Petro Data Mgt II- Drilling and Production Petroleum Professor Collins Nwaneri.

Petro Data Mgt II- Drilling and Production Petroleum Professor Collins Nwaneri

Drilling Geology Overview – geology as it relates to drilling operations and basic principles of hydrostatic pressure exerted by a fluid at depth as it is important for drilling operations. Types of Rocks: 1. Igneous rocks – Formed by molten rock cooling and solidifying. what are examples of Igneous rocks? 2

Continued Sedimentary rocks – Formed by digenesis (chemical changes) or cementation of sediments. Metamorphic rocks – Formed by the physical changes of existing rocks by high pressures and temperatures. which of this rock type is likely to be a better source rock and why? 3

Continued Plate Tectonics – solids plates found underneath the earth surface floating on top of liquid rock or molten rock. Movement of the plates leads to rocks moving up or down within the earth crust. It can also need to rock beds becoming folded, broken and turned over. Fluid pressure and stresses within the rock will vary. Two major types of rock movements are: 1. Thrust fault (rocks are compressed together) to move in what direction? 4

Continued Normal fault(rocks are stretch apart) to move in what direction? 5

Lithology Lithology- a description of rocks that is based physical characteristics such as mineral comp, color, grain size and texture. Lithology affects many drilling decisions when planning and drilling a well. Examples of some lithologies: 1. Shale- consists of layers of clay minerals. They form about 75% of sedimentary rocks. Shale cause about 90 % of geology related drilling problems. What will happen if water based drilling mud is used to drill reactive shale formations? 6

Continued 2. Sandstone – consists of particles of sand (quartz), and maybe with traces of other minerals, such as iron. - clay minerals can also be found within sandstone if found within sandstone, how will it cause problems? - 11% of sedimentary rocks are made up of sandstone. Sandstone or other rocks must have porosity and permeability in other to be a reservoir. 7

continued What is a reservoir and define porosity and permeability? How is the porosity and permeability for sandstone and shale? Yes or no…..can a rock have permeability but no porosity. 3. Carbonates – composed of fossilized skeletons and minerals grains of calcite (crystals of calcium carbonates). Example is limestone. They are crystalline limestone and fossiliferous limestone. what is the difference between them? Most limestone's are fossiliferous. 8

Continued - Carbonates are often fractured due to their brittle nature. Fractured carbonates make prolific reservoir rocks as oil and gas collect in the fractures -They have high permeability and can produce high rates of hydrocarbons if intersected in a drilled well. - can also loose drilling fluids into the formation due to the fractures. Carbonates make up 13% of sedimentary rocks 9

Continued 3. Evaporates (salts) – occurs as result of sea water evaporating, leaving behind soluble salts. Less soluble salts are deposited first out of solution. Very soluble salts come out when dehydration is almost complete. - Salts can cause drilling problems…True or false. How? - What can you pump to dissolve flowing salt around drill bits in a well that causes the bit to stop drilling? - salt dome are good trap for reservoirs hydrocarbons. 10

Rock Strengths and Stress Rock strength varies depending on the types of stress applied on the rock (compressive, tensile or shear and may also vary due to the direction the stress is applied. - Tensile stress is negative rock stress -Compressive stress is positive rock stress -Shear stress is up and down rock stress Overburden stress – vertical stress due to weight of surrounding rocks. 11

Continued Stress distribution is affected by tectonic activities. -No or little tectonic activity …less horizontal compressive stress and high vertical compressive stress -With tectonic forces or other forces, stress differs. Example basic stress distribution magnitude in disturbed horizontal and vertical wells? 12

Principal stress Three stress resolved in perpendicular direction to each other. Two horizontal and one vertical stress. All compressive or tensile ( no shear stress). - stress orientation is important in designing a well and procedure to drill it successfully. Fracture pressure – rock ability to withstand pressure, which can cause tensile failure if not controlled. 13

Hydrostatic pressure Fluid impose hydrostatic pressure in a well and if the downhole pressure is not kept under control, it can cause an uncontrolled release of hydrocarbons (Blowout). Pressure is force/Area When formation pressure is higher than is normal for a depth this is called Over pressured formation 14

Geological input to drilling wells You need to know the relationship between hydrostatic pressure, fracture pressure and pore pressure for a successful drilling operations. 15

Oil and Gas Reservoir Formation Overview – The processes involved in petroleum generation, migration and accumulation into an exploitable reservoir will be described. Important rock properties for reservoir creation and fluid properties within the reservoir will be described. Hydrocarbons move upwards within the earth until they meet a barrier, and then may accumulate as an oil and gas reservoir. If there is no barrier, then they migrate to the surface as oil seep. 16

Continued They are seven main factors that all need to be present, in the right order, for a hydrocarbon accumulation to occur. These are the following: 1.Source rock 2.Hydrocarbon generation 3.Primary migration to a suitable structure (Reservoir) 4.Structural trap 5.Reservoir rock 6.Seal Rock 7.Secondary migration within the reservoir Which of this factors can be best attributed to what is called a dry wellbore? Mention at least two man made factors that can result in a dry wellbore? 17

Source Rock and Hydrocarbon Generation Buried remains of plant and animals accumulated over millions of years ago in slow moving or stationary water environments such as swaps, lakes, coastal regions and shallow seas. These organic materials plus other non-organic particles (clay minerals, fine sands, and silts) sank to the bottom and resulted in a build up of sediments over a long period. Increasing Temperature and Pressure with depth of this organic-laden sediments results to sedimentary rocks when they under go digenesis. 18

Continued About 99 % of all hydrocarbons deposit are found in sedimentary rocks. Chemical transformation also occur in the organic matter present in the pore spaces of the rock. Oil is generated from organic remains under certain conditions, with temperature as the most important factor. Oil generation starts at 50 deg. C and conversion to oil peaks 90 deg C and stops at 175 deg C. This temperature range between 50 deg C and 175 deg C is known as the oil window 19

Continued The decay of organic remains that generate gas occurs at below and above the oil window. Biogenic gas (generated by microbes) or swamp gas is generated at a temperature below 50 deg C. Thermal gas is generated at above 175 deg C. Heavy oil is generated at temperatures at the lower end of the oil window At Increasing temperature, lighter (more valuable) hydrocarbons are generated. At a high rock temperature of above 260 deg C, the organic mineral, which generates oil is destroyed. 20

Continued Petroleum is made up of: (83%) Carbon and (13%) Hydrogen and sometimes with small amounts of sulfur (up to 2%), nitrogen (0.5%) 90 % of most crudes oils contain hydrocarbons that are composed of carbon and hydrogen. Source rocks are rocks that produce hydrocarbons from organic matter that are buried within the rock pore space. Shale is the most common source rock for most oil and gas sedimentary rocks. 21

Continued Types of shale are Black, Green or Gray Shale Black shale has about 1 – 3 % of organic matter. Green or Gray shale has about 0.5 % of organic matter. Only about 2 % of deposited organic material becomes hydrocarbon. And only about 0.5 % is found in commercially exploitable reservoir. Coal comes from woody plant remains deposit. Low quality coal generated at lower temperature and pressure High quality black coal is buried deeper under higher temperature. Methane (Hydrocarbon gas) is also generated as a bye product from woody plants remains when coal is formed. This can migrate upwards to form a Gas Reservoir. 22

Vital Rock Properties Hydrocarbon is formed in pore spaces of a source rock. Rocks can be: 1. Highly or well consolidated 2. Poorly consolidated or unconsolidated This is controlled by the mineral bonding holding the rocks together. Which of the two above will have a stronger bonding? Two Important rock properties are Porosity and Permeability. 1. Porosity – the extent of porosity is measured as the fraction of the total rock volume occupied by the pore spaces. Porosity is expresses in percentage - Rock porosity is very important because without porosity hydrocarbon cannot be generated, migrate or accumulate in a reservoir. 23

Continued If 30 % of the total volume of a rock has pore spaces, what is the rock porosity? 2. Permeability – Ability of a rock to allow fluid to flow through it. It is measured in darcies. - Needs connected pore spaces. - Rock permeability is very important because oil generated in the source rock cannot migrate into a reservoir. -Shale has very low porosity and low permeability. -Hydrocarbon and water produced in the shale source rock are squeezed out by pressure and it takes a longtime for the fluids to migrate out. 24

Primary Migration The first two conditions necessary for the birth of a reservoir are : 1. Organic rich source rock. 2. Temperature and time for hydrocarbon generation. Finally, the source rock should be next to a permeable rock or channel that allows for hydrocarbon migration. -Conduit of hydrocarbon can be provided by permeable sandstones, fractures in the rock or ancient reefs. 25

Structural Traps A structural trap has the ability to trap the hydrocarbon as a result of it’s primary migration from a source rock. Maybe formed in a deformed rock as a result of movements within the earth crust. Examples of structural traps are: 1.Anticline 2.Salt Dome 3.Angular Unconformity 26

Reservoir Rock Hydrocarbon (gas or oil) and water are found in pore spaces or fractures within the rock matrix. Most reservoirs are sandstones which have good porosity to hold hydrocarbon and high enough permeability for production. Carbonates (limestone) with fractures and/or pit tend to be prolific reservoirs with high porosity and permeability. Reservoir rocks that have clay within the pore spaces tend to reduce permeability around the wellbore. Reservoirs may have different layers of varying characteristics that leads to what is known as directional permeability….difference in permeability due to direction of hydrocarbon flow. 27

Seal Rock Impermeable rock that is a seal above a reservoir rock to prevent upward migration of hydrocarbon. Clean shale, salt and unfractured limestone are examples of seals. Seal rocks are a source of a formation pressure transition from a normal pressure to overpressure. 28

Secondary Migration Formation of hydrocarbon pools due to movement of hydrocarbon droplets within the reservoir. Also another step may occur when the earth crust movement shifts the pools position within the reservoir rock. Accumulations can be affected by: 1.Buoyancy 2.Other Impermeable barriers 3.Hydrocarbon accumulations in carbonate reservoirs 4.Different layers of shale in large sandstone may distribute reserve with earth crust movement. 29

Continued 5. Faults 6. Uplift and erosion 7. Cap rock fracturing Single Phase Reservoirs – contain only single fluid (gas or oil). Oil is seldom found without some gas or some water. Most Reservoirs are multi-phase – they contain mixtures of gas, oil, and water Secondary migration separate’s this fluid out by gravity, and gas sits at the top (Gas Cap), and then oil under gas and water under oil (lightest fluid at the top of heaviest fluids at the bottom) 30

Reservoir Drives Energy that is used to move the hydrocarbons to the surface from the reservoir when first drilled. Most oil when first drilled have sufficient pressure (energy) in the reservoir to push the oil to the surface. Types of energy sources: 1. Gas Drive – partially or completely isolated from the pressure regime in the surrounding rock. Oil production causes the gas cap to expand and looses it energy. - The temperature and pressure in the reservoir will drop and there will not be enough energy left to drive the oil out of the reservoir. 31

Continued Gas drive is not an efficient long-term production producer. The following can be done if there is no sufficient pressure left to drive out oil in order to increase the reservoir pressure: 1.Inject more gas 2.Ignite oil underground by injecting air 3.Install a down hole pump to pump oil to the surface 32

Continued 4. Inject gas into the well (gas lift) 5. Inject water and chemicals in some part of the reservoir All of the above method are called secondary recovery method. 2.Water Drive – has a reservoir that is connected hydraulically to an area regime (i.e such as aquifer that is open to the atmosphere). - In addition, in a sedimentary rock sequence, there is a local water table(rock pore spaces with salt water, which exerts a pressure at depth. (Principles of hydrostatic pressure) 33

Continued - The water from the local water table pushes the oil to the oil well. - Water drive last longer than gas drive. - water is eventually produced as oil is driven out from the well and may cause what is known as water blocking in the well (Increase in the amount of water in the pore spaces blocks oil) 34

Problems Related to fluids in the reservoir Hydrogen sulfide can be produced from degradation by bacteria of the oil in a reservoir - it is extremely toxic and it is also called sour gas. Carbon dioxide in reservoirs can lead to corrosion of steel in a wet environment. - This can cause corrosion problems for well tubular. Hydrocarbons that have both H 2 S and CO 2 are normally treated before they are sold. 35

Drilling a Land Exploration Well Overview – This will cover the planning and execution of exploration well drilling on land.

Identifying a Prospect An area called a Block is purchased by an oil and gas company to explore for hydrocarbon. A permit is bought to explore on the block by the operator because they believe: 1. The geology shows indication of hydrocarbon accumulation 2.Cost of exploration will be worth the chance of finding an exploitable well 3.They can afford to absorb the exploration cost if nothing substantial is found or can afford to develop any discovery to produce hydrocarbon to market.

Continued An exploration well is drilled to gain information. It is false economy to drill an exploration well to later produce hydrocarbon. This is due to the lack of sufficient information about a reservoir rock when a well is first drilled as an exploratory well that may affect the well design of a producing well, if unexpected changes conditions are encountered while drilling. Exploration wells should be minimum cost well that should be used to get essential information and then abandoned.

Well Proposal Let us a use an example of a potential trap of oil and gas in an angular unconformity structure. There are indications that it contains a gas cap on top, with a column of oil and water below. A call was made to drill the well into the edge of the gas cap and follow the bedding plane down through the oil and into the water. The above is done in other to establish the following well objective:

Continued 1. Prove that oil and gas both exist in the reservoir, samples of each are collected for analysis, and the fluid pressures are measured in the reservoir. 2. Determine the gas-oil and oil-water contact depths. 3. Take rock samples in the oil part of the reservoir. 4. Test the oil layer to measure the following: a. The maximum rate at which the oil can flow before the start of sand production. b. The maximum possible production rate. c. Internal reservoir characteristics of the reservoir such as: permeability, porosity, internal pressure, and temperature.

Continued d. Indications of damage to the reservoir from the drilling operation. This is known as mechanical skin and causes permeability reduction. After the well objectives are carried out from the exploratory well, a well proposal is written, which is request from the exploration department for a well to be drilled. It provides the necessary information to the drilling department to start designing the exploratory well.

Continued The Well Proposal Content : The well proposal contains the following information: 1. The type of well (exploration) and well objectives (as stated above) 2. Essential well design data: a. Surface (rig) location to use, if known. b. Down-hole targets to hit along side acceptable margin for error. c. Description and depth of the down-hole rock strata as far as possible. d. Expected down-hole formation strengths and fluid pressures inside the rocks.

Continued e. The down-hole temperature variation with depth. (Temperature profile) f. What information is required from the well. g. If core samples of rock will be obtained and at what depths. h. If the well should be abandoned or temporary secured for later use after operations i.The well completion design. The drilling department will have to review the well proposal to make sure the following criteria are met:

Continued 1.The proposal is logical, and the objectives can be achieved. 2.The essential well design data is complete, and there are no ambiguities or omissions. 3.The directional target for the well hits the reservoir as large as possible. This is in other to reduce the well cost if a smaller target is hit. 4.The proposal does not give rise to unsafe hazards to personnel, rig or well. After the well proposal is agreed to by all parties, the drilling engineers start the well design.

Well Design and Drilling Program A well design defines the final status of the well. A drilling program is a document that the drilling engineers use to advise the rig on how the well design might be achieved. - A drilling program can be modified due to unplanned events during drilling. Well Design There are five areas that must be defined when designing a well:

Continued 1.Completion design - this is conduit design for hydrocarbon to travel from the well bottom through the well head and to the surface production facilities. 2.Casing design - it defines the pipes and cement sheath that seals the space between the casing and hole. 3.Directional profile - The 3D path of the well from the surface location to the reservoir. 4.Wellhead configuration - it is a surface pressure tight component assembly that handles the load imposed on the well, such as casing string weight and internal fluid pressure from the well.

Continued Well Fluids requirements - the final fluid mixture configuration after drilling. Completion: consists of many pieces of tubing that are joined together. - All the joined tubes are called a string - A connection is what makes up’s series of tubing’s and also casings. - Completion connections has to withstand both the tubing weight plus additional weight and allow hydrocarbon flow without leaks. - There are other components such as Valves that control fluid flow and components to position other tools inside the tubing

Continued - Parkers can also be used to form a seal between the outside of the completion tubing and inside of the casing. Normally, Parkers are used to prevent the flow of hydrocarbons outside the tubing. (diag) -One device that is installed in every completion is a subsurface safety valve (SSSV). It a can be placed surface (or below the seabed). This used for well control. -The completion in an exploratory well is a simple configuration used to test well performance with a production test or well test. The type of completion is called test string.

Continued Casing Design - designed from the bottom up starting from the total well depth. - Normally determined by the completion design. This is also related to the hole size and casing size. -The fluid pressure at the well bottom and rock strength higher up are used to help select the next casing point depth which is cemented in place. -Depth sand size’s of all casings are designed by the drilling engineer. -Casings and their connections must withstand the forces imposed by the casing weight, lowering the casing down-hole (bending due to well path), internal pressures and high temperatures.

Continued Directional Profile: Wells can be drilled vertically or directionally depending on the well objective. - Directional wells can be a low or high angle build or drop well or Horizontal well. - Directional wells are drilled to: intersect a target that cannot reached when drilled vertically, to drill two or more wells from a single pad, for precise placement in a small reservoir target for maximum production and intersect multiple reservoirs in well path. mention types of casing with directional profile (diag) A relief well can be a vertical or directional well which is drilled to help relief an adjacent well with over flowing hydrocarbons.

Continued There are two types of depth 1) Measured depth and True vertical depth. Wellhead – visible part of the well. The three main types of wellheads are: 1. Land wellhead – used with a beam. No pressure on wellhead. Oil pumped to surface with a pump. No parker between the completion and casing. 2. Subsea wellhead – placed on the sea-beds. It has a housing on top with running tools that is visible to lower the wellhead and release it. 3. Spool type wellhead – consist of a conductor casing at the bottom, then a surface casing is hang with a casing hanger inside that sits on top of the conductor casing. An intermediate casing is ran Inside the surface casing and sits in the casing head housing and it is secured with it’s own casing hunger. A production casing can also be run from the surface.

Continued Well Fluids : After drilling, the fluid types to be left inside will be specified before a completion fluid or parker fluid (brine) before a completion tubing is run. Drilling Program - it contains advisory instruction to the well on how a well should be drilled. - it is an advice that can be subject to change if necessary. The following can be major headings of a well program for drilling and completing a well: 1. General Information 2. Well Objective 3. Potential Hazards 4. Surface location and how the rig is to be positioned

Continued 5. General notes, including: a. Reference to government regulations, company polices, and oilfield standards. b. Reporting procedure c. Quality control and data recording requirements. d. A diagram of the completed well. e. Equipment checklist and suppliers of each item. f. Cost estimating information to allow the well cost to be calculated. 6. Drilling notes fro each hole section, that includes the following:

Continued a.A potential hazard or problems, how to avoid them, and how to recover. b.Required drilling practices c.Recommended operational sequence of events. d.Kick tolerance e.Drill bits recommended f.Bottom assembly recommended g.Any special requirements

Continued 7. Drilling fluid design and maintenance requirements for the whole well 8. Wellbore trajectory information 9.Casing design for the well and how they should be cemented. 10.Geological information of the formations to be penetrated. 11.Logging and coring programs. 12. Well completion design. 13. Well test information (if it will be production tested) 14. Well status when rig has finished work.

Drilling a Well General sequence is similar for almost all well drilled. Location preparation and conductor driving: - Obstructions are cleared and removed. - a hole is dug on under the rig on land so that a Blow out preventer can be placed on top of the casing. Ordering Equipment: - Quality control is important on equipment ordered. Must meet industry standard - Give time to get equipment.

Continued Checking the infrastructure: - Drilling operations should be able to handle high volume traffic at anytime of the day or night. Moving the rig on location and attaching a diverter: - Land rig break down into packages that are moved by a truck. Each major part must be accurately positioned relative to the substructure.

Continued Spudding the well: After the conductor pipe is driven into the ground and the debris is then circulated with mud. - The first drill bit drills a hole called the Pilot Hole (because the hole will be redrilled later) with a larger bit. The start of drilling this hole is called spudding the well. This time is taken as to when the drill bit leaves the bottom of the conductor pipe. - Spud mud is the fluid used to drill the top section of the mud. -Discuss drill bits, drill collars, mud, flow-rate, operating parameters and limitations in spuddng a well.

Continued Drilling the first hole section: - A well is drilled until it reaches the depth to run the surface casing. - one common problem with drilling surface hole section is lost circulation (fractures or permeable rock) - Discuss Drill-pipe’s and tool joint, drill collar, x- over sub, bit sub, what is BHA et.c - When drilling is stopped, the hole is circulated with mud to remove all cuttings before the pulling out. If not…mention what can happen. This circulation is called circulating clean.

Continued - Caving is described as a result of rock falling of the side of the wall when drilling surface holes that have weak and unconsolidated formations. - Three 30 ft pipe screwed together is called a stand (90 ft). - The pilot hole size is enlarged with a Hole Opener (has a bull nose on the bottom) to be able to run the surface casing.

Continued Running and Cementing surface casing : - Surface casing is cemented in place with the casing shoe in the strong formation. - The CHH is used to hold the surface casing on top above the conductor pipe and it is attached on top to the Blow Out Preventer (BOP). - BOP and control systems must be pressure tested. - BOP systems come in pressure rating of 2000 psi, 3000 psi, 5000 psi, 10,000 psi and 15,000 psi. BOP also come in different sizes and the size is the nominal inside diameter of the BOP.

Continued Drilling out the casing and testing the formation strength: - A float shoe (valve made up of cement with some plastic components) is below the surface casing. - This is drilled out with cement below to do a formation strength test below the casing shoe. - Drill bit is pulled into the casing and the blow out preventer is closed to provide a seal. Fluid is pumped slowly into the drillpipe. - After a while the volume of fluid pumped would result to higher surface pressure from normal and this point is called Leak-off test.

Continued When you know the depth of the formation and The pressure it will bear the formation strength gradient can be calculated: i.e. : 730 psi total pressure on formation divided by depth = formation strength gradient - The driller can figure out the maximum surface pressure that can be exerted on the well with the particular drilling mud density in the hole. This is called the Maximum allowable annular surface pressure (MAASP) and can be calculated by:

Continued MAASP = (Formation strength gradient – Mud gradient) * Vertical Depth I.e. with 0.5 psi/ft mud in the hole MAASP is 230 psi. So a reduction in mud gradient is equal to reduced MAASP. So, if the MAASP pressure is exerted in an overpressure formation, then a Kick is likely to occur.

Continued Drilling the intermediate section: - Normally drilled to a given direction and target that is not the surface location. - A BHA is made up to build or drop or hold in this section. - A will may contain more than one intermediate casing or non, if it is a shallow well.

Continued Logging: Usually ran as a wireline tool in the intermediate hole section for the following reasons: 1.To establish formation tops and thickness. 2.Litho logy, porosity, pore fluid sanity, and presence of hydrocarbons. 3.Continuous hole profile 4.Formation compressive strength.

Continued Running and cementing the first intermediate casing: - As with the surface casing a float shoe is screwed on the bottom, then after two joints of casing, a float collar is run. Float collar is different from a float show because it has thread at the bottom and allows other casing to be run inside it. -The casing head housing and hoses are made up to the casing. Hoses are for fluid conduit.

Continued - Pressure testing is done above the casing hanger to ensure that the hanger seal works, then the BOP can be removed. - Afterwards, a housing called the casing spool as added to the wellhead. This is made up of casings, hanger and spools. -The next BOP which is smaller than the first is attached to the top of the spool. It has a higher pressure rating

Continued Drilling the production hole section: - Casing normally set above the reservoir and the reservoir is drilled through to set a liner. - liners are not ran to the surface, but suspended with a liner hanger inside the ID of the last casing - advantages of liners are: reduced cost (short length of casing pipe and less cement needed) and a disadvantage is increased difficulty running it downhole - it is essential to run cores into the reservoir to get information while drilling through the reservoir. - Logging the hole: tools ran to provide well information -Takes sample of the formation fluids, pressure readings and measure formation permeability Running and cementing the production liner: - Drillpipe use to lower the liner with the Liner hanger can be mechanically or hydraulically set inside the casing ID - Cement is placed in the annulus and drillpipe is released from the liner hanger and pulled out.

Production Testing the Well The cutting samples, logs and core samples show there is hydrocarbon Preparing the well for the test string: - it involves cleaning the hole section with fluid Running the test string: - A string of tubing that is run fro hydrocarbon production for production testing (drill stem test) - it has s SSSV for well control. -Tubing is suspended at the well head -The BOP is removed and a Christmas tree is installed

Continued - A special BOP is placed on top of the Christmas tree, which allows well’s to be perforated with wire-line while providing a seal. Perforating the Well: - A logging cable is used to run perforating guns inside the tubing to perforate the tubing opposite the reservoir. Testing the well: discussed later Killing the well after the production test is complete: - Heavy fluid is pumped to kill the well, once the well test is over.

Abandoning the well A well is abandoned when there is use for it after well testing. This is done by placing cement in the well. Removing the test string: - Test string is pulled out once the well is dead. Making the well safe into the future: - Cement is pumped into the perforations - casing is cut and pulled out - Conductor is cut and cement is dumped on top.

Planning and Drilling a Development Well Offshore Overview – This will cover the drilling of a development well offshore in template on the seabed. An drilling of an horizontal well will be used as an example. A development well is drilled for hydrocarbon when the field is commercially exploited. Well Planning - A suspension cap is used to protect the wellhead from debris and corrosion until a platform is placed on the wellhead. - The well is connected for production after the platform is placed on the template. - Coring is not used in development well, but can be requested - The wells are closed together (directional plan is vital)

Continued Completion Design: The following should be considered during well completion design. 1. Well inflow configuration-affects flow of hydrocarbon from reservoir the well. Sometimes, stimulation can be used to increase permeability (i.e. Acid), fracturing, e.tc during completion. 2. Well Outflow configuration- affects hydrocarbon flow from the reservoir to the surface. This affects the tubing size and type or any down-hole valves or pumps placed in the tubing string for completion. -Water coning occurs when there is a breakthrough of water pass oil in a well that is at (perforated) a Oil-Water interface. More water production than oil -The same will occur for gas (Gas breakthrough) -A vertical well that is perforated for flow creates high flow rate from the reservoir which will have a high tendency for gas or water coning compared to a horizontal well reservoir. (Why?)

Hole and Casing Size In development well compared to exploratory well, one less string of casing if not needed can help reduce cost by 15% if the well can be drilled one size smaller. The size of the completion tubing and type of completion affects the hole size of the final hole section. A liner can also be used as part of a completion tubing. This is design type is called monobore completion. Unlike a traditional completion design..(Illustrate..) In horizontal well, it is best to place the well above the oil-water contact but below the gas-oil contact. Appraisal drilling means drilling done after an exploration well to further appraise the hydrocarbon. (Discuss drilling from vertical to kick-off, build, Tangent, second build and Horizontal steps…with diag.)

Writing the Well Program Usually done by the drilling engineer with the aid of data from an exploratory well and appraisal well. Care is normally taken when using such information. Drilling a Well Spudding the well and cementing the conductor: A floating rig is used as an example. For this a template is place on the seabed and steel pipe at each corner is cemented in place. A conductor slot used to pass conductors through is fitted above.

Continued -Drilling the well Drilling the surface casing: No diverter is run because surface hole is drilled from a floating rig with the returns to the seabed. If shallow gas is encountered, the rig drops the drillstring and moves away. Subsea BOP installed on top of the outside of subsea wellhead which is on top of the surface casing. A riser (steel pipe) is attached to BOP and lowered to the seabed. Heave Compensator: Used to help keep the drill bit on bottom for actual weight- on- bit (WOB) while drilling or landing a casing if the rig floats up and down due to waves.

Continued Kicking off the well: Kick-off should be started and finished in one hole section High up kick-off, smaller the displacement of he well. Less hole id drilled to reach the target Lower kick-off, longer the well displacement. More hole to be drilled to reach the target. Kick-off for this well is done in the first intermediate section (want mud return) (Discuss Build rate examples during kick-off, BHA for directional objective, i.e mwd, mud motor and functions like tool-face, azimuth etc and how everything work together)

Continued Drilling the tangent section: A straight hole section drilled after the kick-off to the next build or drop section. (Discuss survey measurement from point to point..MD, TVD, Inclination and Azimuth and how the tangent is drilled i.e. BHA preference, objectives) Locating the casing point: Casing point depth is normally selected in the well design because the well geology is already known from the exploratory well.

Continued (Discuss use of drillability with bit types to determine formation type for casing point. Why circulate at the end of drilling a casing point) Logging: Logging is done to gather formation data to optimize a well and better understand the fluid types. (Discuss lwd and wireline)

Continued Bringing the well to Horizontal: In order to drill into the horizontal section, the second kick-off point must exactly be right to place the horizontal section not too high or low in the reservoir. (Discuss method of drilling from here and other things to consider i.e. casing point to isolate reservoirs et.c)

Continued Drilling the Horizontal section: Production casing is run and cemented with the casing shoe in the reservoir and horizontal. (Discuss method of drilling the horizontal well i.e. overbalance and underbalanced in relation to reservoir formation damage and sand control and BHA) Suspending the well: A well needs to be left in a safe and stable condition for later re-entry and move to drilling other wells. Most operators and government regulations require at least 3 physical barriers to prevent hydrocarbons reaching the surface. i.e. for well example, barriers are hydrostatic pressure, one bridge plug and cement plug. A suspension cap is placed on the well head.

Rig Selection and Rig Equipment Overview- How to select a rig, types of rig an cost, rig equipments and functions. Selecting a Suitable Drilling Rig Classification of drilling rigs deals with the environment in which the rig has to function. (Use diagram in illustrate) Special units such as: coiled tubing units, snubbing units and work-over hoist are used for working on oil and gas wells are not classified as rigs The requirement for a rig is a based on the drilling program, working environment, rig availability and cost.

Classifications of Drilling Rigs - Description Land Rigs: 1) Heavy land Rig: for drilling deep and heavy deep wells (over 10,000 ft) -Maximum derrick load is equal or more than 1,000,000 Ib -Has two or three mud pumps -BOP rated at 10,000 psi and above -It cost around $80,000 per day 2) Light land Rig: for drilling shallower wells - maybe used fro work-over operations - It cost around $25,000 to $40,000 per day

Continued 3) Heli-rig (Helicopter transportation land rig): placed on location by Helicopters in remote areas without road access. - Can cost as much as Heavy Rig cost per day, depending on the capacity, but running cost will be higher due to helicopter operations. 4) Automated singles rig: highly automated rigs that use pipe handling system to lay down all the drill-string components when pulling out of hole. - it does not have a large derrick - works with fewer people on the rig than convectional rigs 5) Coiled tubing rig: cannot rotate, can only slide. (a new design can rotate in well centre). Disadvantage ‘s of non- rotation includes: a. Poor Hole Cleaning b. Inability to slide in highly deviated wells c. Stuck pipe

Continued Floating Rigs (Non-fixed rigs) 1)Semisubmersible: large rig -Sits on steel columns (between 3 to 8) buoyancy chambers called Pontoons. -Ballast water pumped into tanks in the pontoons and columns to lower the rig in the and for stability over a well site. -Maybe be self propelled or towed to location -Limit for water depth is dependent on amount of needed riser pipe and capability of the anchoring system if the rig is anchored -It cost between $300,000 to $400,000 per day. 2)Drillship: Has a ship shaped hull

Continued -The large hole through the hull over which the derrick sits centrally on the ship is called a moonpool -Often positioned dynamically over the well rather than being anchored in place -Cost range from $230,00O per day (older ship) to over $400,000 (newer ship) 3) Drilling Tender: Has ship or barge shaped hull that contains the accommodation and all equipment except derrick, BOP, and ancillary equipment which are installed on a platform deck that is moored against a tender - Normally used for development drilling from established platforms - Cost range from $30,000 per day (Barge style tender) to $100,000 a day (modern semisubmersible tender) 4) Drilling Barge: Has a rectangular hull that floats over a well that is anchored in position. - Derrick is on a cantilever opposite the accommodation - Can drill wells up to 20,000 ft

Continued -Used in shallow waters up to 50 meter 5) Jackup: triangular shaped or square floating hull that is moved to location - Derrick is located on a moveable cantilever from the hull - Steel legs are used to anchor the rig to seabed - Cost about $50,000 to $250,000 per day 6)Platform: Fixed in position on the seabed - A large platform can drill lots of well (more than 30 wells) - A tendered platform called a tension leg platform (TLP) that floats but is tethered to the seabed with steel pipes is used in deep or very deep water. - A tendered platform saves time in being used immediately after a well is drilled and is ready to be developed. Cost effective to be removed compared to a convectional platform. It should be used in water depth greater than 10,000 ft where convectional platform cannot be reached.

Continued 7) Submersible: 2 types are a) A barge-type structure with a flat bottom that is sunk in shallow water (20 ft). Also called swamp barges. Not common and have about 12 worldwide. b) A structure similar to light built semisubmersible with columns and pontoons. - can be used in up to 130 feet of water - A jack-up can also be used in water depths operated by this submersible. NOTE : Reading Assignment on Rig systems and Equipment section.

Drill Bits Overview – the basic classification of drill bits and their major design features will be discussed. In addition the process of bit selection will be outlined. -Drill bits can be grouped into 2 major categories: Roller Cone Bits and Fixed Cutter Bits. (Show diagram) Roller Cone Bits : has one, two, or three cones with teeth. - Roller cone bits drill by crushing action on the formation - The rollers rotate on bottom and the teeth press on the formation with enough pressure that exceeds the rock compressive strength.

Continued - Can handle rougher drilling conditions -Less expensive than other bit types -Roller cone bits are available in two types: a) Steel tooth bits or Mill tooth bits with Steel teeth milled from the same block of metal as the cone. b) Roller cone bit with steel cones fitted with tungsten carbide teeth. Milled tooth bits can tolerate severe drilling condition, but wear faster compare to tungsten carbide teeth. - Tungsten carbide teeth will not tolerate shock loadings but drill for long distance before wearing out.

Continued -New technology that coats tungsten carbide teeth with a layer of diamond increases the life of the bit in aggressive formations -Outside cutters on roller cone bits are called gauge cutters Fixed Cutter Bits: The two types are diamond bits and polycrystalline diamond bits. - Fixed cutter bits drill by shearing and crushing on the formation. - No moving or rolling part -Only cutters wear out 1) Diamond bits : - Drills the hardest rock, and drill slowly. Very expensive - Used in the formation with the highest compressive strength or very abrasive formations that will destroy other bits.

Continued -The diamonds are natural industrial grade diamonds. 2) PDC bits: - Drill with a disk of diamond mounted on a tungsten carbide stud. - drill very fast (over 100 ft/hr) for long distances and the large ones can be very expensive. Two common available types of PDC bits are: a) PDC bits that are constructed from a machined steel body with tungsten carbide studs mounted on steel pegs that fit into hole machined in the body. (Steel body bits) b) PDC bits constructed from a molded tungsten carbide. (Matrix body bits)

Continued -Steel bodies are cheaper to produce than matrix bodies, but matrix bodies are harder wearing out and can be made in complex shapes more easily. -PDC and diamond bits can be made in different shapes and this shapes influence their directional tendency (made to drill easily in a directional or vertical direction) -The shape also affects the number of cutters that can be placed on the bit -Older early bits was the fishtail bits.

Continued Core Bits: Core bits cut a doughnut shaped hole that leaves a column of rock sticking up the middle of the bit. A special tube behind the bit holds this core of rock and recovers them to the surface. -They were mainly diamond bits, but now predominantly PDC designs, with natural diamond core bits applied for very hard, abrasive formations.

Optimizing Drilling Parameters As a bit drills in to the formation, the teeth will wear. Also, bearings that allow the cutting cones to turn will wear. -More weight on bit and the faster it turns, the greater the wear rate. -As a bit wears out, rate of penetration (ROP) will decrease. -ROP is the speed the bit drills( in feet/hr or meters per hour) -In general, the weight on bit (WOB) and revolutions per minute (RPM) can be increased for an increase ROP

Continued -Increasing either or both parameters also increases the bit wear rate -Important to find optimum set of drilling parameters to achieve a good ROP and a moderate wear rate Increase in WOB, results in deeper penetration of the teeth into the formation to generate large cuttings (Increase in ROP). However there is a point beyond which increasing the WOB does not result to an increase in ROP. This could be that although the teeth fully penetrated the formation, only part of the bit that did not drill was impacted the formation. Also it could be

Continued at the RPM used, the teeth did not have time to penetrate further before being pulled out as it rotated. -In this case, a constant RPM can be maintained with an increase in WOB a little at a time, while recording the ROP. Eventually, the point at which increasing the WOB does not correlate to an increase in ROP, will be noted.

Continued As the RPM increases, a tooth penetrates the formation more times in a minute. However, there is point at which an increase RPM does not increase ROP. This is because the teeth did not have time to penetrate as much as the WOB would otherwise allow. - A solution is to establish an optimum WOB, and then hold the WOB constant while increasing the RPM. Then thereafter the best combination of WOB an RPM with which to drill for the best ROP will be found.

Continued The best drilling economics is achieved by a fast ROP while not exceeding the optimum drilling parameters, so that the bit drills for longer. A drill-off test is a procedure for optimizing drilling parameters. Factors that affect ROP: 1. Effect of mud hydrostatic pressure on ROP: Normally, the hydrostatic pressure of the mud is greater than the formation pore pressure. This is to keep the well in check. - A condition called Chip hold down is as a result of this overpressure or overbalance well condition. - As a bit is used to drill and cuts rock chip, there is formation pore pressure below the bit and mud hydrostatic pressure above - This pressure differential holds the chip in place.

Continued - Therefore the chip removal from the bottom is delayed and results to a slowing down of the drilling process, when the next tooth hits the chip instead of a new rock. Note: In tricone bits, there is a strong correlation between mud overbalance and ROP. - In this case,an advantage will be an increase in ROP when the bit penetrates an area of an increasing pore pressure. - Naturally, ROP decreases with depth. An increase in ROP is an indicated that a kick may occur (if it cannot be explained by a lithology change)

Continued - PDC bits less affected by Chip Hold down -Rock bits (Tri-cone bits) used in exploratory well to help indentify pore pressure trend. (ROP will increase due to an increase in pore pressure compared to a decrease in ROP as a result of chip hold down in a zone with increasing pore pressure. Pore pressure increase is the dominant factor. 2. Effect of mud solids content on ROP: A low solids content results to a higher ROP, just like a low mud overbalance. - This is said to be due to a reduction in chip hold down effect because the mud solids slows down pressure equalization under the chip.

Continued 3) Drilling Hydraulics: It involves the use of nozzles in bits to direct the flow of drilling fluids in other to effectively clean or remove cuttings from the hole bottom and the cutting structure. - The nozzles are fitted into nozzle pockets on the bit bottom -A smaller selected nozzle diameter results in a faster mud speed for a given flow rate compared to a larger nozzle diameter. -Increase in mud speed results to more energy at the bit bottom that gives higher drilling penetration.

Continued -ROP of any bit is limited by the ability of the mud to clean the hole bottom. - ROP will increase with increasing flow-rate and mud speed at the bottom up to a point. For example in softer formations, the force can help remove rock chips (hydraulic force), but will ultimately result to an over-gauged drilled hole when rocks are eroded from gauge area of the bit.

Grading the Dull Bit -A dull bit is referred to a bit that is pulled out of hole after drilling. -A dull bit analysis (indicates features of a bit due to down-hole condition after drilling) and drilling records (surface recorded information while drilling) is called dull bit grading’s -Dull bit grading process is used to optimize bit selection for a new well at the same depth range from close previously drilled well to improve drilling performance.

Continued -An example is the identification of teeth cracks (heat checking) when bit with tungsten carbide teeth are not cooled while drilling after a run. In addition, broken teeth can be found due to high down-hole vibration, high WOB/RPM or down-hole steel junk. -A standard system of letters and numbers are used to record dull bit grading. -Eight characteristics are noted with this system: Four relates to cutting structure One relates to bearings One to the wear of the bit gauge One to any other dull features The last shows why the bit was pulled out of hole

Continued -It is important to take and keep photographs of dull bits of wells for verification purposes. Bit Selection -Good bit selection equals best drilling performance and reduction in drilling cost. -Most important source of data for analysis is the drilling records of close by wells. (Looks at other bits performance that have drilled in the same formation) in other to select a bit for a nearby new well. -Dull bit grading is also important and also the analysis of the ROP and drilling parameters (WOB, RPM and flow-rate) for each foot drilled by previous bits.

Continued -Electric logs, Sonic logs and gamma ray logs can be used to aid in bit selection. -In drilling a directional well, straight cutting tendency bits can be used in the vertical section and side cutting bit types in the directional section -In exploration wells, avoid PDC bits (less sensitive to pore pressure changes) and use tricone bits instead. -Better to use PDC Bits in smaller hole section rather than tri-cone bits.

Drillbit Economics -The rate of wear of a bit accelerates when used past its economic life. -If used past its economic life, junks of bit parts are left in hole (This will result to the recovery of this junks before drilling continues). The process is known as fishing. -The economic life of a drill bit is measured by calculating the dollars spent to drill the distance drilled with the bit. -Calculation repeated frequently as drilling continues. -The cost per foot or (cost per meter) decreases within the economic life.

Continued -When the cost per foot starts to increase, it indicates the end of the economic life of that drill bit. Cost per foot is calculated by adding together Bit cost $ plus cost of time spent drilling that bit run (dollar’s per hourly operating cost X hours) divided by the distance drilled. For example Cost per foot = Bit Cost $ + $1500(tripping hours +drilling hours) Feet Drilled - Time starts when a new bit is screwed onto the BHA, which includes time taken to run it in hole and pull out of hole.

Continued -Few conditions that will occur for a bit to be pulled (terminated) before minimum cost per foot is seen are; 1)Bit is damaged 2)Casing point is reached 3)Logging is required before the next casing point - It is a bad practice to leave a bit in hole after cost per foot starts to increase.

Drilling Fluids Drilling fluid can be defined as either liquid, Air or mist and also a combination of liquid, solids and gases that is pumped down-hole in a well -A well designed drilling fluid is essential to safe, efficient and economic drilling Functions of Drilling Fluid 1) Formation pore pressure control for proper well control 2) Minimize drilling damage to the reservoir 3) Stabilize the wellbore to keep it in gauge or Minimizes hole enlargement.

Continued 4) Remove cuttings from under the bit while drilling 5) Transport drilled cuttings to the surface while circulating 6) Release drilled solids to the surface in other to return clean mud down-hole. 7) Keep the bit cool 8) Provide lubrication to the bit and drill-string 9) Allow circulation and pipe movement without causing formation fracture 10) Absorb contaminations from down-hole formations and handle the difference between surface and down-hole temperature, without causing serious mud degradation

Continued Basic Mud Classifications -Drilling fluids can be divided into seven major classifications. -This depends on the continuous phase fluid, and the type and conditions of the major additive within the continuous phase. -The main component of a drilling fluid is the continuous phase.(Carrying phase into which everything is mixed). The following are the drilling fluid classifications types: 1) Fluids with water as the continuous phase and with clays present dispersed throughout the water(dispersed water based muds).

Continued 2)Fluids with water as the continuous phase and with clays present inhibited from dispersing throughout the water (non-dispersed water-based muds) 3)Clear fluid systems based on water with soluble salts used to control density (“solid free systems” or “brines”). Brines may include acid soluble solids that can be removed from the reservoir face by circulating acid past the reservoir. 4)Fluids with oil as the continuous phase and less than 10% water by volume (any water forms an emulsion of water within “Oil muds”) 5)Fluids with oil as the continuous phase and more than 10% water by volume (with water forming an emulsion of water within the oil (“inverted oil emulsion muds”). 6)Fluids with air as the continuous phase (“air drilling”). 7)Water based systems with air present in gaseous form within a liquid (“aerated “ and “formed” systems)

Continued Dispersed Muds: - Some clays react strongly with water (they hydrate) and will expand in the presence of water. -If water is allowed to enter the crystal structure, it causes the crystal structure to expand due to changes in electrostatic forces. -This expansion is described as Dispersion -Water molecules are polar (electrically neutral overall, but have both negative and positive charged areas in different parts of the molecules) -Polar nature of water can be increase with addition of alkalis such as, sodium or potassium hydroxide. -The more polar the water, the more reactive clays are dispersed.

Continued -Potential reactivity of a clay formation depends on the types of clay present and the physical environment (more likely to hydrate and expand than others). -One highly reactive clay mineral in the presence of water is Montmorillonite -Montmorillonite (Bentonite) can be added to mud to give it certain useful properties. -A fully dispersed clay such as montmorillonite has a large surface area that causes dispersed mud with added bentonite to become viscous. -A mud designed for the clays to be dispersed (either added like bentonite or from drilled formations) is called a dispersed mud.

Continued Nondispersed Mud: -They are muds in which the hydration and dispersion of a drilled clay is minimized. The most common way to achieve this is by limiting the amount of water that reacts with the clay, which is done by encapsulating the clay with polymer as quickly as possible to prevent further access of water to the clay. -In the past natural occurring starches where used as polymers. Now, synthetic polymers are often used in specific drilling situations. The following functions are performed by polymers: 1)Increase fluid viscosity- High viscous fluid means more pump pressure to flow fluid down-hole and vise-versa 2)Increase gelation properties – allows solids in muds and rock cuttings to be suspended longer within a gel for efficient hole cleaning.

Continued 3) Decrease fluid loss into the formation – loss of liquid or filtrate into the formation is called fluid loss. When this happen solids in the mud form a plaster or cake on the formation face. - A low fluid loss is sometimes desired in a mud 4) Act as surfactant – allows oil and water to mix together in an emulsion. Solid- Free brines or Brine system: used in the reservoir as a drilling fluid or during completion or work-over operations in other to minimize formation damage that slows hydrocarbon production. -Brines can be formulated as solids-free system with density gradients up to 1.07 psi/ft (2.47 SG) -Solids weighing material and acid soluble fluid loss additive can be added (i.e. calcium carbonate and iron carbonate - Well designed brine due not create formation damage

Continued The following are potential interactions of brines in the reservoir: 1.Scale production from the reaction of divalent brine( contain calcium or zinc salts) with dissolved CO2, which produces an insoluble carbonate. 2. Sodium chloride precipitation from formation water when exposed to some types of brine. 3.Iron compounds precipitation in the formation due to it’ interaction with soluble iron in completion fluids. 4.Reaction of formation clays with brine. 5.Corrosion of casing and tubular. Oil muds and invert emulsion muds: Oil mud contains solids and additives mixed in all-oil continuous phase. Contains little or no water (10% or less by volume liquid) Invert oil emulsion has water present at more than 10% by volume and is an emulsion within the continuous oil phase.

Continued -The water forms tiny droplets that are surrounded by oil. -The water droplets are held together with the oil phase by an emulsifier. -The presence of water phase in oil helps to control parameters such as Rheology. -Oil mud and oil based mud is the same term. Air as a circulating medium: I other to use compressed air for circulation, the following conditions must exist: 1)The formation must remain stable without hydrostatic pressure support. 2)No fluid influx danger into the wellbore (oil or salt water).

Continued - Applied in hard, dry formations (i.e. dry geothermal zones and dry gas production zones. Gas is produced when used fro drilling in gas bearing reservoir. Aerated and Foamed muds: Injection of standard drilling mud with air that lightens the fluid column. The following advantages are: 1) Maintains full circulation in loss zones 2) Increase ROP due to chip hold down reduction 3) Reduce differential sticking 4) Reduce formation damage -Generally limited to an injection depth of 2800 ft -In foam mud, the liquid is in continuous phase and contains encapsulated air bubbles within it. The percentage of liquid varies between 2% to 15 % by volume.

Continued -Lifting capacity of foam is better than that of drilling fluids. -Oil and saltwater are likely to destroy foam stability. (Not the best candidate)

Designing the Drilling Fluid -In general in designing a mud system, the overall cost of the mud system should be the lowest for drilling each hole section except for the reservoir. (This should be based on choosing between technically suitable mud systems in other to prevent hole problems) -Cost of the drilling fluid is one component of the overall cost. Requirements of a Mud System A) Mud physical properties: Density: Used to control down-hole pressure when a mud of a given density exerts a greater hydrostatic pressure on the formation more than the pore pressure (Over-balance). -Can also be Under-balanced - lower safe limit of the mud density is equal density to balance formation pore pressure plus a safety margin (small additional amount) -Upper safe limit on mud density selection can be based on the following factors:

Continued 1)Losses or formation breakdown may be induced when hydrostatic pressure plus circulating pressure losses exceed the formation pressure. This can occur with a higher mud weight than needed. 2)Higher mud density gives a reduced MAASP. (Formation strength testing at casing shoe). Kick may be more likely than with lower mud weight. 3)Rate of penetration reduction 4)Hole sticking due to higher mud density. 5)Mud solids and filtrate invasion in tiny fractures in shale can lead to unstability problems. 6)Higher mud density has higher mud solids that affect mud rheology. NOTE: The right mud density s within the range of maximum and minimum should be closer to the lower limit.

Continued Fluid Loss: Indicates how well a seal is formed by the mud against permeable formations. -Fluid loss can be tested to give filtrate measurements in 30 minutes and filter cake in 1/32 nds described as hard, soft, tough, rubbery, firm, etc. -High fluid loss builds a thicker, sticker wall cake (leads to problems like pipe sticking) rather than a thin, tough and impermeable cake. -Fluid loss test is a comparative test and does not indicate the actual filtrate lost or cake build up down- hole due to factors like actual overbalance pressure, down-hole permeability and pipe/mud flow movement that affects the cake

Continued Sand Content: Most abrasive solid present in mud. - All solids contribute to mud abrasiveness - measured by passing a fixed volume of mud through a 200 –mesh sieve in a marked container Mud Rheology: affects the relationship between fluid flow rate and the pressure required to maintain the flow-rate. (In the pipe or in the annulus) - This relationship will affect circulating pressure, surge pressure, swab pressure and hole cleaning ability. This relationship affects the circulating pressure, surge pressure and surge pressure. -Surge pressure is the extra pressure that is created in the hole when the drill-string is moved downwards in the hole and fluid is displaced upwards. -Swab pressure is the reduced pressure that is created in the hole when a drill-string is moved upwards in the hole and fluid flows downwards (pressure drop or suction is created by the withdrawal of the steel volume) -Hole cleaning- ability of the drilling fluid to lift cuttings out of the hole at a certain flow rate. This ability is related to fluid density and rheology.

Continued -Rheology also affects flow regimes changes because it affects the flow rates that induce the regime changes. -At very low flow-rates, all parts of fluid flow in the pipe or annulus will move in the same direction and at roughly the same speed. This is referred to as Plug Flow. -As the flow is increased, the middle part of the fluid flows faster than the fluids at wall or edges. This is referred to as Laminar Flow. Less efficient for hole cleaning. -Further increase in the flow-rate, results to chaotic fluid flow with numerous eddies and swirling flow and an average flow in one direction. Most efficient for hole cleaning. -Transitional flow is fluid flow behavior that is between laminar flow and turbulent flow. A cross fluid flow from laminar flow regime to turbulent flow regime.

Continued B) Mud Chemical Properties: Mud chemical properties is defined by well bore stability considerations of drilled formations per hole section. - mud should not damage(reduce permeability) in a reservoir Different hole problems and the required chemical: 1) Reactive shale: - a result of the incompatibility between water and shale that causes many hole problems - solved by using oil/water emulsion muds (oil in the continuous phase) or 100 % oil muds. Helps to isolate water from shale's and so prevents hydration. Environmental concerns and high cost of oil based mud is a limiting factor - Water cased mud with potassium chloride (KCL) can be used to control reactive shale - Polymer’s can be used to control reactive shale - New development is the use of soluble silicates in clay stabilization 2) Salts: - Non-salt saturated water based mud that is used in a salt formation, will leach out salt formation and cause extreme hole enlargement and possible cementing problems. - Use of salt saturated water mud or oil based mud can prevent this problem. - A mixed salt system is best to use in complex mixed salt sequence of potassium and magnesium that is present in a formation

Continued 3) Reservoir damage: - Damage of formation fluids due to mud filtrate - The two areas of particular concern are: Pollution of water sources and reduced permeability. - The two ways that can be used to prevent formation fluids, which can be separately or together are: using additives to plug off pore throats where the formation is exposed in other to prevent filtrate invasion and using a mud with non-damaging filtrate. Productivity damage from filtrate in the pay zone may occur in the following ways: a. Filtrate may have fines (small solid particles) that bridge the zone of invasion. Deep zones may affect perforations that will cause the well to be less productive. - acid soluble fines can be dissolved with acid treatment. But, weighting agents or drilled solids are not acid soluble. b. Chemical reaction between filtrate and formation fluids may produce solid precipitates or blocking emulsion.

Continued c. Filtrate may react with clays in the formation. Low amount of oil filtrate in oil based mud compared to using water based mud. 4) Corrosion of down-hole steel components: - Drilling, casing and completion tools and tubulars can be subject to corrosion by mud. - mud left in the annulus after casing is cement if it contains organic additives can produce H 2 S or low ph levels with time. - oil based mud left down-hole with time will help prevent corrosion of tubulars. 5) Hydrogen sulfide-related problems: - may enter the mud in a permeable formation as a kick or from within the drilled cuttings - it is very toxic and can cause hydrogen embrittlement of most steels, which degrades tensile strength. - If H 2 S is anticipated in a mud system, excess lime can be added in the mud to neutralize the H 2 S. - When H 2 S is identified in a mud system, Zinc oxide can be added to the mud. (It is recommended to add around 2 Ibs for each barrel of mud)

Directional and Horizontal Drilling Directional drilling is a process of accurately guiding a well through a predefined target or targets. Overview- The reasons for drilling directional well and how the well path is designed will be covered. The tools and techniques for wellbore deviation will be described. Problems that can be associated with such wells; and specifics concerning drilling horizontal and multi-lateral wells will be discussed. Reasons for drilling directional wells - Single surface location for multiple wells: 2 or more wells from different parts of a reservoir at a single surface location flow to the same production facilities. Reduced production cost.

Continued -Salt dome drilling: used to drill around a salt dome reservoir in other to drain trapped hydrocarbons. -Multiple exploration wells from a single wellbore: used to drill more than one exploration well path for more reservoir evaluation from a single wellbore. - Onshore drilling to an offshore reservoir: used to target offshore reservoirs from onshore locations. Can save cost and also can be due to environmental concerns.

Continued - Optimum orientation in the reservoir: helps to get into the best position (permeability direction ) in a reservoir for optimum production. -Remedial work (sidetracks): used to drill directional a new well-path (Deviate) from an original wellbore for a new objective. -Relief wells: Used to intercept a blowout well in other to stop hydrocarbon flow to the surface from the blowout well.

Continued Directional Well Planning This involves the drilling engineer designing a well path to meet target requirements at the lowest cost. -The wellbore placement for the target reservoir is defined by the geologist and the reservoir engineer. - Reservoirs can be drilled as a single (with a tolerance distance) target, multiple targets or along cap rock (top) to target.

Continued Below is an example of a planned well profile (a simple directional profile)

Continued From this well profile, there are 2 targets to hit (rectangles and lines on the side); top target hits at it’s edge closet to the surface location when compared to the bottom target. -A J-shaped profile which is a “Build and Hold to target” profile is the simplest (cheapest) directional profile. -A target is an area not a point -Cost more to hits a small target than a large target

Continued Advantages of planning hit the edge of a target compared to planning to hit center: 1.Well can be built to a lower inclination (less hole to drill) 2.Less Chance to miss the target (but results in reduced ROP with low inclination) compared to increased ROP with high inclination) - Other consideration in well planning is to identify areas of drill pipe that will have then tendency for increased tension due to more contact on a curved well path that will result to problems such as metal fatigue, pipe wear or can cause stuck pipe

Continued -Dogleg severity: defined as a rate of change in direction, measured in degrees per 100 ft or 30 m of drilled hole. -It is a descriptive expression of a bent hole. -Avoid a high dogleg severity shallow or upper portion of a well path in other to reduce high forces between the pipe and the hole wall. - Vertical wells are not truly vertical (Have slight spiral). This is because bits can experience side forces when penetrating wells with: 1. Rock bedding planes that are at angles other than 90 degrees. 2. Harder rock lump within softer rock. - Directional drilling method (i.e. Mud motor, rotary steerable system e.tc) can still be used in drilling a vertical well.

Continued Deviating the Wellbore This is achieved when a side force is developed at the bit in other to make a well deviate from vertical. - The amount of side-force and direction, formation hardness, bed plane angles are examples of factors that can influence wellbore deviation. Two techniques used to develop a side force in the early days of rotary drilling are Jetting and Whip-stock (Still used today in some cases): use demo diags  Jetting: involves the use of a bit (preferably a roller cone) with one large nozzle and two smaller nozzles. Drilling fluid flows out of the nozzles with a great force to help erode the rock away. -Most of the drilling mud flow goes through the large nozzle towards on side of the hole. A pocket is washed in that direction when the bit is aligned in the desired direction and the pumps are increased (Increase in flow) without rotation to cause the well to deviate.

Continued - After about 5 or 6 ft is washed, the bit is rotated and drilled conventionally -This is repeated until about 12 degrees of build angle or the rock is too firm to jet -A rotary build assembly is then used to continue once the some angle is achieved.  Whipstock: it is wedge which is set in the hole to kick- off a new wellbore from the original hole. After drilling below the whipstock, the drilling assembly with bit and the whipstock is pulled out of hole. The whipstock is removed and a drilling assembly is used to continue drilling. - Whipstocks can also be used to deviate a well out from the side of a casing. A mill instead of a bit is used to cut the casing. The whipstock is left in the hole in this application.

Continued Other techniques that are used to develop a side force are:  Steerable motor: a down-hole motor with the lower part having an adjustable bend. -Power to the motor is achieved by pumping mud through it (Hydraulic energy input). - Before the motor is ran in hole, the following things is done: The motor bend is adjusted based on the directional objective and other BHA tools (i.e. mwd,stabilizer e.tc) are connected to the motor to achieve the required directional performance.

Continued An example of the main components of this system are: (Demo with Diagram) 1)Drill bits – used to create a side force for deviation (curved hole) when mud is pumped down the drill- string to turn the motor. 2)Undergauge stabilizer- (normally smaller than the hole size) used as a fulcrum point behind the bit with the motor acting as a lever to generate side force at the bit. 3)Motor- contains part of the motor with rotor/shaft and the bottom part has the adjustable shaft. 4)Dump valve- at the top of the motor and it allows mud diversion at the motor top, if needed. 5)Stabilizer- Used above the motor at the far end of the lever to exert an opposite force at the bit.

Continued -Steerable motors can be used to turn, drop and build angle or some combination of build/drop and turn. - The whole drill-string can also be rotated to drill a straight hole. -One limitation of using steerable tools is that sliding (non-rotating) to build angles leads to cuttings accumulations that cause hole problems such as stuck pipe compared to while rotating which improves cuttings transportation. -We have rotary steerable tools now to help with this limitation. (can be expensive)

Continued  Rotary drilling assemblies: it involves the support of the drill collar with a stabilizer at one end or both ends that causes the middle of the drill collar to sag due to its weight and this creates a side force at the bit to build or drop angle. - The positions and size of the stabilizers (full gauge or under-gauge) determines the drop angle (bit is pushed into the low side of the hole) or build angle (bit is pushed up to the high-side) or no angle change (very little/no side force). For a rotary build assembly, the hole needs to be at about over 12 degrees to create a sag with the drill collar. The higher the inclination, the more the side force. (Use diag.) A NB (near bit) stabilizer that is under-gauge with a top stabilizer that is full gauge will result to a less upward side force (low build angle) compared to a near bit stabilizer and a top stabilizer that are both under-gauge (Increase build). (i.e. 60’, 90’ build assembly)

Continued -The weight applied on the bit (WOB) also has the effect on the build angle, drop angle or no angle change in a wellbore. (Drill collar sag increase with more applied WOB on top the drill collar and vise-versa) No NB stabilizer is used in other to drop angle. Normally about 60 ft or 90 ft of drill collar between the bit and first stabilizer. (sag minus NB stabilizer results to less side force on the bit to drop angle). (use diag.) Light WOB is required to start the drop and then the WOB is increased. Azimuth is difficult to maintain in drop assembly. -A drop assembly is also known as a pendulum assembly. -Drill bit type also has an effect on build angle, drop angle or no angle change in a wellbore. Drill bits with side cutting actions will be more effective in a drop or build assembly compared with a bit with no side cutting which will tend to drill straight. (i.e. 60’,90’ drop assembly).

Continued A tangent assembly (locked assembly) is used to drill straight. (if the desired direction and angle is confirmed) - Also referred to as a packed assembly (packed with stabilizers) and also a stiff assembly (stiff and resists bending forces). - Mostly full gauge stabilizers -Natural formation trends or drilling parameters (WOB) rarely affects the directional performance (objective) of this assembly type. - High WOB is not a limitation using this assembly and can be used to drill faster. -Can also tend to build slightly with increased WOB - A locked assembly can be run with a slight under-gauged second stabilizer for an increased build tendency.

Continued  Rotary Steerable: A tool that is ran above the bit with blades that move in and out. - As the tool turns, the blade can be controlled to push on the side of the hole opposite the desired direction of the deviation and side force is imposed on the bit to make it drill a curve. -One big advantage of the rotary steerable tool is that it creates a nice smooth curved hole when compared to steerable motors. -Leads to more stable wellbore and less resistance while tripping in and out. -Easier to run casing and logging tools in a smooth wellbore at higher inclination.

Continued -Used to break friction (less drag) in long horizontal wells compared with sliding with steerable motor. -Helps effective hole cleaning in horizontal holes by releasing the cuttings in the annulus compared to cutting build up while sliding with a steerable motor. -More expensive than steerable motor.

Navigating to the Target The two factors needed to navigate while drilling are: Measurements must be taken and calculations made to get the desired position of the wellbore. Wellbore position surveying tools: - All measure the same parameters but use different equipments - The two information that are measured by the tool are 1) Inclination: angle between the center line of the wellbore and vertical and 2) Azimuth: the Direction - Magnetic compass tools measures azimuth that is converted from magnetic north to grid north. - Gyro tools measure relative to geographic north (axis of the earth rotation)

Continued -A survey point from a tool indicates the measured depth, Inclination and the azimuth. A continuous survey points is used in calculations generate a wellpath. -The following tools can be used to produce one or more surveys: 1.Magnetic single shot survey- a slim, stainless-steel barrel of around 1 ½” diameter that contains a magnetic compass unit, an inclinometer, and a camera controlled by a timer. - ran in hole with a drill-string or wire-line. - a timer used to give enough time for tool to be ran in hole and the camera used to take a photograph of the compass, which has a marker showing the inclination. -Modern units also take measurements but dispense with the camera and film - a less common unit has a motion sensor that takes a survey two minutes after no motion is sensed.

Continued 2. Magnetic multi-shot survey: the tool records a series of surveys as it is pulled out of hole. Surveys can be recorded or transmitted real-time to the surface. 3. Gyro multi-shot surveys: ran on wire-line that transmit information to the surface. Takes many surveys at short intervals for known depth at the surface computer. - More accurate with reading azimuth than magnetic tools 4. Measurement while drilling: a tool that measures azimuth with a magnetic device and inclination with an Inclinometer. These and the survey at a known depth are transmitted to the surface.

Continued Wellbore surveying calculations: - Several surveys (Inclination and Azimuth) of the well are taken at known measured depths. -This are inputted into a calculation that shows the well path. -The vertical depth and N/S – E/W for each survey point are calculated. - The minimum curvature method is one the common calculation methods that are use. (show arc diag) The survey calculation that shows the well-path can be illustrated as follows:

Continued Surface locations are: (Use diagram) Zero displacement (east/west) Zero displacement (north/south) MD = 0, Inclination = 0, Azimuth = 0 and TVD = 0 The above can be referred to as survey number 0. Survey #1 is: MD = 250 ft, Inc = 0 degree, Azimuth = 0 degree, TVD = 250 ft, E/W= 0 ft and N/S = 0 ft Survey #2 is: MD = 500 ft, Inc = 3 degrees, Azimuth = 0 degrees, E/W = 0 ft and N/S = 6.54 ft Survey #3 is: MD = 750 ft, Inc = 5 degrees, Azimuth = 20 degrees, TVD = 749.28 ft, E/W = 3.73 ft and N/S = 23.33 ft…and so on - An assumption in this survey is that the well follows a perfect curve. (Not true and causes error between survey points)

Continued -Cone of uncertainty: results as survey errors created in a cone shaped well-path. -Can cause well collision between two or more close wells The following ways are used to reduce such errors: 1.Take more surveys 2.Use gyro tools for azimuth measurement instead of magnetic based tools….more frequent surveys with gyro and no azimuth correction compared to MWD tools when used in casing. - Sag correction is applied to correct inclination error as a results of a BHA sag on the low side of a hole.

Continued Multiple Wells from a Single -more than one well is drilled from a single surface location -Collision risk increases -Spider plot used to visualize the wells. Multilateral Wells -More than one side wellbore can be drilled from a single wellbore (mother bore). Use diag -More hydrocarbon production from this wells. (lower reservoir pressure for increased drainage)

Continued Geo-steering - It involves the use of LWD tools to steer into a small reservoir or away from the top of a reservoir into a target. - LWD/Rotary steerable tool can also be used together.

Directional Drilling Problems  Hole Cleaning: ability of the mud to lift the drilling cuttings to the surface - Vertical wells more easy to lift cuttings - As hole angle increase and at a higher angle above about 45 degrees, cuttings removal starts to get hard due to cuttings pile up on the low side of the wellbore - Rotating better than sliding for cuttings removal  Stuck Pipe: occurs due to solid build up in the well that is not effectively cleaned out. - Cannot pump in the well to clear up the hole

Continued  Wellbore Stability: -Stable hole is uniform (same as bit size) throughout. -Unstable hole is not uniform (variation in size other than the bit size) in all or some parts of the well. -The difference between maximum and vertical stresses increases as you drill from vertical to horizontal  More likely for wellbore collapse in horizontal wells if not designed properly.  Logging: - As hole angle increases above about 50 degrees, wireline logging becomes hard. - Also harder for a rough wellbore compared to a smooth wellbore.

CASING AND CEMENTING Casing is lowered into the drilled hole and cement is placed between the casing and the drilled hole. Cement is used for the following reasons: 1)Used to prevent formation fluid from moving up the annulus outside the casing. 2)Seal zones that will allow mud into the formation 3)Seal zones with very soft formation to prevent hole collapse 4)Seal zones that will allow formation fluid into the wellbore 5)Used for well abandonment to prevent unwanted formation fluid to escape to the surface. 6)Used to seal of the lower part of the well to allow a new hole to be drilled away from the old wellbore.

Continued Types of Casing: Conductor casing: -First casing that is set (shallow depth) -Maybe driven into the ground or cemented inside a drilled hole. The purpose of a conductor are: 1.Conduct drilling fluid returns back up the rig during surface drilling in other to establish a closed circulation system. 2.Protect unconsolidated surface formations from washout. 3. Sometimes to support the weight of the wellhead and BOP’s.

Continued Surface Casing: -First casing set deeper for formations at the shoe to withstand pressure from a kicking formation lower down. The purpose of a surface casing are: 1.Allow connection to a BOP so the well can be drilled deeper. 2.Protect freshwater zones from drilling fluid pollution. 3.Isolate loose or weak formation from entering the wellbore to cause hole issues. Intermediate Casing: - May not be needed by a shallow well compared to its use in a deep well. - Serves as a staging post between the surface casing and the production casing.

Continued The purpose of an intermediate casing are: 1.Allow for increase well pressure integrity with depth. 2.Protect any directional work done after kicking off by placing the casing in hole. 3.Help consolidate the upper section that is already drilled. - Intermediate casings are usually between 20” and 13 3/8” outside diameter. Production Casing: - Placed across the reservoir and houses the completion tubing. - Hydrocarbon flows through the tubing and also can flow through the production casing if there is tubing leak. - Can be placed and cemented in place above the reservoir and a new hole is drilled across the reservoir. A liner is then placed across the reservoir from the end of the production casing (not from the surface).

Continued Advantages of a Liner are: 1.Economics: less cost compared to full length of casing, 2.Utility: ID of liner is less than ID of production casing. This allows completion tools to be ran to sit above the liner. Disadvantages of a Liner are: 1.Complexity: equipment used to run liners are more complex than for casing. (high chance for mistake) 2.Cement job quality: small cement volumes around liner requires precise and good cement quality without drilling fluid contamination. 3.Perforation is achieved with an explosive gun that penetrates the casing or liner into the formation for hydrocarbon flow.

Designing the Casing String To design a sets of casing for a well, the force that will be subjected on the casing and the chemical environment around the casing throughout the life of the casing are important factors for consideration. The following are casing design considerations: 1)Tension: -Each casing piece is in tension from the weight below. - Tension increases from bottom to the top - Casing, tubing and drill-pipe are specified as wt/ft and grade - Buoyancy helps to reduce down-hole casing wt from air weight - additional forces are imposed on casing in a deviated well. - Maximum tension on casing must be less than thee tensile strength of the casing. - Tensile force is also applied on the casing during testing after cementing. (force that try’s to pull it apart)

Continued 2) Burst: -Casing must be able to withstand internal pressure. -Internal pressure will come from down-hole formation pressure, hydrostatic pressure and pressure test. 3) Collapse: - Opposite of burst pressure. - Pressure outside the casing is higher than the pressure from fluids inside the casing. -Possible fro casing to be squashed by external pressure. -Cemented casing much harder to collapse than uncemented casing.

Continued -Salt can impose very high collapse pressure on a casing string. -Two factors that can used in flowing salt are: using very strong casing and the formation of a complete cement sheath around the casing. 4) Driving force: - used in conductor casing to drive the casing into the ground. -Pipe must have strong to withstand the heavy shock loads. 5) Temperature: - Casing expands at high temperature and losses its strength. -At about 200 degrees C, steel losses about 19% of it’s strength. -Must be accounted fro in casing design for high temperature wells.

Continued 6) Combined axial and internal forces: - results from opposite effects o casing when undergoing tension and compression forces. -Casing design accounts for deceased collapse pressure resistance due to tension and not the increased burst strength due to tension (making safety margin higher). 7) Corrosion: -Presence of H 2 S, CO 2 and water can corrode casing steel - Worst with high temperature. Corrosion rate doubles at every 32 Degrees increase in temperature. -Special steels with nickel or chromium can be used. -H 2 S will result in the hydrogen casing hydrogen embrittlement in steel casing that will cause the casing to fail at a reduced load. -Higher steel strength and lower temperature increases the failure.

Continued 8) Connections: - 90 % of failures in casing occur at the connections. - High tension, bending forces and internal forces places great strength requirements on the connection threads. Role of the Cement outside Casing Cement around casing is designed to meet the following needs: 1.Physically support the casing weight 2.Prevent upward fluid migration inside the casing or between casing/formation or casing/cement. 3.Protect the casing against corrosion. 4.Protect the casing against mobile formation. 5.Allow for production casing perforation without shattering the cement.

Continued Mud Removal -Easier to remove drilling fluids and replace it with cement in an in-gauge hole with centralized casing compared to an over-gauge hole with the casing not well centralized. The following actions can be taken to maximize full mud removal: 1.Drill a stable in gauge hole 2.Use a thin mud (not viscous) just before running casing. 3.Move casing while pumping cement around. 4.Pump thin (low viscosity) spacers ahead of cement. 5.Use casing centralizers to keep the casing straight. - Centralizers are tool placed on the outside of casing to help keep the casing in the middle of the hole.

Continued Cement -American petroleum institute (API) established standard specifications for oil well cements. -API defined and classified eight different cements. based on the depths and temperature at which they can be used. -The cement classes are designated A through B. -Cement specifications state the chemical and physical attributes of the cement. -Class G cement is the most useful when the properties are chemically modified during mixing, it is universally available around the world and the vast amount of experience using it. -Neat cement is defined as the point when a correct amount of water is used to make a pumpable slurry without free water. -API class G cement, the water requirement is 4.96 US gallons for each 94 Ibs sack and a resulting slurry weights 15.8 Ibs per gal. -Free water for normal slurries should not be more than 0.5 % of slurry volume. -0 % free water for a slurry is designed for high angle or horizontal wells.

Continued Cement Design The following are cement design considerations: Density: -It is the most important cement slurry property. -Casings are normally cemented with two different slurry densities…a light “lead slurry” and a neat “tail” slurry. This is done for two reasons: 1) Hydrostatic pressure- prevent formation breakdown with a long column of neat cement slurry. 2) Cost – light cement slurry is cheaper.

Continued -Free water (excess water) that is left in slurry after it sets must be minimized because it can form channels through the cement that will later on allow fluids to flow. (e.g. Class G cement needs 22% of water by weight of cement (BWOC)to hydrate the cement, but it is not a pumpable slurry. An additional 22% of water is needed to make the slurry pumpable. This makes a total of 44% BWOC. Anything above the 44% BWOC that is left is referred to as free water -Lighter cement is called extended cement (addition of more water) -Clay is added to soak up free water(excess water). A sufficient quantity of clay is used. The clay used to soak up excess water is called Bentonite. -Clay used to lighten a slurry is called an extender.

Continued - Standard cement design table gives the quantities of cement, water and bentonite needed to mix a slurry of various densities. - For example to mix one (US) gallon of slurry using API class G cement. The following mix is required at different weights. As shown on the table below:

Continued Other materials that can be used as extenders (can be added to neat cement): 1.Hollow glass 2.Ceramic microsphere 3.Powered coal 4.Crushed volcanic glass 5.Mixing nitrogen to cement (Foam) Materials that can be used to mix up heavy slurries denser than neat cement: 1.Barite 2.Hermatite -Lower limit of cement slurry density is dictated to maintain overbalance hydrostatic pressure on pore fluid pressure while pumping cement around and in place. -Upper limit is dictated by the down-hole formation strengths.

Continued Thickening Time: -Thickening time and compressive strength is dependent on well temperature. -Higher temperature equals to faster setting and strength buildup. -Slurry must have sufficient pumpable time and thickening time to avoid rig time lost. -Accelerators or retarders (Chemical additives) used to lessen or lengthen the pumping time. Note- This will affect the rate of compressive buildup Compressive Strength: - Cement is designed to have a good compressive strength A good cement compressive strength to support the casing is considered to be 500 psi.2000 psi Is considered the minimum for cement that will be perforated. Temperature Rating: -Circulating and static temperature with depth are important for cementing operations.

Continued -Temperature log run on wireline measures bottom hole static pressure (BHST) when not circulating. -Bottom hole circulating temperature (BHCT) can be calculated by reference to API specification 10 which contains temperature tables. -LWD tools can also measure circulating bottom hole circulating temperature. -BSHT is used to investigate cement stability and compressive strength development with time. -BCHT is used when circulating pumpable time -As Rule of thumb, the static temperature at the depth of top of cement should be less than the BHCT used in slurry design. -If it is significantly less, it will take longer to cure. -For deep, hot wells (BSHT should be less than 110 deg. C)

Continued Rheology: -Cement slurry rheology is important for the following reason: 1.It affects downhole pressures while pumping cement around the casing and annulus. 2.It affects mud displacement, mixability, pumpability and free fall of the slurry down the casing. -Free fall occurs when total hydrostatic pressure inside the casing when cement slurry is pumped is greater due to the higher slurry density than the fluid in the annulus; this causes the cement to fall faster than the pumps can fill the casing behind when the pump is stopped. This will cause a partial vacuum inside the casing. -Cement slurry depends on the following: 1. Ratio of solids to water 2. Sizes and shapes of the solids in the slurry. 3. Energy used to mix the slurry 4. Flow Regime 5. Time for chemical reaction 6. Temperature and pressure effect on slurry in the well with depth.

Continued Chemical additives: Other additives that can be added to modify cement are: 1. Deformers - prevents slurry from forming while mixing. 2. Dispersants- helps to distribute solids present in the slurry. 3. Fluid loss – control loss of filtrate into the permeable formations. 4. Lost circulation material – inert solids materials to plug off pore spaces at the formation face to prevent loss of slurry into the formation. Cementing casing in massive salt formations: Inadequate cement can lead to the following failure modes. 1.Casing collapse due to point loading on casing by uneven salt closure ( Salt Creep). 2.Casing collapse due to horizontal overburden pressure by mobile salt. 3.Casing shearing due to directional salt flow. 4.Casing corrosion in the presence of magnesium salt. 5.Long term cement degradation of cement sheath due to ion diffusion by salt leading to casing collapse.

Continued The following can be specified in the drilling program to maximize the chance of good cement throughout a salt interval. 1.Use salt saturated salt. 2.Use a saturated Kcl slurry. 3. Be aware of potential problems with other formations with salt saturated slurries. 4. Use fast setting cement time. 5. Use suitable drilling fluids to minimize leaching out of the salt. 6. Increase mud densities to reduce salt creep rate.

Running and Cementing Casing -Casing usually around 40 ft length. -A float shoe at the casing bottom it allow fluid to be pumped down through it and does not allow fluid to flow in the opposite direction. -Cement does not enter inside the casing from the annulus with the float shoe. -First, two joints of casing are run above the float shoe and another float valve called a float collar (back-up float valve) is made up, and then other joints of casing are screwed on top of each other while running in hole. -Two types of cementing techniques are: Plug cementing and stinger cementing. -Plug cementing involves using a top and bottom plug on the top of the casing and then a known volume of cement that is calculated in advance is pumped inside the casing.

Continued Cementing Surface Casing -Large casing do not use the cement plug system. This is due to any sudden enlargement of the surface hole and the cement volume required is not known in advance. -Normally cemented all the way up to the surface or seabed. -A technique called stinger cementing is used by pumping cement until cement returns are seen back on the surface and then mud can be pumped behind.

Continued Cement Evaluation behind the Casing -A basic cement evaluation log will give an indication of the cement bonds only. -More sophisticated tools can detect the presence of 1.Microannulus 2.Channels in the cement 3.Gas bubbles in cement and much more. Other cement jobs are: Secondary cementing: it involves repairing a bad primary cement job. (Work-over jobs) -Secondary cementing may have a low success rate. Curing lost circulation: Cement can be used to cure serious loss circulation problems. Cement plugs: -Column of cement that is set at some point in the well and some uses are: 1.Well Abandonment 2.Suspend a well (Temporary abandonment) 3.Side track a well - Cement plugs are set by running tubing and pumping the cement through the tubing into the well. - The tubing is then removed and a column of cement is left in place.

Petro Data Mgt II- Drilling and Production Petroleum Professor Collins Nwaneri.

Similar presentations

Presentation on theme: "Petro Data Mgt II- Drilling and Production Petroleum Professor Collins Nwaneri."— Presentation transcript:

Similar presentations

About project

Feedback

Log in

Auth with social network:

Petro Data Mgt II- Drilling and Production Petroleum Professor Collins Nwaneri.

Similar presentations

Presentation on theme: "Petro Data Mgt II- Drilling and Production Petroleum Professor Collins Nwaneri."— Presentation transcript:

Similar presentations

About project

Feedback