Introduction To Petroleum Engineering

Gubkin State University of Oil and Gas

Basics of oil and gas

Fabrizio La Vita Drilling Department [email protected]

Moscow 12/15

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Oil & Gas Industry Characteristics • Large investment, can reach billion of US$. • High risk in all aspects (people safety, environment, investment, reputation). • High reward/return. • Long term business from initial investment until revenue generated, even longer until break even point (can be more than 20 years). • Complex operation, involves multi discipline experts from both technical and non-technical. • Strategic value (economic & politic). • Global impact.

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Oil & Gas Industry Sectors Upstream Midstream

Finding, lifting, and processing oil & gas from subsurface into surface and ready for transportation. Also known as exploration and Production (E&P).

Transportation and storage of crude oil and natural gas from E&P plant for further processing by pipeline, railway, road, or tanker.

Downstream

Further processing of crude oil and natural gas into useful final product or raw material for other industry. Also known as Refining & Marketing (R&M)

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Upstream Oil & Gas Life Cycle LICENSING • Activities to offer the right to manage an area (block) which is expected to contain oil & gas

EXPLORATION • Activities to search for oil & gas deposits on the reservoir beneath the earth surface within block’s boundary

APPRAISAL • Activities to define the oil & gas volume and characteristic more precisely after discovery

DEVELOPMENT • Activities to build the subsurface & surface facilities to produce oil & gas safely & efficiently

PRODUCTION • Activities to extract, process, and export oil & gas as per contract agreement

ABANDONMENT • Activities to plug wells permanently, remove surface facilities, and restore the block as per initial state

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Licensing Round • Government has the area (including oil & gas beneath the surface) but no resource (money, man power, technology), while Oil Company have the resource, but not the area. • Government, via host authority (government regulatory body or national oil company) will offer certain area known as “block” to oil companies in an activity called “Licensing Round.”

• Government will offer raw data & petroleum agreement to attract oil companies to invest for exploration & production (E&P) activities. • Oil companies will compete each other in a bidding / tender stage to obtain the right for E&P in a certain block. The winner will be granted the right (contract) to manage E&P activities in a certain period and get compensation based on the agreement. • In this stage, government need to attract investment by offering “interesting package” while keep protecting the national interest. 5

Exploration & Appraisal EXPLORATION

APPRAISAL

• Activities to find oil & gas prospect • It is required to determine the beneath the earth surface by means reservoir size which define the volume & of gravity survey, magnetic survey, to get better characteristic of oil & gas. and seismic reflection survey. • Volume will be measured in million • Once prospect is likely to be found, barrels (MMbbls) oil and billion cubic exploration (wildcat) drilling will be feet (Bcf) gas, both original in place conducted to determine the presence volume (Oil Initial In Place / OIIP and Gas of oil & gas reserve. Initial In Place / GIIP) & recoverable volume. • Most wildcat drilling fail to find oil & gas (dry hole), only few (less than • Important characteristic includes 25%) hits oil & gas layer (discovery). pressure, temperature, oil viscosity, hydrocarbon composition, • After discovery, more drilling is compartmentalization, and required to “appraise” the reservoir. contaminants. 6

Reserve Type Once appraisal conducted, it will determine the quantity of petroleum which can be recovered / produced. Typically, only 30% of oil and 70% of gas can be recovered, can be more if advance technique applied like water injection & submersible pump. • Proved (1P) : Quantities of oil and gas, which, by analysis of geoscience and engineering data,

can be estimated with reasonable certainty to be economically producible–from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. At least 90% probability (P90) that the quantities actually recovered will be equal or exceed the estimate. • Unproved : Reserves are based on technical data similar to that used in estimates of proved reserves; but technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved. Unproved reserves may be further classified as probable reserves and possible reserves. – Possible (2P) : Unproved reserves which analysis of technical data suggests are more likely than not to be recoverable. At least a 50% probability (P50) that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves. – Probable (3P) : Unproved reserve which analysis of technical data suggests are less likely to be recoverable than probable reserves. At least a 10% probability (P10) that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable plus possible reserves. 7

Field Development Plan (FDP) Once the estimated recoverable value is determined, the Company will prepare a plan to monetize the reserve, called Field Development Plan / Plan of Development (PoD). • FDP shall contain at least : Subsurface characteristic (OIIP, GIIP, contaminants, etc) Recoverable reserve in P90-P50-P10 Production Rate & Field Life Production Facilities (number & type of wells, surface facilities type) Project Plan (including Cost, Schedule, Quality) Project Economics Other aspects like Risk, Health Safety Environment (HSE) • FDP shall be approved by the host authority. Once approved, the Company will conduct a tender for facilities development.

• In the same time, Company will secure the hydrocarbon sales, especially gas, known as Gas Sales Agreement (GSA). While for oil, it will be absorbed by the market as per oil price trend. • Once the GSA secured and cost of development known from proposed tender price, the Company will further calculate the project economic. If it meet the criteria, the Company will sanction (commit to invest money) the project, known as Final Investment Decision 8 (FID)

Production Period Production rate

Plateau phase Tertiary recovery

Primary recovery Secondary recovery Time

• Typical production phase start with ramp up period (increase production rate up to peak, normally less than a year), then plateau (maintain peak for several years, for oil production normally less than 5 years while for gas production between 5 to 10 years), then declining until reach economic limit (timing when operating cost is higher than production revenue) or end of contractual period. • Plateau & decline phase can be extended by applying secondary recovery (i.e. gas injection & water injection) and tertiary recovery (i.e. chemical injection & steam injection), however cost to benefit ratio must be carefully calculated since secondary/tertiary recovery is more expensive than primary recovery. 9

Abandonment • The last phase in upstream life cycle is abandonment.

• The activities comprises well plug & abandonment (P&A) and surface facilities removal. • Well must be permanently closed and ealed, so no more hydrocarbon can escape to the surface. • Surface facilities must be removed until few meter below seabed, or left on the seabed as an artificial reef after free hydrocarbon condition reached. • Site must be restore to as close as its original condition. 10

Composition and physical properties of hydrocarbons Petroleum is a naturally occurring liquid, gaseous or solid mix, composed principally of hydrocarbons, that accumulates in underground reservoirs.

Natural Gas

Bitumen Black Oil

From point of view of the chemistry

• Hydrocarbon: any organic compound – gaseous, liquid or solid – consisting solely of carbon (C) and hydrogen (H)

In petroleum industry practice

• Both hydrocarbon and petroleum are used to indicate a mixture of natural hydrocarbons, usually with other minor components. Petroleum occurs in the subsurface as gas (dry and wet gas), liquid (crude oil, condensate), or semisolid, or mutual solutions of these 11

Composition and physical properties of hydrocarbons

Physical properties of a petroleum fluid are determined by its composition, and they vary as function of Temperature and Pressure. The temperature and pressure change relative to the reservoir conditions, during production where the pressure is lowered to fulfil transport, and storage condition T > 200° C

P = 150MPa

Changing in pressure lead to a change in the state of the mixture from a single phase state to a two-phase state.

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Origin, migration and accumulation of petroleum

HOW DOES PETROLEUM ORIGINATE?

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Origin, migration and accumulation of petroleum As a general rule, the origin of petroleum is never in the reservoir accumulation from which it is produced. Instead, petroleum have experienced a long series of processes prior to accumulation in the reservoir.

Oil and gas are generated by the thermal degradation of kerogen in the source beds (Kerogen is the organic matter that occurs into the source rocks, insoluble in organic solvents). With increasing burial, the temperature in these rocks rises and, above a certain threshold temperature, the chemically labile portion of the kerogen begins to transform into petroleum compounds.

Petroleum accumulation forms in sedimentary basins and can be discovered by exploration.

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Origin, migration and accumulation of petroleum

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Origin, migration and accumulation of petroleum

ELEMENT • Source Rock • Reservoir Rock • Migration Path • Seal • Trap PROCESSES 1. Petroelum Generation 2. Petroelum Migration – Primary 3. Petroelum Migration – Secondary 4. Petroelum Accumulation in trap and its preservation 5. Seepage of petroleum at Eart’s surface as consqeunce of fracturing of cap rock 16

Origin, migration and accumulation of petroleum

1. Occurrence of source rocks which generate petroleum under proper subsurface temperature conditions 2. Sediment compaction leading to expulsion of petroleum from the source into reservoir ( primary migration) 3. Occurrence of reservoir rocks of sufficient porosity and permeability allowing flow the petroleum through the pore system (secondary migration) 4. Structural configurations of sedimentary strata whereby the reservoir rocks form traps, in order to contain the accumulation of petroleum under the subsurface. 17

Origin, migration and accumulation of petroleum

5. Traps are sealed above by an impermeable sediment layer defined cap rock, in order to keep petroleum accumulation in place 6. Correct timing respect to the process of generation, migration and trap formation has occurred during the history of a sedimentary basin 7. Favorable conditions for the preservation of petroleum accumulation during an extended period of geological time without any destructive phenomena like: fracturing of cap rock, dissipation of accumulation, cracking of oil into gas

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Origin, migration and accumulation of petroleum ESSENTIAL ELEMENTS AND PROCESSES ELEMENT • Source Rock • Reservoir Rock • Migration Path • Seal • Trap PROCESSES 1. Petroelum Generation 2. Petroelum Migration – Primary 3. Petroelum Migration – Secondary 4. Petroelum Accumulation in trap and its preservation 5. Seepage of petroleum at Eart’s surface as consqeunce of fracturing of cap rock

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Origin, migration and accumulation of petroleum Source rock: a sedimentary rock with a sufficient amount of suitable organic matter to generate and expel commercial quantities of hydrocarbons. SILICLASTIC ROCKS (clay-rich) Mudstones, Shales

A petroleum source rock is characterized by:  sufficient content of finely dispersed organic matter of biological origin;  this organic matter must be of a specific composition, i.e. hydrogen-rich; The source rock must be buried at certain depths and subjected to proper subsurface temperatures in order to initiate the process of petroleum generation by the thermal degradation of kerogen. 20

Sedimentary rocks  Mud Rocks: Mudstone (also called mud rock) is a fine grained sedimentary rock whose original constituents were clays or muds. With increased pressure over time the platy clay minerals may become aligned, with the appearance of facility or parallel layering. This finely bedded material that splits readily into thin layers is called shale, as distinct from mudstone. Mud rocks, such as mudstone and shale comprise some 70% of all sedimentary rocks. • • • • •

Clay & Clay Stone Mud & Mudstone Argillite Slat Shale (formed from clay that is compacted together by pressure) • Loess • Organic Rich Mud rock • Siltstone

Clay stone

Shale

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Origin, migration and accumulation of petroleum Reservoir rock: a rock in which oil and gas accumulates; a rock having sufficient porosity and permeability to store and transmit petroleum fluids. CLASTIC ROCKS

Sandstone

CARBONATE ROCKS

Limestone, Dolomite

Most hydrocarbons accumulate in clastic rocks which also contain most of the reserves in the largest known reservoirs. Reservoirs are located mostly in sands that have undergone varying degrees of cementation; cemented sands are called sandstone. Carbonate rocks too, can contain large hydrocarbon reservoirs, especially those that have undergone dolomitization, which determines a notable increase in porosity and permeability. The sedimentation environments of rocks of chemical origin are mainly marine and the result of evaporation. 22

Sedimentary rocks Types of Sediments: 1. Terrigenous clastic sediments 2. Carbonate Rocks 3. Evaporites

4. Ironstones 5. Phosphate deposits 6. Siliceous sediments 7. Volcanic Rocks

1‐Terrigenous Clastic Sediments  Sandstones: Sandstone (sometimes known as Arenite) is a sedimentary rock composed mainly of sand‐sized minerals or rock grains. Most sandstone is composed of quartz and/or feldspar because these are the most common minerals in the Earth's crust. • Black Sandstone: if Sand contain Tin Oxide • Argillaceous S.S.: if Sand contain Clay • Calcareous S.S.: if Sand contain CaCO3 Grain Supported Sandstones: (Arenite)  Arenite  Arkosic Arenite  Lith Arenite Phyll Arenite  Calc Lithite

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Sedimentary rocks 2‐Carbonate Sediments  Limestone Limestone is a sedimentary rock composed largely of the mineral calcite. Like most other sedimentary rocks, limestones are comprised of grains. Other carbonate grains comprising limestones are oids, peloids, intraclasts, and extraclasts. Some limestones do not consist of grains at all and are formed completely by the chemical precipitation of calcite or aragonite.

Limestone

 Dolomite Composed of calcium magnesium carbonate CaMg(CO3)2 (known as magnesium L.S)

Dolomite 24

Origin, migration and accumulation of petroleum Seal (Cap) rock: a rock or a fault that prevent upward migration of hydrocarbons acting like a barrier. Their usual concave shape prevent lateral migration of hydrocarbons.

Clay, Evaporites rocks ( Anhydrite) and salt are an excellent cap rock

To be assumed as an effective cap rock, rock’s permeability must be less than 104 Darcys without interconnected pores. Cap rocks are more efficient if the hydrocarbon is in liquid state. For gas hydrocarbons, if the rock is slightly permeable with porous filled with water, the gas will gradually displace water and spread through the cap. 25

Sedimentary rocks 3 - Evaporites Evaporites are water‐soluble mineral sediments that result from the evaporation of water. Evaporites are considered sedimentary rocks.  Gypsum It is a major rock forming mineral that produces massive beds, usually from precipitation out of highly saline waters, composed of calcium sulfate dehydrate, with the chemical formula CaSO4∙2H2O  Anhydrite From aqueous solution calcium sulfate is deposited as crystals of gypsum, but when the solution contains an excess of sodium or potassium chloride anhydrite is deposited if temperature is above 40°C. Chemical formula: CaSO4  Halite It is commonly known as rock salt. Halite forms isometric crystals. The mineral is typically colorless or white It commonly occurs with other evaporite deposit minerals such as several of the sulfates,halides, and borates. Chemical formula: NaCl

Gypsum

Anhydrite 26

Origin, migration and accumulation of petroleum Hydrocarbons trap: A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate. Traps are divided into three types: structural, stratigraphic, and mixed Structural traps It is formed where the space of petroleum is limited by a structural feature

 Anticline traps: trap whose closure is controlled by the presence of an anticline.

 Fault trap: in which closure is controlled by the presence of at least one fault surface. 27

Origin, migration and accumulation of petroleum 

Salt domes traps: Salt domes traps are caused when plastic salt is forced upwards through layers

Stratigraphic traps: It is the trap created by the limits of reservoir rock itself, without any structural control. It is formed by changes in rock type or pinch-outs, unconformities, or sedimentary features such as reefs.

Pinch-out trap: The termination by thinning or tapering out ("pinching out") of a reservoir against a nonporous sealing rock creates a favorable geometry to trap hydrocarbons. 28

Unconformity trap: trap whose closure is controlled by the presence of an unconformity.

Reef trap: sedimentary rock, most commonly produced by organisms that secrete shells such as corals. Because the rocks that surround reefs can differ in composition and permeability, porous reefs can form stratigraphic traps for hydrocarbons.

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Physical parameters of a reservoir rock A reservoir is characterized by different physical parameters. Temperature, pressure, gas saturation, porosity and permeability characterize fluids characterization and their phase. The mentioned factors come into play in the development of a reservoir and interact with one another. For example a change in temperature or pressure can determine a change of phase. Temperature varies directly with depth. The geothermic gradient (on average, 1°C every 30 m of depth) is influenced by geographic location and other local factors such as the possible presence of volcanic activity or the flow of underground waters. Reference temperatures are often obtained during drilling or production, and they are largely influenced by those operations. In these conditions, the temperature of the sediment and of the fluid it contains are not in equilibrium, and the measured gradient is lower than the real one.

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Physical parameters of a reservoir rock

The minimum pressure of a reservoir is the hydrostatic one . That value is hardly ever reached in practice as a result of the presence of the lithostatic (or geostatic) load of the superposed sediments, which influences the bottom hole pressures and always produces higher gradient values, usually of about 1.5 atm

Gas saturation. The oil in the subsurface always contains a certain percentage of dissolved gas. If it is greater than the amount of gas soluble in oil at the existing temperature and pressure, the gravity force causes the gas to concentrate towards the summit (gas cap). If the percentage of dissolved gas is lower, the gas remains in solution until a decrease in pressure (production phase). The gas cap hydrocarbons facilitates the extraction of oil which rises towards the surface as a result of the push effect when the gas expands (gas drive).

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Physical parameters of a reservoir rock

Porosity (total porosity) is the percentage of pore volume or void space, or that volume within rock that can contain fluids Porosity is determined by the totality of empty spaces present in the reservoir rock(pores, but also by empty spaces, interstices or fractures, that intersect the rock.) Φ= Vpor/ Vtot

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Physical parameters of a reservoir rock

Effective porosity (or efficient) is represented by the volume of the pores in which the fluid is also effectively able to flow. Pumice, for example, which has a total porosity of more than 50%, has no effective porosity; the pores it contains are not interconnected and fluids are therefore unable to infiltrate and penetrate it.

Porosity can vary considerably inside a reservoir rock, both vertically and laterally, as a function of variations in the nature of the rock itself because, it is in influenced by the sedimentation environment in space (lateral variation) and over time (vertical variation). It is primary, when formed during the deposition of the sedimentary rock, or secondary, as result either of chemical processes, or physical processes 33

Physical parameters of a reservoir rock

Permeability is the property that allows fluids to pass through rock . It is a characteristic of the porous media and give the measure of the productive capacity of a reservoir due to the fluids flowing rock by filtration through pores (permeability by porosity) or by direct transmission through discontinuities. It is measured in Darcy. Darcy measures the fluid flows through the medium in laminar regime at the flow rate of 1 cm/s per cm2 under p = 1 atm per cm.

Absolute Permeability is the measure of the media permeability when it is present a fluid in the rock. It depend by the characteristics of the rock.

Effective Permeability is ability of the rock to transmit a particular fluid respect to another when they are both present in the porous media at the same time

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Physical parameters of a reservoir rock

Relative Permeability is the ratio between absolute permeability and effective permeability. It assumes values between 0 and 1. I t measure the capacity of a fluid to flow respect in the media, respect to an other

Knowing the permeability value during the evaluaton process of a reservoir allow to :  To evaluate the pressure variation into the reservoir  Define the mobile ratio λ= keff/μ  Variation of mobile ration affect the capacity of the fluids to move in vertial or horizontal direction inside the reservoir, facilitating the mobility of a fluid respect to another

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Water drive The reserovir is limited below or lateral by an aquifer which replace the volume of hydrocarbons during production by soustaining the pressure inside the reserovir. The oil recovery is 30 -60 % The production of hydrocarbons is considered secondary when it occurs due to the water flooding or gas injection for pressure maintenance A displacement process occurs when fluid in place is removed by another fluid (water or gas).

It can be natural or artificial through external injection of water or gas to enhance the recovery of oil.

RF= 40 -50 % 36

The term drilling indicates the whole complex of operations necessary to construct wells of circular section applying excavation techniques not requiring direct access by man.

Why drilling a well? • To gain information (e.g. Exploration & Appraisal wells) • To produce hydrocarbons or support their production through Injection of gas and liquids  Safety

Zero accidents in a harsh and hazardous environment

 Environment

Zero pollution

 Team-work

Multi-tasks, works with Service Companies

 Adaptation

Activities in different countries

 Decisions

Diagnostic following drilling hazards must be done immediately; High requirements for decision-making and work execution

 Context (economics)  Reservoirs

In continuous evolution; depends mainly on oil price. More and more complex and difficult to discover

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Development process EXPLORATION DELINEATION STUDIES

Geoscience – studies Technico economical

DEVELOPMENT

PRODUCTION

studies

Drilling Devel wells

Drilling Well test

Drilling activities including Wells maintenance/ WO Infill drilling

% of total cost

FIRST OIL (approx)

(approx) 2 to 4 years

50 to 65 % (approx) 2 years (approx) 1 to 3 years

including

Wells P&A decommissioning

Site restoration

Investment decision DISCOVERY

Drilling activities

END OF PRODUCTION? (approx)

35 to 50 % (approx) 10 to 15 years ??

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Onshore project 1400

Offshore project Drilling = 1324 MUSD 9380 MUSD 22%

Drilling = 1014 MUSD 30%

10000 9000

1200

Other costs

Other costs

8000

1000

7000 MUSD

MUSD

Drilling 800

O D 600 M

Package 4

Drilling

6000 5000

O D 4000 M

SSPS

SURF

3000

400

2000 200

Package 3 Package 2

0

Package 1&5

Initial budget

1000

FPSO

0 Initial budget

39 NO TO COPY -- N

Drilling phases EXPLORATION • WILDCAT: Prospect in an area where no hydrocarbons have been produced. Uncertainty(ies) still exist i.e.: source rock, migration path, traps…(well drilled on geological basin studies) • EXPLORATOR: Site selection is based on seismic data (well drilled on a “prospect”) drilling data in the prospective horizon are not known

APPRAISAL • APPRAISAL: Delineates the reservoir’s boundaries; wells drilled to evaluate a discovery and/or results of tests on exploratory well

DEVELOPMENT • PRODUCTION: To produce hydrocarbons • INJECTION: For hydrocarbon secondary recovery

MAINTANANCE • WORKOVER: for maintenance of the well integrity or the maintenance of “well performance”.

ABANDONMENT • When a well becomes uneconomic the wells team return to install downhole cement plugs to isolate hydrocarbon zones and the wellhead is removed.

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 Depth reference  Measure Depth (MD) is the distance measured along the course of the borehole from the surface reference point  TrueVertical Dept (TVD) is the vertical distance calculate from the surface reference point

 TVD and MD can be the same only in vertical well  In practice, TVD is always less than MD

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Directional drilling

Directional drilling is controlling technique of the direction and deviation of a wellbore to a predetermined underground target or location. The first controlled directionally drilled well was drilled in the Huntington Beach Field in 1930 to tap offshore reserves from land locations.

Directional drilling became more widely accepted after a relief well was drilled near Conroe, Texas in 1934.

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Directional drilling

Today, directional drilling is an integral part of the petroleum industry. It enables oil companies to produce reserves that would not be possible without directional drilling.

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Directional drilling

Directional wells are commonly drilled … For increasing well productivity (horizontal, multilateral wells) To gain access to remaining reserves from new wells or re-entries requiring Complex directional profiles  For a reduction of the number of wells

 for a reduction of the $ / bbl 45

Directional drilling

 Inclination Reference

Inclination (α) is the angle, measured in degrees, by which the wellbore or survey-instrument axis varies from a true vertical line. By oilfield convention, 0° is vertical and 90° is horizontal

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Directional drilling

 Directional Measurement Hole direction is the angle (φ), measured in degrees, of the horizontal component of the borehole or survey-instrument axis from a known north reference. This reference is true north, magnetic north, or grid north, and is measured clockwise by convention. Hole direction is measured in degrees and is expressed in either azimuth (0 to 360°) or quadrant (NE, SE,SW, NW) form

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Directional well profiles

Common terminology for a no vertical well profile

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Main applications

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Main applications

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Main applications

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Main applications

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Main applications

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Main applications

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Main applications

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Main applications

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Directional well profiles The using of steerable system in directional drilling allows to plan and drill wells with complex path, involving 3-D dimensional trajectory. This is particularly true in the case of re-drills, where old wells are sidetracked and drilled to new targets.

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Determining the Kick-off Point (KOP) The selection is made by considering the geometrical well-path and the geological characteristics. The most distant targets have the shallowest KOPs The optimum inclination of the well is a function of the maximum permissible build rate (and drop rate if applicable) and the location of the target. Avoid to kick-off in unconsolidated clays formations Determining Build and Drop Rates (DLS) They are the rates at which the well deviates from the vertical (N-S-W-E). •

The total depth of the well.

•

Maximum Torque and Drag limitations.

•

High dogleg severity in the build section o results in high torque and drag. Severe limiting factor in deeper wells.

•

The formations through which the build section must pass. Higher build rates are often not possible to achieve in soft formations Mechanical limitations of the drill string or casing.

•

Mechanical limitations of logging tools and production strings.

“Optimum build/drop rates (DLS) in conventional wells vary from place to place but are commonly in the range of 1.5° to 3° per 100 ft (30m).” Tangent angle of the well (or drift angle) It is the inclination (in degrees from the vertical) of the long straight section of the well after the build-up section of the well. The tangent angle will generally be between 10° and 60° since it is difficult to control the trajectory of the well at angles below 10° and it is difficult to run wire line tools into wells at angles greater than 60°.

Directional well profiles J-shape profile

Also called Deep Kick off wells Features: •

Deep KOP

•

Build-up section

•

Short tangent section (optional)

Applications: Disadvantages: • Appraisal wells to assess • Formations are harder so the the extent of a newly initial deflection may be more discovered reservoir difficult to achieve •

Repositioning of the • bottom part of the hole or re-drilling

•

Salt dome drilling •

Harder to achieve desired tool face orientation with downhole motor deflection assemblies (more reactive torque) Longer trip time for any BHA changes required 59

Directional well profiles S-shape profile Features:

There are several variations

- Shallow KOP

-

- Build-up section

-

- Tangent section

-

Build, hold &drop back vertical Build, hold, drop &hold*

Build, hold& continuous drop through reservoir

- Drop-off section Applications: • •

• • •

Disadvantages:

Multiple pay zones • Reduces final angle in reservoir • Lease or target • limitations Well spacing requirements Deep wells with small horizontal displacements

Increased torque & drag Risk of key seating Logging problems due to inclination

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Directional well profiles Extended reach well Features: • MD 2:1 TVD

• Shallow kick-off point (KOP) • Build-up section (which may have more than one build up rate) TVD

MD

• Tangent section Applications: • Deep wells with large horizontal displacements • Moderately deep wells with moderate horizontal displacement, where intermediate casing is not required 61

Directional well profiles Horizontal well 1. Reduced water and gas coning because of reduced drawdown in the reservoir for a given production rate, thereby reducing the remedial work required in the future. 2. Increased production rate because of the greater wellbore length exposed to the pay zone.

3. Reduced pressure drop around the wellbore. 4. Lower fluid velocities around the wellbore. 5. A general reduction in sand production from a combination of Items 3 and 4. 6. Larger and more efficient drainage pattern leading to increased overall reserves recovery. 62

Directional well profiles Horizontal well Horizontal wells are normally characterized by their buildup rates and are broadly classified into four groups that dictate the drilling and completion practices required

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CASING SETTING DEPTH GUIDANCE

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Casing  Supports the walls of the hole

 Prevents the migration of fluids from layers at high pressure to ones at low pressure  Eliminate circulation losses  Protects the hole against damages  Acts as an anchorage for the safety equipment

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Casing Conductor pipe

Surface casing

Intermediate casing

Production casing

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Casing Conductor pipe

• • • •

It is the first string of casing to be used. Depth from 10 ft to 300 ft. Size range from 16 to 36 inches Large enough to allow the other casing strings to be run through it.

Purposes of conductor pipe are to: • • • •

The conductor isolates unconsolidated formations and water sands Protects against shallow gas. It is usually the string onto which the casing head is installed. A diverter or a blowout prevention (BOP) stack may be installed onto this string. • When cemented, this string is typically cemented to the surface or to the mudline in offshore wells. 69

Casing Surface casing

• Number depends on the depth of the unconsolidated formations • Size range 20 inch - 13-3/8 inch • Different grades depend on the different well conditions (P &T) Purposes of surface casing are to: • Protect fresh water formations • Seal off unconsolidated formations and lost circulation zones • Provide a place to install the B.O.P. • Protect “build” sections on deviated wells 70

Casing Intermediate casing

• Normally from 2 to 3 and have always decreasing size • Sizes range 9 5/8 and 13 3/8 inch Purposes of surface casing are to: • Isolating the formations which can create potential hole problems (circulation losses, abnormal pressures, instability, etc.) • Permitting the installation of higher pressure rated safety equipment. 71

Casing Production casing

• Size of production casing depends on expected production rate, the higher production rate larger inside diameter • Size rate 3 - 7 inch

Purposes of surface casing are to: • Isolating producing formations • Providing for selective production in multi-zone production areas. 72

Casing Liner is a string of casing that does not reach the surface. They are usually “hung” (attached to the intermediate casing using an arrangement of packers and slips) from the base of the intermediate casing and reach to the bottom of the hole.

The major advantage of a liner: • Cost of the string is reduced • Running and cementing times reduced During the course of the well, if the liner has to be extended to the surface (making it another string of casing), the string attaching the liner to the surface is known as a “tie-back” string.

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Pressure in wellbore Hydrostatic pressure is defined as the pressure exerted by a column of fluid. The pressure is a function of the average fluid density and the vertical height or depth of the fluid column. PH = Units Coefficient x MW x TVD PH (in psi) = 0.052 x mud weight (ppg) x depth (ft) or,

PH (in kg/cm2) = 0.1 x mud weight (kg/l) x depth (m) A

Units … conversions: feet x 0.3048 --- >meter psi x 0.07 --- > kg/cm² ppg x 0.12 --- > kg / l kgf / cm² x 14.22 --- > psi kg / l x 8.345 --- > ppg

Hydrostatic pressures can easily be converted to equivalent mud weights and pressure gradients. Hydrostatic pressure gradient is given by: HG = HP x 10 / D [kg/cm2/10m]

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Pressure in wellbore As said, for an adequate characterization of a formation from a pressure regime standpoint, the following parameters have to be determined:  Overburden Pressure, Pov  Pore Pressure, Pp  Fracture Pressure, Pfr These pressures are strictly dependent one from the other. In fact, pore pressures and overburden pressures are related between them by the compaction process in accordance with the effective stress principle and together allow the calculation of fracture pressures. The overburden and pore pressures are linked together through the so called effective pressure. It represents how the forces, due to the weight of the sediments and acting on a certain area laying at a defined depth, are distributed between the solid and the liquid components of the considered rock. The effective pressure, σ or Pc, is, therefore, given by: σ (or Pc) = Pov - Pp

Pressure in wellbore

Overburden or geostatic or lithostatic pressure is the pressure exerted on a given formation by the weight of sediments having an average density equal to ρb, that extend from the surface to the considered depth, H:

Pov = (ρb · H) / 10 where: Pov = overburden pressure, kgF/cm2 H = depth, m ρb = average sediment density, g/cm3

Pressure in wellbore

Pore Pressure, also called Formation Pressure, Pp, is the pressure of the fluid contained in the pore spaces of the rocks.

In a sedimentary basin three categories of Pore Pressure can be encountered: 

Negative pressure anomaly (subnormal pressure or underpressure): Pp < Ph



Normal pressure: Pp = Ph



Positive pressure anomaly (abnormal pressure or overpressure): Pp > Ph

The timely and reliable detection and quantification of overpressures is fundamental for safe and cost-efficient drilling operations. A great deal of efforts have to be made to properly predict abnormally pressured formations.

77

Normal pore pressure is equal to the hydrostatic pressure of a column of formation fluid extending from the surface to the subsurface formation being considered. Normal pore pressure is not a constant. The magnitude of normal pore pressure varies with the concentration of dissolved salts, type of fluid, gases present and temperature gradient Abnormal pore pressure is defined as any pore pressure that is greater than the hydrostatic pressure of the formation water occupying the pore space. Abnormal pressure is sometimes called overpressure or geopressure. Abnormal pressure can be thought of as being made up of a normal hydrostatic component plus an extra amount of pressure. This excess pressure is the reason why surface control equipment (e.g. BOPs) are required when drilling oil and gas wells. Subnormal pore pressure is defined as any formation pressure that is less than the corresponding fluid hydrostatic pressure at a given depth. Subnormal pore pressures are encountered less frequently than abnormal pore pressures and are often developed long after the formation is deposited. Subnormal pressures may have natural causes related to the stratigraphic, tectonic and geochemical history of an area, or may have been caused artificially by the production of reservoir fluids. 78

Abnormal pore pressure is developed as a result of a combination of geological, geochemical, geophysical and mechanical process.

These causes may be summarized under:

 Depositional Effects  Diagenetic Processes  Tectonic Effects  Structural Causes  Thermodynamic Effects

79

Pressure in wellbore

80

Pressure in wellbore

Fracture Pressure is the pressure necessary to fracture a formation. This pressure is a function of the overburden pressure, the pore pressure and the mechanical properties of the rock matrix (expressed by the K coefficient). The general and empirical formula for fracture gradient is:

Pfr = Pp + K (Pov – Pp) where: - Pfr = fracture pressure, kg/cm2 - Pp = pore pressure, kg/cm2 - Pov = overburden pressure, kg/cm2 - K = matrix stress coefficient

Pressure in wellbore PREDICTING FORMATION PORE PRESSURES Formation pressures can be the major factors affecting drilling operations. Unfortunately, formation pressures can be very difficult to locate and/or to quantify precisely where abnormal pressures exist.

Proper detection and evaluation of formation pore pressures will help in more effective overall well planning, including:

 Safe and economical selection of casing points  Proper engineering of equipment to minimize potential hazards (e.g. : selection of BOP WP, avoiding pipe sticking), to minimise magnitude of well kicks

 Optimization of penetration rates under controlled drilling mud conditions, minimizing formation damages.

Casing design

Once the three pressure gradient curves depth have been obtained, it is possible to take following decisions:

1. Define the density of the mud versus depth; 2. The next step consists in determining the depths at which the various casing strings shall be run, that is the casing setting depths. This also implies the number of casing strings required to case the hole from surface to bottom; 3. Knowing the depths of setting and the pressures acting in the well, it is then possible to calculate the stresses at which the various casing strings will be subjected during drilling and production and calculate the mechanical properties the casings should have in order to withstand these stresses.

Mud density determination

4.

The mud weight (or density) should be slightly higher than the pore pressure gradient (usually 100 g/litre), when in static conditions (no mud circulation), and below the fracture gradient (plus a certain safety margin depending on the particular situation), when in dynamic conditions (with mud circulation).

5.

This means that in overpressure zones, the mud density must be increased with the depth as does the pore pressure gradient.

6.

For practical reasons, at the rig site the mud density is increased following step by step patterns, and not continuously.

85

Mud density determination 1.00 0 2.50 500 100 0 150 0 200 0 2500

1.50 MUD DENSITY (theoretical)

MUD DENSITY (actual)

3000 3500 4000 4500 5000

PORE PRESSURE GRADIENT

2.00 FRACTURE GRADIENT

Casing depth

The next step consists in the determination of the depths at which the various casing strings shall be run, taking into account safety margins, knowledge of the area, previous experiences, expected hole problems.

This sequence of calculations will also define the number of casing strings required to case the hole from surface down to bottom.

87

SELECTION CRITERIA AND PROCEDURE The procedure usually followed to determine the casing points is fairly simple and is based on a “bottom up” procedure, that is: 1.

Firstly, it is assumed that the final production casing will be set at bottomhole if the well is hydrocarbon bearing. This will be the production casing string. In case the well will not be productive, this string will not be run.

2.

To determine the immediately previous casing, a straight line is traced, which starts from the bottom of the well in correspondence of the maximum mud density predicted there. This straight line will intersect the fracture gradient curve at a certain depth, where both the fracture gradient and the mud density coincide. For safety reasons this depth is increased by some hundred meters (depending on the trend of the gradients), so that the density of the mud in hole will be lower than the fracture gradient of the open hole by a set amount. This is an intermediate casing string.

3.

The procedure continues in the same way and other intermediate casings can be required before reaching the surface. 88

4.

A first large diameter casing, the conductor pipe (42”, 30”), is usually set at around 30-50 m with the purpose to protect the shallower formations from caving or collapsing or for avoiding any eventual stability problem of the drilling rig. If this casing is driven, it is called the drive pipe.

5.

A second casing, the surface casing (30”, 26”, 20”), is also positioned at a depth between 100 and 500 m, with the scope to make possible the installation of the BOPs and excluding areas with low facture gradients.

6.

The number of casing strings required in a well varies between 4 and 7, depending on the depth, pressure gradients trend and targets to be reached.

89

Casing setting depth: a bottom up approach

DEPTH

Normal pressure

EQUIVALENT MUD WEIGHT

CONDUCTOR PIPE SURFACE CASING

d

Fracture gradient Fracture gradient less safety margin

Pore pressure gradient

c

INTERMEDIATE CASING

b

pore pressure + safety margin

a

PRODUCTION CASING

Target depth

Oil wells can be drilled onshore or offshore. Normally two basic design of rigs are used: the derrick (A) and the mast (B), both with a similar shape but with some constructive differences which makes the second type easier to install and transport and, therefore, more suitable for onshore operations than the first type, used generally offshore.

A. DERRICK

B. MAST

91

ROTARY TABLE

TRAVELLING BLOCK AND HOOK

DRILL BIT

TOP DRIVE 92

LIGHT RIGS

2000 m

650 HP MEDIUM RIGS

4000 m

1300 HP HEAVY RIGS

6000 m

2000 HP ULTRA-HEAVY RIGS

> 6000 m

3000 HP +

93

Main Components of a Rotary Drilling Rig

Draw works and Rotary Table

Drillers Control Room “Doghouse”

94

Hoisting system The hoisting system is a large pulley system which is used to lower and raise equipment in and out of the well. In particular, the hoisting system is used to raise and lower the drill string and casing in and out of the well. Normally, the structural part has two basic design : the derrick and the mast, both with a similar shape but with some constructive differences which makes the second type easier to install and transport and, therefore, more suitable for onshore operations than the first type, used generally offshore.

DERRICK

MAST

95

Rotation system The system of rotation is intended to cause the drill string to rotate, and it consists of the rotary table, the kelly and the swivel.

96

Rotation system In modern rigs there is often also a top drive which groups together the functions of the three items of equipment mentioned above. Using top drive is not longer necessary to have swivel and kelly, and in theory also without rotary table. ADVANTAGES Drilling by stands, allowing greater control of drilling

DISADVANTAGES Structural modifications to the drill rig

The reduction of the time More complex required to connect the More costs and more pipes  LESS ACCIDENTS maintenance

Performing the trip-out operation while circulating mud and rotating the string Intermediate connections are eliminated 97

The drill string

The drill string is an assemblage of hollow pipes of circular section, extending from the surface to the bottom of the hole.

THREE FUNCTIONS:  It takes the drilling bit to the bottom of the hole, while transmitting its rotation and its vertical load to it  It permits the circulation of the drilling fluid to the bottom of the hole  It guides and controls the trajectory of the hole 98

The drill string

The drill string is an assemblage of hollow pipes of circular section, extending from the surface to the bottom of the hole.

THREE FUNCTIONS:  It takes the drilling bit to the bottom of the hole, while transmitting its rotation and its vertical load to it  It permits the circulation of the drilling fluid to the bottom of the hole  It guides and controls the trajectory of the hole 99

The drill string typical …. •Size (OD 3 ½” and 5”) •Length (30 ft) •Weight (13.3 lbs/ft and 19.5 lbs/ft) •API shouldered connections typical …. •Weight (25.3 lbs/ft and 49.3 lbs/ft)

Drill Pipes Heavy Weight (intermediate stiffness pipes)

X-over Drill Collars

typical …. •Size (OD 4 ¾” to 9 1/2”) •Length (30 ft approx) Total weight / joint (1043 lbs to 6727 lbs)

Jar (Shock tool to be activated while drilling string stuck) Drill Collars Stabilizer (for hole reaming) Drill Collar Shock absorber (vibrations damper) Stabilizer

BHA (Bottom Hole Assembly

Drill Collar (Short Drill Collar) Near bit Drilling bit

100

The drill string HEAVY WEIGHT

JAR

Placed on the neutral point of the BHA (the changes from tension to compression), Possible to give upward bumps in case of stuck REAMER

Transition pipe. Provide a gradual transition from heavy drill collars to lightweight drill pipe , prevent stress concentration at the top of drill. Reducing torque and differential pressure sticking.

Special stabilizer with roller cutters. Reaming the wall of the hole, taking it to the nominal diameter of the bit, and eliminate small variations in diameter

STABILIZER

Placed in between the drill collars, to make the string more rigid controlling the borehole trajectory

SHOCK

ADSORBER

Placed above the bit to reduce the axial vibrations generated during drilling

101

Downhole motor/mud motor

    

Faster rate of penetration Reduced drilling times Reduced drill-string rotation speed Less wear and fatigue of drill-string connections Less drill-string torque

Most convenient application in steerable system ( directional drilling). Downhole motor allows the offset stabilization. It stabilizes the bit affected by changing in direction.

102

BITS TECHNOLOGY

07. DRILLING BITS TECHNOLOGY 103

BIT SELECTION The selection of the proper bits for a well is an important decision that has a big impact on costs. Many factors need to be considered and evaluated: • Method of drilling • Formation type and properties • Mud system • Rig cost • Bit cost Drilling bit performance is function of several operating parameters: a) Weight on bit (WOB) b) Rotations per minute (RPM) c) Mud properties d) Hydraulic efficiency

07. DRILLING BITS TECHNOLOGY 104

BIT DEFINITION Bits can be divided into two main categories:  Roller Cone Bits -Milled Tooth Bits -Insert Bits  Fixed Cutter Bits -Natural Diamond Bits - Synthetic Diamond Bits (PDC Bits, TSP Bits, Impregnated Bits) - Drag bits (usually employed to drill water wells) 07. DRILLING BITS TECHNOLOGY 105

How Bits Drill The main mechanisms according to which a bit works are the following:  scraping or gouging  ploughing and grinding  chipping and crushing  shearing  erosion (from the drilling fluid) Roller cone bits work: - with the mechanisms of gouging and scraping when drilling soft formations; - with the mechanisms of chipping and crushing (crater mechanism) when drilling hard formations. Diamond bits work: - with the mechanism of ploughing and grinding. PDC bits work: - with the mechanism of shear

07. DRILLING BITS TECHNOLOGY 106

ROLLER CONE BITS

07. DRILLING BITS TECHNOLOGY 107

Roller Cone Structure

API Pin

Lubricant Reservoir Cover

Leg

Nozzle Boss Tungsten Carbide Hardfacing Nozzle

Shirttail Outer Row (Gage) Cutting Structure 07. DRILLING BITS TECHNOLOGY 108

Cone Inner Row Cutting Structure

Roller Cone Bit Cutting Action: Soft Formations

• Scraping & Gouging – Indentation & Fracture

– Tooth Displacement

07. DRILLING BITS TECHNOLOGY 109

Roller Cone Bit Cutting Action: Hard Formations

• Chipping & Crushing

1. Tooth Impact

2. Wedge Formation 07. DRILLING BITS TECHNOLOGY 110

3. Fracture

4. Post-Fracture

Roller Cone Bit Design

The design of roller cone bits can be described in terms of the four principle elements of their design. The following aspects of the design will be dealt with in detail:

• Bearing assemblies • Cones • Cutting elements • Fluid circulation

111

Bearings and Seals

07. DRILLING BITS TECHNOLOGY 112

Bearing Assembly • • •

Roller bearings, which form the outer assembly and help to support the radial loading (or WOB) Ball bearings, which resist longitudinal or thrust loads and also help to secure the cones on the journals Friction bearing, in the nose assembly which helps to support the radial loading. The friction bearing consists of a special bushing pressed into the nose of the cone. This combines with the pilot pin on the journal to produce a low coefficient of friction to resist seizure and wear.

113

Major Bearing Types a. Roller Bearings – Typically used in large bit sizes – Also referred to as “AntiFriction” bearings

b. Friction Bearings – Typically used in small bit sizes – Also referred to as “Journal” bearings JOURNAL

CONE

07. DRILLING BITS TECHNOLOGY 114

a. Roller Bearing

Rollers

07. DRILLING BITS TECHNOLOGY 115

b. Friction Bearing

Bearing Sleeve

07. DRILLING BITS TECHNOLOGY 117

Lubrification Cone lubrication is an essential factor in determining a bit life. Two types of bearing are adopted for ensuring an adequate lubrication:  open bearing  sealed bearing In the open bearing type bits, the lubrication is ensured by the drilling fluid itself; but because of the presence in the mud of abrasive solids, this type of lubrication is used only in large size bits (above 17 ½”), where the bits are not required to drill for long periods of time. The sealed bearing type bits have a sealed lubrication system, which prevents contaminants to enter the bearing and lubricant to escape. The sealing can be provided by: - an o-ring, manufactured with elastomers; - a metal-to-metal seal.

07. DRILLING BITS TECHNOLOGY 120

Open Bearing

07. DRILLING BITS TECHNOLOGY 121

Cones

07. DRILLING BITS TECHNOLOGY 124

Geometric Elements of Bit Design

•

Directly influence the type of Cutting Action

A. Journal Angle B. Cone Profile Angles C. Offset

07. DRILLING BITS TECHNOLOGY 125

A. Journal Angle

• Definition – “..is the angle formed by a line perpendicular to the axis (or centerline) of the journal and the axis (or centerline) of the bit.”

Bit Axis

Journal Angle

Journal Axis

07. DRILLING BITS TECHNOLOGY 126

A. Soft vs. Hard Journal Angle •

Soft to Medium Formations – 32½º Journal Angle

07. DRILLING BITS TECHNOLOGY 127

•

Medium to Hard Formations – 36º Journal Angle

B. Cone Profile Angles

• Inner Cone Profile Angle • Outer Cone Profile Angle

07. DRILLING BITS TECHNOLOGY 128

B. Cone Profile Angles Outer Cone Angle (Gage Row)

Intermediate Cone Angle (Middle Row)

Inner Cone Angle (Nose Row) 07. DRILLING BITS TECHNOLOGY 129

C. Bit Offset • Definition of Offset: – “..the horizontal distance of the cone axis from the centre of the wellbore” or as “the angle of which is necessary to rotate the cone axis to make it pass through the centre of the wellbore”. • Offset measured in inches – Very Soft formations

typically 3/8” or up to 4o

– Very Hard formations

typically 1/32” or down to 0o

07. DRILLING BITS TECHNOLOGY 130

C. Bit Offset

07. DRILLING BITS TECHNOLOGY 131

07. DRILLING BITS TECHNOLOGY 132

Cutting Structures

07. DRILLING BITS TECHNOLOGY 133

Cutting Structure The cutting structure determines the distinction of the roller cone bits into: - milled tooth bits - tungsten carbide insert bits. The design of the cutting structure will therefore be based on the hardness of the formation for which it will be used.

07. DRILLING BITS TECHNOLOGY 134

Milled Tooth Bits: Cutting Structure Milled tooth bits for soft and hard formations are visually recognizable on account of the height and number of their cutters: • Bits for soft formations have long and sparse cutters. • Bits for hard formations have short and closely arranged cutters. Another feature of roller-cone bits is the cutters’ location on the cones; this is arranged so that each cutter row of each cone strikes its own rock portion on its circumferential path. This feature allows the entire borehole surface area to be subject to the bit action.

07. DRILLING BITS TECHNOLOGY 136

Milled Tooth Bits: Cutting Structure Number 1 Cone

Partially Deleted Tooth

Heel Row

Spearpoint

Tooth Hardfacing (Leading flank)

Nose Row

Intermesh Area or Groove

Middle Row Gage Row Number 3 Cone

Number 2 Cone Pitch Break

07. DRILLING BITS TECHNOLOGY 137

138

Milled Tooth Bits: Cutting Structure Soft Formation Bits A soft formation bit is characterized by a limited number of teeth, the way they are relatively spaced from one another and their considerable length. Soft formation bits mainly work through: • scraping • gouging Operations are carried out with light weights (approximately 2 t/in of diameter) and a high rotational speed (100-200 RPM) of the drill string.

07. DRILLING BITS TECHNOLOGY 139

Milled Tooth Bits: Cutting Structure Hard Formation Bits Hard formation bits have a high number of teeth and a high density of short cutters. Hard formation through: • crushing • chipping

bits

mainly

work

Operation are carried out with heavy weights (approximately 3.6 t/in of diameter), because formations oppose considerable resistance to penetration, and a slow rotational speed of approximately 50-60 RPM.

07. DRILLING BITS TECHNOLOGY 140

Milled Tooth Bits: Cutting Structure

Very Soft

Soft

Medium-Soft Medium

12¼” Bits 0.375” (3/8”)

0.281” (9/32”)

0.281” (9/32”)

0.186” (3/16”)

Total Rows

7

8

9

12

Total Teeth

65

78

109

160

Offset

07. DRILLING BITS TECHNOLOGY 141

Milled Tooth Bits: Cutting Structure Roller Cone Bits Hardfacing Hardfacing is the application of tungsten-carbide on the gauge and teeth to provide increased resistance to abrasion. Without hard-facing a bit would lose gauge and the teeth would dull quickly. Hardfacing provides wear resistance to the teeth and resistance to fracture.

07. DRILLING BITS TECHNOLOGY 142

Milled Tooth Bits: Cutting Structure

Steel Tooth Bits

Advantages

Disadvantages

Long teeth are better in soft Can drill only a limited formations because they dig variety of formations more Cheaper than TC insert cutters

07. DRILLING BITS TECHNOLOGY 143

Tungsten Carbide Insert Bits In these three-cone bits the cutting structure is formed by tungsten carbide INSERTS pressed into appropriate holes bored in the cones. Designations of cones (1-2-3) and insert rows are the same as with tooth bits. Inserts have different lengths and shapes in function of the bit hardness:  soft formations require long and sparse inserts;  hard formations require short and closely arranged inserts;  small and round inserts are placed on the shoulders of the bit.

Figure 7

07. DRILLING BITS TECHNOLOGY 144

Insert Shape: Inner Rows

Soft Medium to Hard

Soft to Medium 07. DRILLING BITS TECHNOLOGY 145

Hard

Tungsten Carbide Insert Bits

Pitch Break

Number 1 Cone

Gage Row Insert Inner Row Chisel Crest Insert

Teeth Rows Intermesh Area or Groove

Number 3 Cone

07. DRILLING BITS TECHNOLOGY 147

Number 2 Cone

Tungsten Carbide Insert Bits • Tungsten Carbide (WC) provides Wear Resistance – Third hardest material known to man – However, it is structurally weak • Cobalt provides Strength and Toughness – Cobalt binder typically 6 to 16% by weight

Tungsten Carbide (1500x) 84% Tungsten Carbide 16% Cobalt

07. DRILLING BITS TECHNOLOGY 148

Tungsten Carbide Insert Bits Very Soft

10 rows / 92 inserts 77/8” Bits Medium-Hard

12 rows / 125 inserts 07. DRILLING BITS TECHNOLOGY 149

Soft

Medium-Soft

11 rows / 114 inserts

12 rows / 120 inserts

Hard

Very Hard

14 rows / 144 inserts

17 rows / 180 inserts

Tungsten Carbide Insert Bits

Tungsten Carbide Insert Bits

Advantages

Disadvantages

Tungsten carbide wears very little so the inserts last longer

Much more expensive than milled tooth bits

The same tungsten carbide bit can drill many different types of formations

Cannot drill as fast as a steel tooth bit in soft-tomedium formations Harder than steel – but also more brittle

07. DRILLING BITS TECHNOLOGY 150

Fluid circulation

151

• CLEANING OF THE CUTTING STRUCTURE • CUTTINGS REMOVAL FROM THE HOLE BOTTOM • AND EFFICIENT CUTTINGS EVACUATION TO THE SURFACE

Fluid circulation through water courses

Fluid circulation through jet nozzles

152

Watercourses

An important part of a rock bit is the watercourse, without which the bit could not function as intended. The design of the passageways and nozzles that direct the fluid when coming out from the bit differentiates between two types of watercourses: 1. Conventional watercourse that directs the fluid onto the cutters 2. Jet watercourses that direct the fluid onto the bottom of the hole (central nozzle and extended nozzles)

07. DRILLING BITS TECHNOLOGY 153

Figure 23

Design Factors Summary Formation Strength Soft

07. DRILLING BITS TECHNOLOGY 154

Med. Soft

Med. Hard

Hard

Very Hard

IADC ROLLER CONE BIT CLASSIFICATION

07. DRILLING BITS TECHNOLOGY 155

IADC Bit Classification A wide range of bits is available in the marketplace. There are many different kinds of bits with different features. For this reason, the International Association of Drilling Contractors, IADC, approved a standard classification system to compare bits having similar features through the use of a numeric code. This standardization, which has been introduced in 1972 and revised in 1992, is extremely useful, because it allows engineers to rapidly find bits with similar features, even if they are built by different manufacturers.

07. DRILLING BITS TECHNOLOGY 156

IADC ROLLER CONE BIT Classification

• 4-Character Design/Application Code – First 3 Characters are NUMERIC – 4th Character is ALPHABETIC • Examples

135M

07. DRILLING BITS TECHNOLOGY 158

447X

637Y

IADC Bit Classification

• Numeric Characters define: – Series – Type – Bearing & Gage

1st 2nd 3rd

• Alphabetic Character defines: – Features Available 4th

07. DRILLING BITS TECHNOLOGY 159

Series

1. First Character: Series • General Formation Characteristics – Compressive Strength – Abrasivity

• Eight (8) Series – Milled Tooth Bits – Insert Bits 07. DRILLING BITS TECHNOLOGY 160

: Series 1, 2 and 3 : Series 4, 5, 6, 7 and 8

Classification Chart: Series

135M

447X 07. DRILLING BITS TECHNOLOGY 161

Typical Formations Hardness

Hardness

UCS (psi)

Examples

Ultra Soft

< 1,000

gumbo, clay

Very Soft

1,000 - 4,000

unconsolidated sands, chalk, salt, claystone

Soft

4,000 - 8,000

coal, siltstone, schist, sands

Medium

8,000 - 17,000

sandstone, slate, shale, limestone, dolomite

Hard

17,000 - 27,000

quartzite, basalt, gabbro, limestone, dolomite

Very Hard

> 27,000

marble, granite, gneiss

UCS = Uniaxial Unconfined Compressive Strength

07. DRILLING BITS TECHNOLOGY 162

Type

2. Second Character: Type • Degree of Formation Hardness • Each Series is divided into 4 “Types” Type 1

Softest Formation in a Series Increasing Rock Hardness

Type 4

07. DRILLING BITS TECHNOLOGY 163

Hardest Formation in a Series

Classification Chart: Type

135M

447X 07. DRILLING BITS TECHNOLOGY 164

Bearing & Gage

3. Third Character: Bearing & Gage • Bearing Design and Gage Protection

• Seven (7) Categories – 1. Non-Sealed (Open) Roller Bearing – 2. Roller Bearing Air Cooled – 3. Non-Sealed (Open) Roller Bearing Gage Protected – 4. Sealed Roller Bearing – 5. Sealed Roller Bearing Gage Protected – 6. Sealed Friction Bearing – 7. Sealed Friction Bearing Gage Protected 07. DRILLING BITS TECHNOLOGY 165

Classification Chart: Bearing & Gage

135M

447X 07. DRILLING BITS TECHNOLOGY 166

Example - Milled Tooth

MSDGH 07. DRILLING BITS TECHNOLOGY 167

IADC 135

Example - TCI

F2

07. DRILLING BITS TECHNOLOGY 168

IADC 517

Features Available

4. Fourth Character – Features Available (Optional) – Sixteen (16) Alphabetic Characters

– Most Significant Feature or Application Listed

07. DRILLING BITS TECHNOLOGY 169

IADC Features Available • A - Air Application

• L - Lug Pads

• B - Special Bearing/Seal

• M - Motor Application

• C - Center Jet

• S - Standard Milled Tooth

• D - Deviation Control

• T - Two-Cone Bit

• E - Extended Nozzles

• W - Enhanced Cutting Structure

• G - Gage/Body Protection

• X - Chisel Tooth Insert

• H - Horizontal Application

• Y - Conical Tooth Insert

• J - Jet Deflection

• Z - Other Shape Inserts

07. DRILLING BITS TECHNOLOGY 170

Classification Chart: Features Available

135M

447X 07. DRILLING BITS TECHNOLOGY 171

FIXED CUTTER BITS

07. DRILLING BITS TECHNOLOGY 172

Types

Fixed Cutter Bit Styles  Drag Bits  Natural Diamond Bits  Synthetic Diamond Bits (PDC: Polycrystalline Diamond Compact Bits, TSP: Thermally Stable Polycrystalline Diamond Bits, Impregnated Bits)

07. DRILLING BITS TECHNOLOGY 173

Types Drag Bits A drag bit is a drill bit usually designed for use in soft formations such as sand, clay or some soft rock. They do not work well in coarse gravel or hard rock formations. Uses include water wells drilling, mining, geothermal, environmental and exploration drilling. Whenever possible, they should be used to drill pilot holes because they produce cuttings that are very easy to log. They are not in current use and are mentioned here only for their historical importance.

07. DRILLING BITS TECHNOLOGY 174

Figure 27 Drag Bits

Natural Diamond Bits Some of the most important benefits of diamond bits over roller bits are: • Bit failure potential is reduced because there are no moving parts. • Less drilling energy is required by their shearing cutting action compared to the cracking and grinding action of the roller bit. • Bit weight is reduced, therefore deviation control is improved. • The low weights required and lack of moving parts make them well suited for turbine drilling.

07. DRILLING BITS TECHNOLOGY 175

Natural Diamond Bits Natural Diamond Bits are made by three main components: • the cutters; • the body or blank; • the shank. The cutters are natural diamonds placed on the surface of the bit, from the nose to the gage, according to well-defined configurations or plots. They are immersed in a matrix composed by a mixture of tungsten carbide and a metallic binder. During the construction process, diamonds are included in the matrix by fusing it (each natural diamond bit is hand-built according to the instructions received from the oil company that placed the order).

07. DRILLING BITS TECHNOLOGY 176

Diamond Bit Terminology & Features

Crown

Junk Slot

Cutters

Diamond Gauge

Shank Breaker Slot API Pin Connection

Natural Diamond Bits A Diamond Bit can have different profiles depending on the formation to be drilled: • a “single-cone profile” presents a rounded shape, which determines a limited load on each cutter. The bit is subjected to a slow wear and long life; • the “double-cone profile” has a narrower attack front and is very aggressive in its central part. The tapered zone maintains the hole in gauge. The bits with this profile ensure higher ROP, but also a more rapid wear; • the “parabolic profile” has a front more rounded than the previous type; it represents a compromise between the two previous profiles; • the “concave profile” has a flat front; it is mainly used in directional drilling.

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Natural Diamond Bits This type of bits is not equipped with nozzles. Hydraulics has the main purpose of cooling the bit face and removing drilled cuttings. The exit holes of the drilling fluid are positioned in the centre of the bit. Fluid is then directed into grooves carved out of the bit face. Grooves are designed according to two main configurations: • Radial flow • Cross-pad flow or feeder-collector flow. In both configurations, the outflow of drilling fluid from the bit centre takes place through a “crowfoot” that distributes the flow into three branches.

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Natural Diamond Bits Collector Crowfoot

Feeder

Waterways

Pad / Rib

Crowfoot

Cross-Pad Flow 07. DRILLING BITS TECHNOLOGY 181

Radial Flow

Natural Diamond Mechanics • Natural Diamond Bits drill by ploughing and grinding the rock • Normally require higher RPM for better performance (e.g. high speed motor or turbine)

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Synthetic Diamond Bits Synthetic diamond bits fall into two main categories: • PDC – polycrystalline diamond compact bits • TSP – thermally stable polycrystalline bits

General Electric was the first company to produce synthetic diamonds on an industrial scale in the Fifties. Same advantages and disadvantages as natural diamond bits but use small discs of synthetic diamond to provide the scraping cutting surface. The small discs may be manufactured in any size and shape and are not sensitive to failure along cleavage planes as with natural diamond 07. DRILLING BITS TECHNOLOGY 184

TSP Bits If uses in high temperature environments are predicted, it is possible to employ construction techniques capable of producing industrial diamonds with a higher degree of thermal stability, namely the TSP diamonds or thermally stable polycrystalline diamonds. There are two main construction techniques: • a technique is based on the acid treatment of the synthetic diamonds produced by the method described above, in order to dissolve cobalt; • the second technique requires the use of silicon carbide as a bonding agent for the diamond particles. Both these techniques allow the realization of industrial diamonds with a thermal stability of about 1150oC. The disadvantage is that TSP diamonds can not be welded onto any substrate, differently from PDC bits, but they must be included in the bit matrix. TSP bits are produced by means of techniques similar to those described about natural diamond bits. In general terms, they are suitable to drill hard and abrasive formations. 07. DRILLING BITS TECHNOLOGY 186

Polycrystalline Diamond Compact PDC Bits PDC bits were introduced in the 1970s and combine the high abrasion resistance of the diamonds with the strength and impact resistance of tungsten carbide. The advancement in PDC design and performance in recent years has been significant and there are now many manufacturers with a wide variety of bits available. Due to the diversity of bits and bit features available, there is no IADC classification system similar to roller bits but simply a code to provide a means of characterizing the general physical characteristics of fixed cutter drill bits.

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Polycrystalline Diamond Compact PDC Bits PDC cutters are built in standard dimensions ranging from 8 mm to 24 mm: • Very small cutters (8 mm wide) are used in hard formations. • Small cutters (13 mm wide) are used in medium to medium hard formations. • Large cutters (19 mm wide) are suitable for soft to medium formations. • Very large cutters (24 mm wide) are used in soft formations. Cutters as wide as 48 mm have also been used sporadically.

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PDC Bits

Steel Body

Matrix Body

PDC Bits

Polycrystalline Diamond Compact PDC Bits Profiles of PDC Bits PDC bits have three basic profiles: (a) Flat profile (shallow), used to drill hard but not abrasive formation (b) Double cone profile (taper) offers a larger work surface and is thus suitable to drill harder formations. (c) Parabolic profile, used in combination with a turbine to drill soft but abrasive formations

a

b Figure 37- PDC BIT PROFILES

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c

Polycrystalline Diamond Compact PDC Bits A further discriminating construction feature is the number of blades, that have the following main functions: • Supporting the cutting structure. The positioning of cutters on blades creates an adequate support structure capable of absorbing the forces engendered on the cutter itself. Generally speaking, when moderately hard formations require a bit with many cutters, the tool will also be equipped with many blades. • Determining the hydraulic flow profile. Blades are set according to well defined paths, so that the drilling fluid flows optimizing both cutting removal from the bit surfaces and its cooling. • Increasing the frontal exposure of the cutter.

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PDC Mechanics

• The shearing action is the most efficient cutting action when operating under identical conditions.

Weight on bit

• PDC cutters cut the formation in shear.

Rotation

PDC Bit - Shearing

PDC Mechanics One important feature of PDC bits is their back rake angle. • Angle at which a PDC cutter attacks a formation. • Higher back rake angles improve impact and wear resistance. • Lower back rakes increase ROP. • Back rakes can be varied to achieve maximum ROP and durability.

+

B.R

PDC Mechanics • Back Rake Angle – 5° to 10°

– 15°

•

Formation Hardness – Very soft clays/shales. – Low angle produces highest ROPs

– All formations. – Best in soft formations (e.g. shale) – All formations. – Improves cutter life. – Best in abrasive/sand formations

– 20°

– 30°

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– Harder formations – Typically used on gage – More durability and reduction of vibration

IADC FIXED CUTTER BITS CLASSIFICATION To take into account the wide range of fixed cutter bits including natural diamond and PDC, IADC introduced a classification system consisting of a four character code: Code 1 - Cutter Type and Body Material (D, M, T, S, O) Code 2 - Bit Profile (1-9) Code 3 - Hydraulic Design (1-9) Code 4 - Cutter Size and Density (1-9).

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IADC FIXED CUTTER BITS CLASSIFICATION Code 1: Cutter Type and Body Material

The subgroup classification is simply a five letter designation categorizing the type of cutter and body material.

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IADC FIXED CUTTER BITS CLASSIFICATION Code 2: Bit Profile

The code numbers (1-9) categorize the bit profile by shape.

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IADC FIXED CUTTER BITS CLASSIFICATION Code 3: Hydraulic Design

The code numbers (1-9) describe the hydraulic features.

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IADC FIXED CUTTER BITS CLASSIFICATION Code 4: Cutter Size and Density

The code numbers (1-9) categorize the cutter size and cutter material.

EXAMPLE OF CLASSIFICATION A fixed cutter bit with the code M442 corresponds to a PDC bit with matrix body, medium taper-deep cone, changeable jets-ribbed design with large size cutter of medium density. 07. DRILLING BITS TECHNOLOGY 202