obvious applications as a storable & transportable form of NG, LNG has many applications in its own right, particularly as a nonpolluting fuel for aircraft and ground

– Current production from conventional sources is not sufficient to satisfy all demands for NG.

Natural Gas Reserves

– 2 terms are frequently used to express NG reserves: proved reserves & potential resources.

– Proved reserves: Quantities of gas that have been found by the drill. They can be proved by known reservoir characteristics such as: production data, pressure relationships  and
other data, so that volumes of gas can be determined with reasonable accuracy.

– Potential resources: Quantities of NG that are believed to exist in various rocks of the Earth’s crust but haven’t yet been found by the drill. They are future supplies beyond the
proved reserves.

– There has been a huge disparity between “proven” reserves and potential reserves.

– Different methodologies have been used in arriving at estimates of the future potential of NG.

– Some estimates were based on growth curves, extrapolations of past production, exploratory footage drilled & discovery rates.

– Empirical models of gas discoveries and production have also been developed and converted to mathematical models.

– Future gas supplies as a ratio of the amount of oil to be discovered is a method that has been used also.

– Another approach is a volumetric appraisal of the potential undrilled areas. Different limiting assumptions have been made, such as drilling depths, water depths in offshore areas,
economics & technological factors.

– Even in the case of the highly mature and exploited U.S.A., depending upon information sources, the potential remaining gas reserve estimates vary from 650 Tcf to 5,000 Tcf.

– Proved NG reserves in 2000 were about 1,050 Tcf in U.S.A. & 170 Tcf in Canada.

– On the global scale, it is more difficult to give a good estimate of NG reserves.

– Unlike oil reserves that are mostly (80%) found in Organization of Petroleum Exporting Countries (OPEC), major NG reserves are found in the former Soviet Union, Middle East, Asia
Pacific, Africa, North America, Southern & Central America, and Europe.

Types of Natural Gas Resources

– NG classified as: conventional NG, gas in tight sands, gas in tight shales, coal-bed methane, gas in geopressured reservoirs & gas in gas hydrates.

  1. Conventional NG: Either associated or non-associated gas.

Associated or dissolved gas is found with crude oil. Dissolved gas is that portion of the gas dissolved in the crude oil and associated gas (sometimes called gas-cap gas) is free gas in
contact with the crude oil.  All crude oil reservoirs contain dissolved gas and may or may not contain associated gas.

– Non-associated gas is found in a reservoir that contains a minimal quantity of crude oil.

– Some gases are called gas condensates or simply condensates. Although they occur as gases in underground reservoirs, they have a high content of H.C. liquids so they yield
considerable quantities of them on production.

  1. Gases in tight sands: Found in many areas that contain formations generally having porosities of 0.001 to 1 millidarcy (md).

– At higher gas permeabilities, the formations are generally amenable to conventional fracturing and completion methods.

  1. Gases in tight shales: The shale is generally fissile, finely laminated, and varicolored but predominantly black, brown, or greenish-gray.

– Core analysis has determined that the shale itself has up to 12% porosity, however, permeability values are commonly < 1 md.

– It is thought, therefore, that the majority of production is controlled by naturally occurring fractures and is further influenced by bedding planes and jointing.

– Coal-bed methane: methane gas in minable coal beds with depths < 3,000 ft.

– Although the estimated size of the resource base seems significant, the recovery of this type of gas may be limited owing to practical constraints.

– Geopressured reservoirs: In a rapidly subsiding basin area, clays often seal underlying formations and trap their contained fluids. After further subsidence, P & T of the trapped fluids
exceed those normally anticipated at reservoir depth.

– These reservoirs have been found in many parts of the world during the search for oil & gas.

– Gas hydrates: Snow-like solids in which each water molecule forms hydrogen bonds with the four nearest water molecules to build a crystalline lattice structure that traps gas
molecules in its cavities.

– Contains about 170 times NG by volume under standard conditions.

– Because it’s a highly concentrated form of NG and extensive deposits of naturally occurring gas hydrates have been found in various regions of the world, they are considered as a
future, unconventional resource of NG.

read also What is LPG?

Future of the Natural Gas Industry

– The 19th century was a century of coal that supported the initiation of industrial revolution in Europe.

– The 20th century was the century of oil that was the primary energy source to support the growth of global economy.

– Simmons (2000) concluded that energy disruptions should be a “genuine concern“. He suggests that it will likely cause chronic energy shortage as early as 2010.  It will eventually
evolve into a serious energy crunch.

– The way to avoid such a crunch is to expand energy supply and move from oil to NG and eventually to H2.

– NG is the fuel that is superior to other energy sources not only in economic attractiveness but also in environmental concerns.

– At the end of the last century, natural gas took over the position of coal as the number 2 energy source behind oil.

– In 2000, total world energy consumption was slightly below 400 × 1015 Btu. Oil accounted for 39%, while NG & coal provided 23 % & 22 %, respectively of this.

– It is expected that the transition from oil to NG must be made in the early 21 century.  This isn’t only motivated by environmental considerations but also by technological innovations
and refinements.

1. Natural Gas Engineering Handbook, Dr. Boyun Guo and Dr. AIi Ghalambor
2. Natural Gas, by Primož Potočnik.
3. Fundamentals of Natural Gas, Arthur J. Kidnay & William R. Parrish

Well Pressure Control

Basically all formations penetrated during drilling are porous and permeable to some degree.
Fluids contained in pore spaces are under pressure that is overbalanced by the drilling fluid pressure in the well bore.
The borehole pressure is equal to the hydrostatic pressure plus the friction pressure loss in the annulus. If for some reason the borehole pressure falls below the formation fluid pressure, the formation fluids can enter the well. Such an event is known as a kick. This name is associated with a rather sudden flowrate increase observed at the surface.

A formation gas or fluid kick can be efficiently and safely controlled if the proper equipment is installed at the surface. One of several possible arrangement of pressure control equipment . The blowout preventer (BOP) stack consists of a spherical preventer (i.e.,Hydril) and ram type BOPs with blind rams in one and pipe rams in another with
a drilling spool placed in the stack.
A spherical preventer contains a packing element that seals the space around the outside of the drill pipe. This preventer is not designed to shut off the well when the drill pipe is out of the hole. The spherical preventer allows stripping operations and some limited pipe rotation.

Hydril Corporation, Shaffer, and other manufactures provide several models with differing packing element designs for specific types of service. The ram type preventer uses two concentric halves to close and seal around the pipe, called pipe rams or blind rams, which seal against the opposing half when there is no pipe in the hole. Some pipe rams will only seal on a single size pipe; 5 in. pipe rams only seal around 5 in. drill pipe. There are also variable bore rams, which cover a specific size range such as 312 in. to 5 in. that seal on any size pipe in their range.
Care must be taken before closing the blind rams. If pipe is in the hole and the blind rams are closed, the pipe may be damaged or cut. A special type of blind rams that will sever the pipe are called shear blind rams.
These rams will seal against themselves when there is no pipe in the hole, or, in the case of pipe in the hole, the rams will first shear the pipe and then
continue to close until they seal the well. A drilling spool is the element of the BOP stack to which choke and kill lines are attached. The pressure rating of the drilling spool and its side outlets should be consistent with BOP stack. The kill line allows pumping mud into the annulus of the well in the case that is required. The choke
line side is connected to a manifold to enable circulation of drilling and formation fluids out of the hole in a controlled manner.
A degasser is installed on the mud return line to remove any small amounts of entrained gas in the returning drilling fluids. Samples of gas
are analyzed using the gas chromatograph.
If for some reason the well cannot be shut in, and thus prevents implementation of regular kick killing procedure, a diverter type stack is used rather, the BOP stack described above. The diverter stack is furnished with a blow-down line to allow the well to vent wellbore gas or fluids a safe distance away from the rig.

While drilling, there are certain warning signals that, if properly analyzed, can lead to early detection of gas or formation fluid entry into the wellbore.
1. Drilling break. A relatively sudden increase in the drilling rate is called a drilling break. The drilling break may occur due to a decrease in the difference between borehole pressure and formation pressure. When a drilling break is observed, the pumps should be stopped and the well watched for flow at the mud line. If the well does not flow, it probably means that the overbalance is not lost or simply that a softer formation has be encountered.
2. Decrease in pump pressure. When less dense formation fluid enters the borehole, the hydrostatic head in the annulus is decreased. Although reduction in pump pressure may be caused by several other factors, drilling personnel should consider a formation fluid influx into the wellbore as one possible cause. The pumps should be stopped and the return flow mud line watched carefully.
3. Increase in pit level. This is a definite signal of formation fluid invasion into the wellbore. The well must be shut in as soon as possible.
4. Gas-cut mud. When drilling through gas-bearing formations, small quantities of gas occur in the cuttings. As these cuttings are circulated up, the annulus, the gas expands. The resulting reduction in mud weight is observed at surface.
Stopping the pumps and observing the mud return line help determine whether the overbalance is lost.
If the kick is gained while tripping, the only warning signal we have is an increase in fluid volume at the surface (pit gain). Once it is determined that the pressure overbalance is lost, the well must be closed as quickly as possible. The sequence of operations in closing a well is as follows:
1. Shut off the mud pumps.
2. Raise the Kelly above the BOP stack.
3. Open the choke line
4. Close the spherical preventer.
5. Close the choke slowly.
6. Record the pit level increase.
7. Record the stabilized pressure on the drill pipe (Stand Pipe) and annulus pressure gauges.
8. Notify the company personnel.
9. Prepare the kill procedure.
If the well kicks while tripping, the sequence of necessary steps can be given below:

  1. Close the safety valve (Kelly cock) on the drill pipe.
    2. Pick up and install the Kelly or top drive.
    3. Open the safety valve (Kelly cock).
    4. Open the choke line.
    5. Close the annular (spherical) preventer.
    6. Record the pit gain along with the shut in drill pipe pressure (SIDPP) and shut in casing pressure (SICP).
    7. Notify the company personnel.
    8. Prepare the kill procedure.
    Depending on the type of drilling rig and company policy, this sequence of operations may be changed.

A formation fluid influx (a kick) may result from one of the following
• abnormally high formation pressure is encountered
• lost circulation mud weight too low
• swabbing in during tripping operations
• not filling up the hole while pulling out the drill string
• recirculating gas or oil cut mud.
If a kick is not controlled properly, a blowout will occur.
A blowout may develop for one or more of the following causes:
• lack of analysis of data obtained from offset wells
• lack or misunderstanding of data during drilling
• malfunction or even lack of adequate well control equipment

1. Drilling Equipment and Operation.
2. drilling Operation.