Drilling Engineering(钻井工程英文课件).ppt

Drilling EngineeringContents nOverviewnRig componentsnDrillstringnDrillbitsnFormation pressuresnWell control1nCasingnCementnDrilling fluidsnHydraulicsnDirectional drillingnDirectional SurveyingnMeasurement while drillingnSubsea2Chap.1 Overview1.Introduction2.Drilling Personnel3.Rotary drilling equipment4.The drilling process5.Offshore drilling 6.Drilling economics3Chap.1 Overview1.1 Exploration and production licencesnIn UK, the secretary of State for Energy is empowered(授权授权), on behalf of the Government, to invite companies to apply for exploration and production licences on the United Kingdom Continental Shelf. nExploration licences may be awarded at any time.(mainly allow to acquire seismic data, not to drill any deeper than 350 meters.)1. Introduction4nProduction licences are awarded at specific discrete intervals known as licencing Rounds.1.2 Exploration, Development and AbandonmentüBefore drilling an exploration well, company have to obtain a production licence.üThe licence allow the company to drill exploration wells in the area of interest.Chap.1 Overview5The objectives of exploration wellnTo determine the presence of hydrocarbonsnTo provide geological data(core, logs) for evaluation.nTo flow test the well to determine its production potential, and obtain fluid sample. Chap.1 Overview6The phases in the life of oil fieldnExploration nAppraisalnDevelopmentnMaintenancenAbandonmentChap.1 Overview7Role of Drilling Chap.1 Overview82. Drilling personnelnDrilling a well requires many different skills and involves many companies.nOperator ：：The oil company who manages the drilling and /or production operations.nIn joint ventures one company acts as operator on behalf of the other partners.nThe oil company will employ a drilling contractor to drill the well.Chap.1 Overview9Contracting strategies Day-rate contract(日费制日费制)nThe most common type of drilling contract is a day-rate contract. nThe operator prepares a detailed well design and program of work for the drilling operationnDrilling contractor simply provides the drilling rig and personnel to drill the well. nThe contractor is paid a fixed sum of money for every day that he spends drilling the well. nAll consumable items(e.g. drilling bits, cement), transport and support services are provided by the operator.Chap.1 Overview10Turnkey contract(大包)nThe drilling contractor designs the well, contracts the transport and support services and purchases all of the consumables, and charges the oil company a fixed sum of money for whole operation.nThe role of operator is to specify the drilling targets, the evaluation procedures and to establish the quality controls on the final well. Chap.1 Overview11nThe operator will generally have a representative on the rig ( sometimes called the “company man〞) to ensure drilling operations go ahead as planned, make decisions affecting progress of the well, and organise supplies of equipment. He will be in daily contact with his drilling superintendent〔主管〕 who will be based in the head office of the operator. nThere may also be an oil company drilling engineer and/or a geologist on the rig. Chap.1 Overview12nThe drilling contractor will employ a tool-pusher 〔钻井主管 also called superintendent〕to be in overall charge of the rig. He is responsible for all rig floor activities and liaises〔保持联系〕 with the company man to ensure progress is satisfactory.nThe manual activities associated with drilling the well are conducted by the drilling crew.nSince drilling continues 24 hours a day, there are usually 2 drilling crews. Each crew works under the direction of the driller(司钻).Drilling activityChap.1 Overview13•The crew will generally consist of a derrickman (井架工 who also tends the pumps while drilling), 3 roughnecks (钻台工 working on rig floor), plus a mechanic〔机修工〕, an electrician〔电工〕, a crane operator and roustabouts (杂工 general labourers)•Service company personnel are transported to the rig and when required. Sometimes they are on the rig for the entire well (e.g. mud engineer) or only for a few days during particular operations (e.g. directional drilling engineer).Chap.1 Overview14Personnel in Drilling a Well153. Drilling proposal and drilling programThe proposal for drilling the well is prepared by the geologists and reservoir engineers in the operating company and provides the information upon which the well will be designed and the drilling program will be prepared. Drilling proposal:• Objective of the well• Depth (m/ft, subsea) , and location (longitude and Latitude) of target• Geological cross section• Pore pressure profile prediction 16•Drilling rig to be used for the well•Proposed location for the drilling rig•Holes sizes and depths•Casing sizes and depths•Drilling fluid specification•Directional drilling information•Well control equipment and procedures•Bits and hydraulics programDrilling program:174. Rotary DrillingEquipment185. Drilling ProcessFig. 4 Typical well in North Sea19Installing the 30 in Conductor1.The first stage is to drive a large diameter pipe to a depth of approximately 100 ft below ground level using a truck mounted pile-driver.2.This pipe, usually called casing/conductor, is installed to prevent the unconsalidated surface formations from collapsing whist drilling deeper.3.Once this conductor is in place the full sized rig is brought onto the site and set up over the conductor, and preparations are made for the next stage of the operation.Overview of the process of drilling20Drilling and casing the 26’ holeA 26〞〞 diameter bit is generally used for the first hole section(the I.D. of conductor is approximately 28〞〞).This section may be approximately 2000’.Whist drilling the 26’ hole, drilling fluid is circulated down the drllpipe, across the face of the drillbit, and up the annulus between the drillpipe and the borehole, carrying the drilled cuttings from the face of the bit to surface. 214.At surface the cuttings are removed from the mud ( to collect more cuttings).5.When the drillbit reaches approximately 2000’ the drillstring is pulled out of the hole and another string of pipe (surface casing) is run into the hole. This casing, which generally 20〞 O.D., is delivered to the rig in 40ft lengths. The casing is lowered into the hole, joint by joint, until it reaches the bottom of the hole. Cement slurry is then pumped into the annular space between the casing and the borehole. 22Drilling and Casing the 17 ½〞〞 HoleOnce the cement has set hard, a large spool called a wellhead hausing( 套管头套管头) is attached to the top of the 20〞〞 casing.This wellhead housing is used to support the weight of subsequent casing strings and the blowout prevention stack.BOP generally fitted to the wellhead before the 17 ½〞〞 hole section is started.234.When the BOP’s have been installed and pressure tested, a 17 ½〞 hole is drilled down to 6000ft. Once this depth has been reached the troublesome formations in the 17 ½〞 hole section, a casing string is used to isolate these formations.5.When the cement has set hard, the BOP stack is removed and a wellhead spool is mounted on top of the wellhead housing.24Drilling and Casing 12 ¼〞〞 HoleWhen the BOP has been re-installed and pressure tested, a 12 ¼〞〞 hole is drilled through the oil bearing reservoir. Whilst drilling through this formation oil will be visible on the cuttings being brought to surface by the drilling fluid.If gas is present in the formation it will also be brought to surface by the drilling fluid and deteced by gas detectors placed above the mud flowline connected to top of the BOP stack.25Petrophysical logsThe drill string is pulled out and a logging tools is pulled in to measure formation characteristics. the electrical resistance;the bulk density;the natural radioactive emissions from the rock.These tools are run on conductive cable called electric wireline, so that the measurements can be transmitted and plotted almost immediately at surface.these plots are called petrophysical logs and the tools are therefore call wireline logging tools.26CoringIn some cases, it may be desireable to retrieve a large cylindrical sample of the rock known as a core.A donut shaped bit is attached a special large diameter pipe known as a core barrel is run in hole on the drillpipe.This coring assembly allows the core to be cut from the rock and retrieved. 27Completion the wellto run and cement production casing across the oil producing zone.then to run the tubing inside this casing string. The annulus between the production casing and the production tubing is sealed off by a device known as packer(on the bottom of the tubing ). The BOP’s are then removed and a set of valves is installed on top of the wellhead.The Xmas tress is used to control the flow of oil once it reaches the surface.28To initiate production, the production casing is “perforated〞 by explosive charges run down the tubing on wireline and positioned adjacent to the pay zone. Hole are then shot through the casing and cement into the formation. The hydrocarbons flow into the wellbore and up the tubing to the surface.29306 OFFSHORE DRILLINGAbout 25% of the world’s oil and gas is being produced from offshore fields.In the north Sea, exploration wells are drilled from a jack-up or a semi-submersible drilling rig. A jack-up(自升式钻井船) has retractable legs which can be lowered down to the seabed. The legs support the drilling rig and keep the rig in position. Such rigs are generally designed for water depth up to 350 ft water depth.A semi-submersible rig (半潜式钻井船)is not bottom supported but is designed to float. Semi-submersibles can operate in water depths of up to 3500ft. 31In very deep waters (up to 7500 ft), drillships are used to drill a well. Since the position of floating drilling rigs is constantly changing relative to the seabed special equipment must be used to connect the rig to the seabed and to allow drilling to proceed. If the exploration wells are successful the field may be developed by installing large fixed platforms from which deviated wells are drilled.Once the development wells have been drilled the rig still has a lot of work to do. Some wells may require maintenance (workovers) or sidetracks to intersect another part of the reservoir. 32A well drilled from an offshore rig is much expensive than a land well drilled to the same depth. The increased cost can be attributed to several factors, e.g. specially designed rigs, subsea equipment, loss of time due to bad weather, expensive transport costs(e.g. helicopters, supply boats). A typical North Sea well drilled from a fixed platform may be cost around $10 million.33Jack Up Rig34Semi-submersible Rig35Drillship36Fixed Platform377 DRILLING ECONOMICS7.1 Drilling cost in field developmentIt is quite common for drilling cost to make up 25-35% of the total development costs for an offshore oilfield.7.2 Drilling cost estimatesBefore a drilling program ia approved it must contain an estimate of the overall costs involved.When drilling in an completely new area with no previous drilling data available the well cost can only be a rough approximation.In most cases some previous well data is available and a reasonable approximation can be made. 38Table 1Table 239Time related cost: drilling contract, transport, accommodationDepth related cost: casing, cementFixed cost:wellheadMore sophisticated methods of estimating well cost are available through specially designed computer programmes.Whatever method is used to roduce the total cost some allowance must be made for unforeseen problems.40Table 341Ex1. Cost and Time DistributionRank the major cost elements in the development of the Brae Field given in table 1 and consider the ways in which the costs distribution might change with a bigger and smaller field.Consider how the costs associated with a well (table 2) are related to the time distribution (table 3) for well.42Platform equipment, development drilling, platform structure, pipeline, platform installation, miscellaneous, onshore facilities.4344Ex. 2 The drilling processYou are required to drill a well into the Rotliegende sandstone shown on the attached geological cross section (Appendix 1). Consider the following aspects of the drilling operation and how you would drill the well:a)The rock penetration process b) -the rock cutting mechanism/toolc) -the transmission of energy to the cutting toold) -the removal of debris from the face of the cutting tool and the borehole. b)The stability/integrity of the boreholec) -potential causes of instabilityd) -potential consequences of instabilitye) -means of preventing/mitigating problems associated with instability 45c) The safety of the operation -the greatest source of risk during the drilling operation d) Data and its acquisition -data relevant to the drilling process -data relevant to evaluating the potential oil and gas production of the formationse) The surface equipment requirement 4647Chap.2 Rig ComponentsnIntroductionnPower systemnHoisting systemnCirculating systemnRotary systemnWell control systemnWell monitoring system481. Introduction•Six sub-systems: •the power system;• the hoisting system;• the circulating system; •the rotary system;• the well control system;• the well monitoring system.4950• Most drilling rigs are required to have a method to generate electrical power.• The electrical power generators are driven by diesel powered internal combustion engines(prime movers).• Electricity is then supplied to electric motors connected to the drawworks(绞车), rotary table(转盘) and mud pumps(泥浆泵).------电驱动钻机2. Power system51523 Hoisting system(提升系统提升系统)The hoisting system is a large pulley(滑轮) system which is used to lower and raise equipment(drill string/casing) into and out of the well. The components:Drawworks: drum, drilling line.Crown block:Travelling block:Hook:Elevator:Deadline, fastlineDeadline anchor5354Static: Ff=Fd=W/NN is the number of lines, W is the hook load.Dynamic: Ff=W/EN; Fd=W/NE is the efficiency of the system.Output power of drawworks (load on fast line times velocity of fast line):HPd=FfVf/33,000 55Round trip operations( 起下钻起下钻):Drilling Ahead〔钻进〕〔钻进〕Running Casing〔下套管〕〔下套管〕Short Trips〔短起下钻〕〔短起下钻〕56The total load of the derrick isFD=W+Ff+Fd57Ex. 1 The hoisting systemA drilling string with a buoyant weight of 200,000 lbs must be pulled from the well. A total of 8 lines are strung between the crown block and the travelling block. Assuming that a four sheave, roller bearing system is being used.a.Compute the tension in the fast line.b.Compute the tension in the deadline.c.Compute the vertical load on the rig when pulling the string. 584 Circulating system• The circulating system is used to circulate drilling fluid down through the drillstring and up the annulus, carrying the drilled cuttings from the face of the bit to surface. • Drilling fluid (mud) is usually a mixture of water, clay, weighting material (Barite) and chemicals. Functions of mud:1.to clean the hole of cuttings made by the bit2.to exert a hydrostatic pressure sufficient to prevent formation fluids entering the borehole.59• The mud is pumped through the standpipe, kelly hose, swivel, kelly and down the drillstring. At the bottom of hole the mud passes through the bit and then up the annulus, carrying cuttings up to surface. •On surface the mud is directed from the annulus, through the flowline and before it re-enters the mudpits the drilled cuttings are removed from the drilling mud by the solids removal equipment.• Once the drilled cuttings have been removed from the mud it is re-circulated down the hole.The mud is therefore in a continuous circulating system.Process of circulation6061The power output of a mud pump:HHP=P Q/1714(1)Duplex double acting(2)Flow rate Q=(2d2-dr2)LEvR/147 gpm(3)d-liner diameter,in.;(4)dr-rod diameter,in.;(5)L-stroke length, in.(6)E-efficiency of pump(7)R-pump speed, spmMud pump62(2) Triplex single actingQ=d2LEvR/98.03 gpmEx. 2 The mud pumpCalculate the following, for triplex pump having 6 in. liners and 11 in. stroke operating at 120 spm and a discharge pressure of 3000 psi.a.The volumetric output at 100% efficviency.b.The horsepower output of the pump when operating under the conditions above. 635 Rotary systemThe rotary system is used to rotate the drillstring and the drillbit.The functions of swivel (旋转头旋转头):•Supports the weight of the drill string;•Permits the string to rotate;•Allows mud to be pumped while the string is rotating.64Kelly (方钻杆方钻杆)：the first section of pipe below the swivel.40’ long and hexagonal cross-sectionHexagonal shape is used to transmit rotation from the rotary table to the drill string. Kelly saver sub(方钻杆保护接头)Kelly cock (溢流阀)Rotary table (转盘)Master bushing (转盘补心)Kelley bushing (方补心)A stand (立柱，由3根钻杆组成)Iron roughneck/a drillpipe spinner (液压大钳)65665.1 Procedures for adding drillpipe when drilling aheadWhen drilling ahead the top of kelly will eventually reach the rotary table. At this point a new joint of pipe must be added to the string in order to drill deeper.1 stop the rotary table, pick up the kelly until the connection at the bottom of the kelly saver sub is above the rotary table, and stop pumping.2 set the drillpipe slips in the rotary table to support the weight of the drillstring, break the connection between the kelly saver sub and the first joint of pipe, unscrew the kelly.673 Swing the kelly over to the next joint of drillpipe which is stored in the mousehole(小鼠洞，接单根用).4 stab the kelly into the new joint, screw it together and use tongs to tighen the connection.5 pick up the kelly and new joint out of the mousehole and swing the assembly back to the rotary table.6 stab the new joint into the connection above the rotary table and make up the connection.7 pick up the kelly, pull the slips and run in hole until the kelly bushing engages the rotary table.8 Start pumping, run the bit to bottom and rotate and drill ahead.68 Procedures for pulling drillstring from the hole695.2 procedure for pulling the drillstring from the holeWhen the time comes to pull out of the hole, the following procedure is used.1 stop the rotary, pick up the kelly until the connection at the bottom of the kelly saver sub is above the rotary table, and stop pumping.2 Set the drillpipe slips, break out the kelly and set the kelly back in the rat-hole (大鼠洞，方钻杆用).3 Remove the swivel from the hook.704 Latch the the elevators onto the top connection of the drillpipe, pick up the drillpipe and remove the slips. Pull the top of drillpipe until the top of the drillpipe is at the top of the derrick and the second connection below the top of the drillpipe is exposed at the rotary table. A stand is now exposed above the rotary table.5 Roughnecks use tongs to break out the connection at the rotary table and carefully swings the bottom of the stand over to one side. Stands must be stacked in an orderly fashion.6 The Derrickman, on the monkey board, grabs the top of the stand, and sets it back in fingerboard.71On some rigs a mechanical device known as an iron roughneck may be used to make up and break-out connections. This machine runs on rails attached to the rig floor, and is easily set aside when not in use. Its mobility allows it to carry out mousehole connections when the tracks are correctly positioned. The device consists of a spinning wrench and torque wrench, which are both hydraulically operated. Advantages offered by this device include controlled torque, minimal damage to threads and reducing crew fatigue.5.3 Iron Roughneck725.4 Top Drive SystemsA top drive system consists of a power swivel, driven by a 1000hp dc electric motor. This power swivel is connected to the traveling block and both components run along a vertical guide track which extends from below the crown block to within 3 meters of the rig floor. The electric motor delivers over 25000ft-ibs torque and can operate at 300rpm. The power swivel is remotely controlled from the driller’s console, and can be set back if necessary to allow conventional operations to be carried out.A top drive system replaces the functions of the rotary table and allows the drillstring to be rotated from the top, using the power swivel instead of a kelly and rotary table.73The procedures for adding a stand1 Suspend the drillstring from slips, as in the conventional system, and stop circulation.2 Break out the connection at the bottom of the power sub.3 Unlatch the elevators and raise the block to the top of the derrick.4 Catch the next stand in the elevators, and stab the power sub into the top of the stand.5 Make up the top and bottom connections of the stand.6 Pick up the string, pull slips, start pumps and drill ahead.74The advantages of TDS:It enables complete 90’ stands of pipe to be added to the string rather than the conventional 30’ singles. This saves rig time since 2 out every 3 connections are eliminated. It also makes coring operations more efficient.When dripping out of the hole the power swivel can be easily stabbed into the string to allow circulation and string rotation when pulling out of hole, if necessary.When tripping into the hole the power swivel can be connected to allow any bridges to be drilled out without having to pick up the kelly.75The disadvantages of TDS:Increase in topside weight on the rig.Electric and hydraulic control lines must be run up inside the derrick.When drilling from a semi-submersible under heaving conditions the drillstring may bottom out during connections when the string is hung off in the slips. This could be overcome by drilling with doubles and a drilling sub which could be broken out like a kelly.76776 WELL CONTROL SYSTEMThe function of well control system is to prevent the uncontrolled flow of formation fluids from wellbore.Any influx of formation fluids in the borehole is known as a kick.The function of well control system:•Detect a kick•Close-in the well at surface•Remove the formation fluid which has flowed into the well•Make the well safe78There are many signs that a driller will become aware of when a kick has taken place. •The first sign that an kick has taken place could be a sudden increase in the level of mud in the pits.•Another sign may be mud flowing out the well even when the pumps are shut down.6.1 detecting a kick796.2 Closing in the wellBlow out preventors (BOPs) must be installed to cope with any kicks that may occur.•On land rigs or fixed platforms the BOP stack is located directly beneath the rig floor.•On floating rigs the BOP stack is installed on the sea bed.•In either cases the vallves are hydraulically operated from the rig floor.Two basic types of BOP:•Annular preventor•Ram preventor (blind rams/pipe rams/shear rams)80Hydril annular BOP81RAM Type BOP826.3 Circulating out a kickTo remove the formation fluids now trapped in the annulus a high pressure circulating system is used. A choke manifold (溢流管汇)with an adjustable choke is used to control flow rates during the circulation. Basically heavier mud must be pumped down the drillpipe to control the formation pressure, and the fluids in the annulus circulated to surface. As the kick starts moving up the hole the choke opening is restricted to hold enough back pressure on the formation to prevent any further influx.The fluids are circulated out via the choke line, through the choke manifold out to a gas/mud separator and a flare stack. Once the heavier mud has reached surface the well should be dead. 837 WELL MONITORING SYSTEMSafety requires constant monitoring of the drilling process. If drilling problems are detected, early remedial action can be taken quickly, thereby avoiding major problems.Driller’s console (司钻控制台)Mudlogging〔泥浆录井〕84BOP Stackup85Chapter 3 The drillstring86ContentsnIntroductionnDrillpipenTool jointsnHeavy wall drillpipenDrill collarsnOther drill string componentsnDrill string design87Drillstring: The tubulars and accessories on the drillbit.The drilldtring consists of:drillpipe, drillcollar, the kelly and various other pieces of equipment such as stabilisers(稳定器) and reamers〔扩眼器 〕.Bottom hole Assembly: the drillcollars and the other equipment which is made up just above the bit.1 Introduction88Components of drillstring89The functions of drillstring are:•To suspend the bit;•To transmit rotary torque from the kelly to the bit;•To provide a conduit(通道) for circulating drilling fluid to the bit.902 drillpipeDrillpipe is a seamless pipe with threaded tooljoints. One end is the box, the other is pin.Each length of drillpipe is known as a joint or a single(单根).Singles are in three API length “ranges〞.But the exact length of each single must be measured on the rig-site. Drillstring must be measured and recorded on a drillpipe tally (标签)91TooljointPipe body92The drillpipe is manufactured with different outer diameters, weights and materials.Specifications: 93weight in air :The weight of drillpipe suspended in air.wet weight :The weight of drillpipe suspended in a fluid.weight in air=weight per foot  length of pipeWet weight=weight in air  Buoyancy FactorEx. 1 dimensions and weight of pipe (see table 13)drillpipe with 4 ½〞〞 IF connections?What is the wet weight of this joint of drill pipe when immersed in a drilling fluid with a density of 12 ppg?942.1 drillpipe stress and failureDrillpipe is exposed to the following stresses:1.Tension-- The weight of suspended drillstring exposes each joint of drillpipe to several thousand pounds of tensile load.2.Torque—during drilling, rotation is transmitted down the string. Gain, poor hole condition can increas the amount of torque or twisting force on each joint.3.Cyclic stress—in deviated hole, the wall of the pipe is exposed to compressive and tensile forces at points of bending in the hole. 95Cyclic stress96Corrosion of a drillstring:•Oxygen•Carbon dioxide•Dissolved salts•Hydrogen sulphide•Organic acids97It is extremely difficult to predict the service life of a drillstring since no two boreholes experience the same drilling conditions. As a rough guide, the length of hole drilled by a piece of drillpipe will be:Soft drilling areas: 220000-250000ftHard or deviated drilling areas: 180000-210000 ftThe methods used to inspect drillpipe are summarised in table 4.2.3 Drillpipe Inspection98993 tool joint (钻杆接头钻杆接头)Tooljoints are located at each end of a length of drillpipe and provide the screw thread for connecting the joints of pipe together.The modern method is to flash-weld the tooljoints onto the pipe.A hard material is often welded onto the surface of the tooljoint to protect it from abrasive wear as the drillstring rotated in the borehole.1001014 heavy wall drill pipeHeavy wall drill pipe has a greater wall thickness than ordinary drillpipe and is often used at the base of the drillpipe where stress concentration is greatest.The stress concentration is due to:The difference in cross section and therefore stiffness between the drillpipe and drillcollars.The rotation and cutting action of the bit can frequently result in a vertical bouncing effect〔纵振〕. 1025 drill collarDrill collars are tubulars which have a much larger outer diameter and generally smaller inner diameter than drillpipe.The functions of drill collars are:•To provide enough weight on bit for efficient drilling•To keep the drillstring in tension, thereby reducing bending stresses and failures due to fatigue.•To provide stiffness in BHA for directional control.103Since the drillcollars have such a large wall thickness tooljoints are not necessary and the connection threads can be machined directly onto the body of the collar.Ex. 2 drillcollar dimensions and weightsWhat is the weight in air of 200 ft of 9 ½〞〞 x 2 13/16〞〞 drillcollar?What is the weight of this drillcollar when immersed in 13 ppg mud?drillpipe to be used in the same string as 8 ¼〞〞 x 2 13/16〞〞 drillcollar. Compare the nominal I.D. of this drillpipe and drillcollar size and note the differences in wall thickness of these tubulars? 104Spiral type of collar1056 OTHER DRILLSTRING COMPONENTS• Stabilisers• Roller reamer• Shock sub• Subs• Drilling jars1061077. DRILL STRING DESIGNThe requirements which must be met for drillstring designing are:•The burst, collapse and tensile strength of the drillstring components must not be exceeded;•The bending stresses within the drillstring must be minimised;•The drillcollars must be able to provide all of the weight required for drilling;•The BHA must be stabilised to control the direction of the well. 108>45<45Drilling tendency1097.1 Design of a stabilised stringWhen the slope of formation bed is less than 45 degrees the bit tends to drill up-dip (perpendiculer to the layers). If the dip is great than 45 degrees the it tends to drill parallel to the layers.There are two techniques for controlling deviation.•Packed hole assembly—a stiff assembly (maintain the hole direction)•Pendulum assembly—tend to decrease the angle of deviation. 110Pendulum assemblyPacked hole assembly1117.2 Bending Moments in string designSection modulus <5.5 safe1127.3 Length of drillcollarsThe length of collar L=WOB/wWOB—weight on bitw—Buoyant weight per footConsidering the change of WOB, The length of drillcollar is 113Ex. 3 Length of drillcollars for a given WOBYou have been advised that the highest rate of penetration for a particular 12 ¼〞 bit will be achieved when 25,000 lbs weight on bit is applied to the bit. Assuming that the bit will be run in 12 ppg mud, calculate the length of drillcollars required to provide 25,000 lbs WOB.Calculate the weight of 10000 ft of 5〞 19.5 lb/ft Grade G drillpipe with 4 ½〞 IF connections.Calculate the weight of this string in 12 ppg mud.Calculate the length of 9 ½〞 x 1 13/16〞 drillcollars that would be required to provide 25,000 lbs WOB and keep the drillpipe in tension in 12 ppg mud. 1147.4 drillpipe selection1.The main factors considered in the selection of drillpipe are the collapse load, and the tensile load on the pipe.2. Burst pressures are not generally considered since these only occur when pressuring up the string on a plugged bit nozzle or during a DST but it is very likely that the burst resistance of the pipe will be exceeded.3. Torsion need not be considered except in a highly deviated well.115Collapse loadThe highest external pressure tending to collapse the string will occur at the bottom when the string is run empty into the hole.Collapse pressure Pc=0.052 x MW x TVDMW –mud weight ppgTVD—true vertical depth at which Pc acts ft116Tension loadThe tension loading can be calculated from the known weights of the drill collars and drill pipe blow the point of interest.The effect of buoyancy force on the drillstring weight must also considered.117In addition to the design load calculated on the basis of the string hanging freely in the wellbore the following safety factors and margins are generally added:•Margin of overpull (拉伸余量拉伸余量) 50,000-100,000 lbs•Safety factor for slip crushing (卡瓦挤毁系数卡瓦挤毁系数)1187.4 Design ProceduresA graphical approach to drillstring design is recommended. If one section of the string does not meet requirement it must be upgraded. The procedure is as follows:1.Choose a weight and grade of the pipe to safety the collapse conditions;2.2 Using the pipe chosen in 1 calculate the tension loading, including buoyancy effects. Draw the tension loading line and also the maximum allowable load line.3.Modify the tension load as given in 2 by applying a design factor, MOP and Sh/St factor. Three design lines are thus generated.1194. If any of these design lines exceed the maximum allowable load, a higher rate drillpipe must be used for that section of pipe.5. Calculate the new tension loading line for the new drill string and repeat step 3 and 4.Design Example: Design a 5〞〞 19.5 lb/ft drill string using new pipe to reach a TD of 12000 ft in a vertical hole. The BHA consists of 20 drill collars 6 ¼〞〞 x 2 13/14〞〞 (82.6 lb/ft) each 30 ft long. For design purposes assume the following:MW=10ppgMOP=100000 lbsLength of slips =12〞〞Design factors= 1.125(collapse) =85%(tension)1201.Collapse loading 2.at 12000’ Pc=0.052x10x12000=6240psi3.From table 114.OD Grade Wt Collapse rating5.Choose: 19.5 lb/ft grade E drill pipe (ID=4.276〞)1212. Tension loading lineAt 12000’ F1=P x A=22) =152683 lbs W1=20x30x82.6=49560 lbsAt 11400’ F2=P x AP=0.052x10x11400=5928 lbs2-5222)=19.19 in2F2=5928x19.19=113758 lbsW2=11400x19.5=2223000 lbsCalculating the tension at the top and bottom of each section:At bottom of collars T=-152693 lbsAt top of collars T=-152693+49560=-103133 lbs122At bottom of drillpipe T=-103133+113758=10625 lbsAt top of drillpipe T=10625+222300=232925 lbsPlot these figures on a graph, along with the maximum allowable load = 0.85x 395000 = 335750 lbs3. Construct design loading lines:a.Multiply actual loads by 1.3 to obtain the design loads(Td)b.at surface Td=1.3x 232925= 302802 lbsc.at 11400’ Td=1.3x10625=13812 lbsd.b. add 10000 MOP to obtain Tdat surface Td=232925+100000=332925 lbsat 11400’ Td=10625+100000=110625 lbs123c. Apply slip crushing factorAt surface Td=1.59x232925=370351 lbsAt 11400’ Td=1.59x 10625=16894 lbs4. Above 2000’ the design loading line exceeds the maximum allowable tensile load, therefore a stronger section of pipe must be used from 0-2000’.Choose 25.6 lb/ft grade E drill pipe.5. Re-calculate tensile loading for new string and repeat 3 and 4.1241256. Final design0-2000’ 25.6 lb/ft grade E2000-11400’ 19.5 lb/ft grade E11400-12000’ 6 ¼〞 x 2 13/16〞 collars126Chapter 4 Drilling BitsnTypes of drilling bitnBit designnBit selectionnRock bit evaluationnBit performance1271281. Types of drilling bit1.1 Drag BitsDrag bits were the first bits used in rotary drilling, but are no longer in common use.A drag bit consists of rigid steel blades shaped like a fish-tail which rotate as a single unit.Due to the dragging/scraping action of this type of bit, high RPM and low WOB are applied.129The decline in the use of drag bit was due to:•The introduction of roller cone bits, which could drill soft formation more efficiently;•If too much WOB was applied, excessive torque led to bit failure of drill pipe failure;•Drag bit s tend to drill crooked(弯曲的弯曲的) hole, therefore some means of controlling deviation was require;•Drag bits were limited to drilling through uniformly, soft, unconsolidated formations where no hard abrasive layers.1301.2 Roller cone bitsRoller cone bits or rock bits are still most common type of bit used world wide.The cutting action is provided by cones which have either steel teeth or tungsten carbide inserts.These cones rotate on the bottom of the hole and drill hole predominantly with a grinding and chipping action.Rock bits are classified as milled tooth bits or insert bits depending on the cutting surface on the cones.The cones of 3 cone bit are mounted on bearing pins, or arm journals which extend from the bit body. The bearings allow each cone to turn about its own axis as the bit is rotated.1311321.3 Diamond BitsNatural Diamond BitsThe diamond bit is really a type of drag bit since it has no moving cones and operates as a single unit. The cutting action of a diamond is achieved by scraping away the rock.Despite its high wear resistance diamond is sensitive to shock and vibration and therefore great care must be taken when running a diamond bit.Effective fluid circulation across the face of the bit is also very important to prevent overheating of the diamonds and matrix material and to prevent the face of the bit becoming smeared with the rock cuttings (bit balling).133PDC bitsA new generation of diamond bits known as polycrystalline diamond compact bits were introduced in the 1980’s. this bit uses small discs of synthetic diamond to provide the scraping cutting surface.TSP bitsA further development of the PDC bit concept was the introduction in the later 1980’s of thermally Stable Polycrystalline diamond bits. These bits are manufactured in a similar fashion to PDC bits but are tolerance of much higher temperatures than PDC bits.1342. BIT DESIGNRoller Cone Bit Design•Bearing assemblies•Cones•Cutting elements•Fluid circulation 135Bearing assemblyThere are three types of bearings:Roller bearings, which form the outer assembly and help to support the radial loading;Ball bearings, which resist longitudial or thrust loads and also help to secure the cones on the journals.A friction bearing, in the nose assembly which helps to support the radial loading.The friction bearing consists of a special bushing pressed into the nose of the cone.136137Cone DesignCone slipage(超顶)Offsetting(移轴)138Cutting StructureThe selection of a milled tooth or insert bit is largely based on the hardness of the formation to be drilled. The main considerations in the design of the cutting structure is the height and spacing of teeth or inserts.•Soft formation bits require deep penetration into the rock so the teeth are long, thin and widely spaced to prevent bit balling. Bit balling occurs when soft formations are drilled and the soft material accumulates on the surface of the bit preventing the teeth from penetrating the rock. 139Moderately hard formation bits are required to withstand heavier loads so tooth height is decreased, and tooth width increased. Such bits rely on scraping/gouging action with only limited penetration.Hard formation bits rely on a chipping action and not on tooth penetration to drill, so the teeth are short and stubbier than those used for softer formations. The teeth must be strong enough to withstand the crushing/chipping action and sufficient numbers of teeth should be used to reduce the unit load. 140Fluid circulationDrilling fluid passes from the drillstring and out through nozzles in the bit. As it passes across the face of the bit it carries the drilled cutting from the cones and into the annulus.The fluid is now generally ejected through three jet nozzles around the outside of the bit body. Jet nozzles are small rings of tungsten carbide and are available in many sizes.The outside diameter of the ring is standard so that the nozzle can fit into any bit size.1412.2 PDC BIT DESIGNThe five major components of PDC bit design are•Cutting Material•Bit Body Material•Cutter Rake•Bit Profile•Cutter Density•Cutter Exposure•Fluid Circulation142There are three basic types of PDC bit crown profiles: flat or shallow cone; tapered or double cone; and parabolic.The flat or shallow profile enenly distributes the WOB among each of the cutters on the bit. Two disadvantages of this profile are limited rotational stability and uneven wear. Rocking can occur at high RPM, because of the flat profile. This can cause high instantaneous loading, high temperatures and loss of cooling to the PDC cutters.The taper or double cone profile allows increased distribution of the cutters toward the OD of the bit and therefore greater rotational and directional stability and even wear is achieved.The parabolic profile provides a smooth loading over the bit profile and the largest constant area. This bit profile therefore provides even greater rotational and directional stability and even wear. Tjis profile is typically used for motor or turbine drilling.1431443. BIT SELECTION3.1 Roller Cone BitsThe IADC bit comparison charts are often used to select the best bit for a particular application. The bits are classified according to the international association of drilling contractors code.The position of each bit in the chart is defined by three numbers and one character. The sequence of numeric characters defines the “series, type and features〞 of the bit. The additional character defines additional design features.Column 1 –SeriesThe series classification is split into two broad categories: milled tooth bits (series 1-3) and insert bits(series 4-8). The characters 1-8 represent a particular formation drillability.145Series 1-3 bits are milled tooth bits which are suitable for soft, medium or hard formations.Series 4-8 bits are insert bits and are suitable for soft, medium, hard and extra hard formations.Column 2 –TypeEach series category is subdivided into 4 types according to the drillability of the formation.Row 1 – FeaturesThe design features of the bit are defined on the horizontal axis of the system. 146The numerical characters define the following features:1 means s standard roller bearings2 means air cooled roller bearings3 means a roller bearing bit with gauge protection5 means sealed roller bearings are included5 means both sealed roller bearings and gauge protection included6 means sealed friction bearings included7 means both sealed friction bearings and gauge protection included147Additional Table—additional design featuresAn additional table is supplied with the bit classification chart. This table defines additional features of the bit. Eleven characters are used to describe features such as: extended nozzles; additional nozzles; suitability for air drilling etc. If a bit is classified as 1-2-4-E this means that it is a soft formation, milled tooth bit with sealed roller bearings and extended nozzles.148Fixed cutter bitsThe fixed cutter bit (diamond, PDC, TSP) classification system was introduced by the IADC in 1987. The system is comprised of a four character classification code indicating a total of seven bit design features: cutter type, Body material, Bit profile, fluid discharge, flow distribution, cutter size, and cutter density. Column 1 primary type and body material:Five letters are used to describe the cutter type and body material, as shown in table 4. Column 2 –Cross sectional profile:The numbers 1-9 are used to define the bits’ cross sectional profile, according to the 3x3 chart shown in table 4. 149Column 3 Hydraulic design:The numbers 1-9 in the third character of the system refers to the hydraulic design of the bit. Column 4 Cutter size and placement Density:The numbers 1-9 in the forth character of the system refers to the cutter size and placement density, according to the 3x3 matrix chart shown in table 4.1504. ROCK BIT EVALUATIONThe evaluation of bits is useful for the following reasons:•To improve bit type selection•To identify the effects of WOB,RPM,etc., •To allow drilling personnel to improve their ability to recognis when a bit should be pulled.•To evaluate bit performance and help to improve their design.•A bit record (table 5) will always be kept by the operating company, drilling contractor and/or bit vendor. 151The IADC Dull Grading System is based on the chart shown in figure 25 and will be described in terms of each column:Column 1—Cutting structure Inner Rows:Report the condition of the cutting structure on inner 2/3 rds of the bit for roller cone bits and inner 2/3 rds radius of a fixed cutter bit.Column 2—Cutting structure Outer Row:Report the condition of the cutting structure on the outer 1/3 rd of the bit for roller cone bits and outer 1/3 rds radius of a fixed cutter bit. 152STEEL TOOTH BITS: a measure of the lost tooth height.8 indicates total loss of tooth height due to wear or breakageINSERT BITS: a measure of total cutting structure reduction due to lost, worn and/or broken inserts0 indicate not lost, worn and /or broken inserts8 indicates total loss of cutting structure due to lost, worn and/or broken insertsFIXED CUTTER: a measure of the cutting structure wear0-indicates no loss of cutter or diamond height due to wear or breakage8 indicates total loss of cutter or diamond height due to wear or breakage153Column 3 Cutting structure Dull Characteristics(D):Column 4 Cutting structure Location (L):Column 5 Bearing Condition (B):Column 6 Remarks (O)Column 8 Reason for Pulling (R)1545 BIT PERFORMANCEThe performance of a bit may be judged on the following criteria:•How much footage it drilled •How fast it drilled•How much it cost to run per foot of hole drilled.The best method of assessing the bit’s performance is the last of the above.C=overall cost per foot($/foot); Cb=cost of bit($); Rt=rotating time with bit on bottom(hrs); Tt=round trip time(hrs); Cr=cost of operating rig($/hrs).1555.1 Roller cone bits:In addition to correct bit selection, penetration rate is a function of many parameters:•Weight on bit(WOB)•Rotary speed(RPM)•Mud properties•Hydraulic efficiencyWeight on bitA certain minimum WOB is required to overcome the compressibility of the formation. It has been found experimentally that once this threshold is exceeded, penetration rate increases linearly with WOB.156Certain limitation to the WOB are as follows:a.Hydraulic horsepower at the bitb.If the HHP at the bit is not sufficient to ensure good bit cleaning the ROP is reduced either by bit balling or bottom hole balling.c.The HHP at the bit is given by:d. HHPb=Pb x Q /1714e. Pb=pressure drop across the nozzles of the bitf. Q=flow rate through the bitg.To increase HHP requires an increase in Pb (small nozzles) or Q (faster pump speed or larger liners).h.Hole cleaning may be improved by using extended nozzles to bring the fluid stream nearer to the bottom of the hole.157b. Type of formationWOB is often limited in soft formations, where excessive weight will only bury the teeth into the rock and cause increased torque, with no increase in ROP.c. Hole deviationIn some areas, WOB will produce bending in the drilstring, leading to a crooked hole. The drillstring should be properly stabilised to prevent this happening.d. Bearing lifeThe greater the load on the bearings the shorter their operational life. Optimising ROP will depend on a compromise between WOB and bearing wear.e. Tooth lifeIn hard formations, with high compressive strength, excessive WOB will cause the teeth break.158Rotary speedThe ROP will also affected by rotary speed of the bit and optimum speed must be determined. The RPM influences the ROPExperience plays a large part in selecting the correct rotary speed in any given situation.The RPM applied to a bot will be a function of a.Type of bit (In general lower RPMs is used for insert bits than for milled tooth bits.)b.Type of formation (Harder formations are less easily penetrated and so require low RPM. )159Mud propertiesIn order to prevent an influx of formation fluids into the wellbore the hydrostatic mud pressure must be slightly greater than the formation pressure. This overbalance, or positive pressure differential, forces the liquid portion of the mud into the formation, leaving the solids to form a filter cake on the wall of the borehole. In porous formations this filter cake prevents any further entry of mud into the formation. This overbalance and filter cake also exists at the bottom of the hole where it affects the removal of cuttings. The differential pressure on the chip tends to keep the chip against the formation. This is known as the static chip hold down effect, and leads to lower penetration rates.To reduce the hold down effect:•Reduce the positive differential pressure •Reduce the solids content of the mud1605.2 PDC Bits:WOB/RPMPDC bits tend to drill faster with low WOB and high RPM. They are also found to require higher torque than roller cone bits. The general recommendation is that the highest RPM that can be achieved should be used. Although the torque is fairly constant in shale sections the bit will tend to dig in and torque up in sandy sections.When drilling in these sandy sections, or when the bit drills into hard sections and penetration rate drops, the WOB should be reduced but should be maintained to produce a rotary torque at least equal to that of a roller cone bit. 161Mud PropertiesThe best ROP results have been achieved with oil based muds but a good deal of success has been achieved with water based muds.Hydraulic EfficiencyThe effects of increased hydraulic horsepower at the bit are similar to their effect on roller cone bits.162Ex. 2 cost per foot of a bit runThe following bit records are taken from the offset wells used in the design of the well shown in Appendix 1 of Chapter 1.Assuming: tahta the geological conditions in this well are the same as those in the offset wells below; that the 12 ¼〞〞 section will be drilled from around 7000ft; an average trip time of 8 hrs; and a rig rate of £400/hr. select the best bit type to drill the 12 ¼〞〞 hole section. WELL BIT COST DEPTH(IN) DEPTH (OUT) TIME £ ft ft hr 163Ex.3 Cost per foot whist drillingWhist drilling the 12 ¼〞〞 hole section of the new well the following drilling data is being recorded and provided to the company man. At what point in time would you have suggested that the bit be pulled and why? Assume n average trip time of 8hrs, rig rate of 400/hr and the bit type selected above had been run in hole.Time footage drilled1 342 623 864 1105 1266 154 7 180 8 210 9 21610 22611 23412 240 164。