1. Petroleum DrillingFundamentalsSigve Hamilton Aspelund

2. Introduction to Rig types andDrill ComponentRig Selection and basic planningstepsTypes of wellsTypes of rigsSteps to drill oil or gas wellsThe well construction teamWell costingCommunications and safety issues 3. Basic pore pressure andfracture gradient estimationUnits and terminology and basicdefinitionsGeo pressure and well designconsiderationCauses of overpressurePore pressure theoryReal time diagnostics of pore pressureOverburden gradient estimationFracture gradient estimationLOT analysisCasing seat selectionUncertainty analysis. 4. Designing the wellTranslating the geological prognosis into a well designRig selectionTypes of drilling rigs onshore and offshoreDrilling equipmentThe rotary system conventional, top drive, rotary steerableAutomated rigsContractor selectionCasing and CementingDrilling muds and completion fluids; types and functionsBits and specialised drilling equipmentFormation and well evaluation requirements:Mud loggingWireline and MWD/LWD loggingCase Study: Casing design including uncertainties in pressure androck strengthCase Study: Identification of potential drilling hazards 5. Drilling the wellMonitoring progress in drilling operationsThe daily drilling report what does it containand how do you read it?Well control issues why the drilling foremanneeds a certificate:Mud control and testingCasing and cementing operationsThings that can go wrongStuck pipeOverpressuresLost circulationKicks 6. Completing the wellTypes of completions what is theirfunction?Completion fluids why are theydifferent from drilling fluids?Basic completion string equipmentand Xmas treesSand control equipment fromscreens to gravel packsPerforation technology equipmentand safety aspects 7. New technology & ideasDrilling the limit how to improve andsave moneyExpandable tubularsMulti-lateral wellsSmart wells (Intelligent completions) 8. Youtube videosOil and gas drilling videoOil rig 3D animationPetroleum engineersDrilling for oil in AlgeriaBlow out preventerWell loggingDrilling, cementing and stimulation3D seismic 9. Structural geology 1Structural geology 2 10. Rig Selection and basic planningstepsOffshore drilling Ca. 25% of worlds oil and gas is producedfrom offshore fields (i.e. North Sea or Gulfof Mexico) North sea: Exploration wells are drilledwith Jack up or Semi-submersible drillingrigs. 11. Jack upRetractable legs that can be loweredto the sea bed. The legs support thedrilling rig and keep the rig in position. 12. Jack upUnaffected by the weather during the drillingphaseThe safety valve is located on deckIt does not need anchoring systemIt does not need heave compensator(permanent installation in the drilling phase)It has removable drill towerDepth limit is 150 metersIt is unstable under the relocationIt depends on the tug for moving 13. Semi submersiblePortable device that consists of a deckplaced on columns attached to two ormore pontoons.During operation tubes are filled withwater and lowered beneath the seasurface. 14. Semi submersibleThe vessel normally kept in positionby anchors, but may also havedynamic positioning equipment (DP).Usually have their own propulsionmachinery (max. depth approx. 600to 800 meters).The most common type is the "semi-submersibledrilling rig". 15. Drilling shipIn very deep water (2300m) drill shipsare used for drilling the well.A drillship is easy to moveand is therefore well suited fordrilling in deep waters, since it iswell suited fordynamic positioning. It requires relatively little force to remain in position. 16. Condeep platformCondeep platform is the denomination of a seriesof oil platforms that were developed in Norway to drillfor oil and gas in the North Sea. The name comesfromthe Englishconcrete deep water structure", or deepstructure of concrete.The platforms rest on thick concrete tanks that are onthe ocean floor and acts as an oil stock. Fromthese sticks it as one, three orfour slender hollow columns, which is about 30 feetabove the surface. 17. Condeep platformIt was Stavanger company NorwegianContractors who developed the concept ofCondeep platforms in 1973, after the success of theconcrete tank at the Ekofisk field.Condeep platforms are not produced anymore. Thelarge concrete platforms are out competed by new,cheaper floating rigs and remote-controlledunderwater installations. 18. Jacket platformThe most widely used platform in the North Seabearing structure is built as framed in steelPlatform are poles fixed to the bottomThe construction is susceptible to corrosionHas no storage tank, but must be associated pipelinenetwork. 19. Tension leg platformA tension leg platform is a floating and verticallyanchored platform or buoy which is normally usedfor offshore production of oil or natural gas, and isespecially suitable for water depths exceeding300 meters. We usually use rods or chains to keepthe platform in place. 20. Tension leg platformAffordable solutionQuick to installCan be equipped entirely by countriesCan be used on very deepCan be moved when a field is emptyBecause of movement of water requiredcompensation equipment 21. Well head plattformCan be an alternative to production facilities on theseabed, especially where water depth is small, asin the southern part of the north sea. Thewellhead platform is an unmanned small platform,which we can remotely control from a motherplatform".Valve tree is dry. 22. Exploration and productionlicencesGovernment invite companies to applyfor exploration and production licenceson the continental shelf.Exploration licences may be awardedany time.Production licences are awarded atspecific discrete intervals known aslicensing rounds. 23. Exploration, development andabandonmentBefore drilling an exploration well anoil company will have to obtain aproduction licence.Prior to applying for a productionlicence Exploration geologistsScouting exerciseAnalyse seismic dataAnalyse regional geologyAnalyse well tests in the vicinity of the prospect theyare considering 24. Explorationists Consider exploration and developmentcostsOil price and tax regimesEstablish if reservoir is worth developingIf prospect is considered worthexploring The company will try to aquire aproduction licenceExplore the fieldThe licence will allow company to drillexploration wells in the area ofinterest. 25. Before exploration wells are drilled Licencee may shoot extra seismic lines ina closer grid patternDetailed information about the prospectAssist in definition of optimum drilling targetDespite improvements in seismictechniques the only way ofconfirmining the presence ofhydrocarbons is to drill an explorationwell. 26. Drilling is very expensice If hydrocarbons are not found there is noreturn on the investment, althoughvaluable geological information may beobtained. With only limited information available alarge risk is involved.Having decided to go ahead and drillan exploration well proposal isprepared. 27. The objectives of this well will be: to determine the presence ofhydrocarbons to provide geological data (cores, logs) forevaluation to flow test the well to determine itsproduction potential, and obtain fludsamples. 28. The life of an oil or gas field can besub-divided into the following phases: Exploration Appraisal Development Maintenance Abandonment 29. The length of the exploration phase willdepend on the success or otherwise of theexploration wells.There may be a single exploration well ormany exploration wells drilled on a prospect.If an economically attractive discovery ismade on the prospect then the companyenters the appraisal phase of the life of thefield.During this phase more seismic lines may beshot and more wells will be drilled to establishthe lateral and vertical extent of (to delineate)the reservoir. 30. These appraisal wells will yield furtherinformation, on the basis of which futureplans will be based.The information provided by theappraisal wells will be combined with allof the previously collected data andengineers will investigate the most costeffective manner in which to develop thefield.If the prospect is economical attractive aField development plan wil be submittedto secrectary state of energy. 31. If approval for the development isreceived then the company willcomeence drilling development wellsand constructing the productionfacilities according to the developmentplan.Once the field is on-stream thecompanies commitment continues inthe form of maintenance of both thewells and the production facilities. 32. After many years of production it may befound that the fild is yielding more or possiblyless hydrocarbons than initially anticipated atthe development planning stage and thecompany may undertake further appraisaland subsequent drilling in the field.At some point in the life of the field the costsof production will exceed the revenue fromthe field and the field will be abandoned. Allof the wells will be plugged and the surfacefacilities will have to be removed in a safeand environmentally acceptable fashion. 33. Well planning and design 34. Standard Spiral drill collar 35. Integral heavy weight drill pipe andSpiral integral heavy weight drill pipeSquare kelly 36. Pup jointStabilizerCross oversub 37. Integral heavy weight drill pipe Spiral drill collar 38. Super high pressure tubinTgu bing used for high-pressureboiler 39. Drill PipeApplicable to API standard.Steel grade EGXS. Size: 2 3/8 3 1/22 7/84 1/2551/2. 40. Drill CollarCollarApplicable to API standard. Out dia2 3/83 1/22 7/84 1/2551/2. 41. KellyKellyApplicable API standard.Hex and square, two models.Size:3 1/24 1/451/46. 42. Heavy Weight Drill PipePipe Applicable API standard. Size: 3 1/24 1/2551/2. 43. TubingApplicable to API standard.Steel grade:J55,N80,P110. Size: 2 3/82 7/83 1/2 44. CasingCasingApplicable to API standard.Size: 4 1/25 1/279 5/810 3/413 3/8 45. OilGas Delivery PipesPipesApplicable to API standard.Size: 8 3/410 3/412 3/414161820222426283032364044485256 46. Drill BitPDC bitCone bit 47. Drilling personnelDrilling a well requires many skills andinvolves many companies 48. The oil company who manages thedrilling and/or production operations isknown as the operator.In joint ventures one company acts asoperator on behalf of the otherpartners.The oil company normally employ adrilling contractor to drill the well.Drilling contractor owns and maintainsthe drilling rig and employs and trainsthe personnel required to operate therig. 49. During the course of drilling the wellcertain skills or equipment may berequired (e.g. Logging, surveying).These are provided by servicecompanies.These service companies develop andmaintain specialist tools and staff andhire them out to the operator,generally on a day rate basis. 50. The operator will generally have arepresentative on the rig called thecompany man to ensure drillingoperations go ahead as planned,make decisions affecting progress ofthe well, and organise supplies ofequipment. He will be in daily contacwith his drilling superintendent whowill be based in the head office of theoperator. 51. There may also be an oil companydrilling engineer and/or a geologist onthe rig.The drilling contractor will employ atoolpusher to be in overall charge ofthe rig.He is responsible for all rig flooractivities and liases with the companyman to ensure progress is satisfactory. 52. The manual activities associates withdrilling the well are conducted by thedrilling crew. Since drilling continues 24hours a day, there are usually 2 drillingcrews.Each crew workd under the direction ofthe driller. The crew will generallyconsist of a derrickman (who also tendsthe pumps while drilling), 3 roughnecks(working on rig floor), plus a mechanic,an electrician, a crane operator androustabouts (general labourers). 53. Service company personnel aretransported to the rig as and whenrequired. Sometimes they are on therig for the entire well (e.g mudengineer) or only for a few days duringparticular operations (e.g. directionaldrilling engineer) 54. Drilling economicsDrilling costs in field developmentDrilling costs ~25-35% of totaldevelopment costs for an offshoreoilfield. 55. The costs of the development will notbe recovered for some time since inmost cases production is delayed untilthe first few platform wells are drilled.These delays can have a seriousimpact on the economic feasibility ofthe development and operators areanxious to reduce the lead time to aminimum. 56. Drilling cost estimatesBefore a drilling programme isapproved it must contain an estimateof the overall costs involved.When drilling in a completely newarea with no previous drilling dataavailable the well cost can only be arough approximation.In most cases some prevours welldata is available and a reasonableapproximation can be made. 57. A typical cost distribution for a NorthSea Well 58. Some costs are related to time and aretherefore called time-related costs (e.g.Drilling contract, transport,accomodation).Many of the consumable items (e.g.casing, cement) are related to depth andare therefore often called depth-relatedcosts.These costs can be estimated from thedrilling programme, which gives thelength or volumes required. 59. These costs can be estimated fromthe drilling programme, which givesthe lenghts or volumes required.Some of the consumable items suchas the well head will be a fixed cost.The specialised services (e.g.perforating) will be a charged for onthe basis of a service contract whichwill have been agreed before theservice is provided. 60. The price list associated with thiscontract will be a function of both timeand depth and the payment for theservice will be made when theoperation has been completed.For wells drilled from the same rigunder similar conditions (e.g. platformdrilling) the main factor in determiningthe cost is the depth, and hence thenumber of days the well is expected totake. 61. Plot of depthagainst days forwells drilled froma North Seaplattform. 62. Time breakdownfor a North Seawell. 63. More sophisticated methods ofestimating well costs are availablethrough specially designed computerprogrammes.Whatever method is used to produce atotal cost some allowance must be madefor unforseen problems.When the estimate has been worked outit is submitted to the companymanagement for approval. This is usuallyknown as an AFE (authority forexpenditure). 64. Funds are then made available tofinance the drilling of the well withing acertain budget.When a well exceeds its allocatedfunds a supplementary AFE must beraised to cover the extra costs. 65. Communications and safetyissuesThe Piper Alpha DisasterIn 1988 Britain suffered one of theworst industrial disasters when thePiper Alpha oil Platform wasdestroyed by fire and gasexplosion, resulting in 167fatalities. The disaster causedsignificant changes to the mannerin which safety was regulated andmanaged in the UK offshore oilindustry. 66. Events in the disasterThe Piper Alpha platform was operated by OccidentalPetroleum (Caledonia) Ltd. and located 110 milesnotheast of AberdeenThe platform produced oil and gas and was linked tothe installations Tartan, Claymore and MCP01 bysubsea pipelinesOn July 6, 1988, dayshift workers had removed a safetyrelease for a consendate pump that was not being usedand replaced it with a blank flangeSeveral hours later the night shift operations teamexperienced a problem with a second consendate pumpand restarted the first pump, unaware of the the safetyvalve had been removed 67. Around 10:00 pm there was an explosion on theproduction deck of the platform which was caused theignition of a cloud of gas consendate leaking from thetemporary flangeThe fire spread rapidly and was followed by a numberof smaller explosionAt around 10:20 pm a major explosion was followed bythe ruptering of a pipeline carrying gas to the PiperAlpha platform from the nearby Texaco Tartan platformThe next few hours an intense high-pressure gas fireraged, punctuated by a series of major explosions thatserved to hasten the structural collapse of the platform 68. Most of the emergency systems on the platform, including thefire water system, failed to come into operationsOf the 226 persons onboard the installation only 61 survivedThe great majority of the of the survivors escaped by jumpinginto the sea, some from as 175 feet (approx. 54 m) 69. Piper Alpha in flames 70. Crisis Management at PiperAlphaThe explosion on the Piper Alpha that led tothe disaster was not devasting. We shallnever know, but it probably would have killedonly a small number of menThere was a number of critisim related to theperformance of the OIM on both Piper Alpha,Claymore and Tartan platformsThese platforms were linked together bypipelines and if the hydrocarbons from theseplatforms had been stopped earlier, thesituation on Piper might have deterioated lessrapidly 71. On the evening of the crisis the platforms OIM was athis cabinIn the control room at 9:55 pm a series of low gasalarms was registered followed by a single high gasalarm and a suddenly explosionThe stand by boat sent out a mayday callBy 10:05 several minutes after the explosion the OIMarrived in the radio room wearing a survival suit andinstructed the radio operator to send out a maydayThe OIM left without giving further instructions or statinghis intentions 72. A few seconds later he ran into the radio room and told theoperator that area outside was on fire and that it should bebroadcasted that the platform was being abandonedBy this time people had started to muster in theaccomodation area an were waiting further instructionsSome of the emergency response teams made attempts totackle the fires or to effect rescues, but these wereuncoordinated and ineffective efforts in a desperate situationBy 10:20 pm 22 surviors had abandoned the platform manywho had been working outside such as diversWhere people had mustered no one was in charge or givinginstructions and there was confusion 73. A second major explosion because of gas coming into the thePiper from Tartan caused a massive high-pressure gas fire onthe platformBy 10:50 pm the structure of the platform was beginning tocollapse and gas fires were ragingThe OIM and the majority of his crew died onboard as a resultof smoke inhalationThe report afterwards showed that the OIM took no initiativein an attempt to save life but in his defense severalpsychological factors could explain the OIM`s inadequateleadership and poor decision makingHe was under considerable stress and had not been properlytrained and smoke inhalation can effect cognitive functioning 74. The Claymore Platform 75. Crisis Management atClaymoreHowever what was more suprising revealing seriousweaknesses in the oil industry`s provision for offshorecrisis management, was that the two other OIM`s onduty from the linked platforms also failed to takeappropriate decisionsThe Claymore platform situated 22 miles from Piperneeded to shut down the oil production to prevent itfrom flowing towards the Piper platformAt 10:05 pm the Claymore OIM was told that there hadbeen a mayday on Piper due to fire and explosionAn attempt to contact Piper was unsuccessful and onthe secong mayday from Piper he sent a standbyvessel without shutting down the oil production 76. The operating superintendent at Claymore askedthe OIM if he could shut down the oil production.The OIM refused thisThe OIM at Claymore then called his manager inAberdeen. They knew that Pipers oil had beenshutdown. But as the pipeline pressure wasstable the OIM decided to continue theproduction10:30 they have heard that the fire on Piper wasspreading, and the operating superintendentagain asked the OIM to shut down oil production.This was refused because he wanted to maintainthe production 77. During a later phonecall the OIM madeto the Production Manager the operatingsuperintendent shouted that there hadbeen an explosion on the Piper. TheProduction Manager in Aberdeen askedthem to shut down immediately when hefound out that they were still operatingThe Production Manager was suprisedthat they were still operating andinstructed both Claymore and Tartan toshut down production 78. Illustration of the Oil fieldPiper AlphaClaymoreTartan 79. The Tartan Platform 80. Crisis Management on TartanTexaco`s Tartan was located 12 miles southwest of Piper andalso needed to shut down gas and oil production in the eventof an serious emergency on Piper10:05 pm the OIM at Tartan heard mayday from Piper AlphaThe OIM could not see any flames so he did not shut downthe production but instructed his production supervisor tomonitor the gas pressure on the pipeline to PiperProduction was maintained on Tartan in the belief that Piperwas still producing (no telephone contact was possible)10:25 the production supervisor was informed of a largeexplosion on Piper. This explosion was in fact caused by thehydrocarbons from Tartan 81. The emergency control was finally shut down and it took 5-10minutes before the Tartan OIM asked for their gas line to bedepressurized and for the oil production to be shut down 82. ConclusionThe Piper Alpha disaster demonstrated the need for propertraining for the responsibility in this kind of positionThis is just one of many crisis that have highlighted the needfor organizations to competent to deal with major crisisCrisis Management is primarily dependent on the decision-makingof those in key command positions, at strategic,tactical and operational levelsThe immediate cause of the accident was due tocommunication problems relating to shift handover andPermit to Work proceduresThis crisis also shows the importancy of good organizationalcommunication and information routines 83. What if...There had been a proper shift-handover,proper marking of the safetyvalve that wasn`t functioning, orproper Permit to Work for this shift atthe Piper Alpha? 84. Risk evaluationRisk & unwanted incidents rankingSystems in place Report incidents and near miss Analyse material Look for trends 85. Risk definitionRisk=Practicable*ConsequenceRisk toPersonelEnvironmentMaterial 86. Mapping of HSE & risksRegister incidents: Positive andnegativeAdmin/Mgmt/QHSE, 303Marine,669Drilling,463Technical,175No name,50Catering,191Sub Sea,48Electrical,137Client, 137Visitors,123rd Party,592 87. Cause assesment Direct causes vs underlying causes Cause persepctive Human Technical Organisational 5 Whys technique Look for underlying causes Eliminate root of the problem 88. HSE analyseQRA: Quantity Risk AssesmentQRM: Qualitative Risk MatrixSafe job analysis ChemicalanalysisRisk assesment promt card 89. Risk reductionALARP: As Low As ReasonablePracticableBAT: Best Available TechnologyPrecation principlesSubstitution principles 90. Barriers swiss cheesemodelThe Barriere ConceptBARRIERS;Technical,Qualifications,Proceduresetc.ACCIDENT/ACCIDENT/LOSSLOSSINITIATINGINITIATINGCAUSECAUSE 91. We are all responsible for managingHSEHazard/RiskBarrier 1 HSE Policy & LeadershipBarrier 2 PlanningI was responsible forplanning theoperations safely 92. Hazard/RiskBarrier 1 HSE Policy & LeadershipI was responsiblefor supervising themaintenance workBarrier 2 PlanningBarrier 3 SupervisionI turned a blind eye tosome of the crew notfollowing all theprocedures as we hadlimited time to do the job 93. Hazard/RiskBarrier 1 HSE Policy & LeadershipBarrier 2 PlanningBarrier 3 SupervisionBarrier 4 ProceduresI didnt work safelyand took short-cutto get the job doneAccidentI was responsiblecompleting the work 94. We all have a part to playMaintenanceMaintain equipment andensure that operationalintegrity is maintainedHazards identifiedand risk mngt plansimplementedVisible leadershippromotes HSEculture ..Legal requirementsof projects identifiedand complied withCompetencies requiredfor job are clearlyidentifiedResources allocatedfor effectiveimplementationLegalIT/ Data/GraphicsHRMngt TeamSJA teamDrillingRisk management integratedto drilling programmeContractEnsure that Ocean Rig aregiven the means to performthe job safely and efficientlyHSE deptSystems to control andsecurely store HSEcritical informationGuidance andadvisory supportprovided tooperationsFinance/AccountingResource budgetseffectively trackedand managed 95. PressurePressure (the symbol: P) is the force per unit area appliedin a direction perpendicular to the surface of anobject. Gauge pressure is the pressure relative to the localatmospheric or ambient pressure.DefinitionPressure is the effect of a force applied to a surface.Pressure is the amount of force acting per unit area. Thesymbol of pressure is P 96. Pressure in fluids at restDue to the fundamental nature of fluids, a fluid cannotremain at rest under the presence of a shear stress.However, fluids can exert pressure normal to anycontacting surface. If a point in the fluid is thought of as aninfinitesimally small cube, then it follows from the principlesof equilibrium that the pressure on every side of this unit offluid must be equal. If this were not the case, the fluidwould move in the direction of the resulting force. 97. Thus, the pressure on a fluid at rest is isotropic; i.e., it actswith equal magnitude in all directions. This characteristicallows fluids to transmit force through the length of pipesor tubes; i.e., a force applied to a fluid in a pipe istransmitted, via the fluid, to the other end of the pipe.This concept was first formulated, in a slightly extendedform, by the French mathematician and philosopher BlaisePascal in 1647 and would later be known as Pascal's law.This law has many important applications in hydraulics. 98. Hydrostatic pressureSee also vertical pressure variation.Hydrostatic pressure is the pressure exerted by a fluid atequilibrium due to the force of gravity.[1] A fluid in thiscondition is known as a hydrostatic fluid. The hydrostaticpressure can be determined from a control volumeanalysis of an infinitesimally small cube of fluid. Sincepressure is defined as the force exerted on a test area(p = F/A, with p: pressure, F: force normal to area A, A:area), and the only force acting on any such small cube offluid is the weight of the fluid column above it, hydrostaticpressure can be calculated according to the followingformula: 99. For water and other liquids, this integral can be simplifiedsignificantly for many practical applications, based on thefollowing two assumptions: Since many liquids can beconsidered incompressible, a reasonably good estimationcan be made from assuming a constant density throughoutthe liquid. (The same assumption cannot be made within agaseous environment.) Also, since the height h of the fluidcolumn between z and z0 is often reasonably smallcompared to the radius of the Earth, one can neglect thevariation of g. Under these circumstances, the integralboils down to the simple formula: 100. where h is the height z-z0 of the liquid column between thetest volume and the zero reference point of the pressure.Note that this reference point should lie at or below thesurface of the liquid. Otherwise, one has to split theintegral into two (or more) terms with theconstant liquid and (z')above. For example, the absolutepressure compared to vacuum is 101. where H is the total height of the liquid column above thetest area the surface, and patm is the atmosphericpressure, i.e., the pressure calculated from the remainingintegral over the air column from the liquid surface toinfinity.Hydrostatic pressure has been used in the preservation offoods in a process called pascalization.[2] 102. Atmospheric pressureStatistical mechanics shows that, for a gas of constanttemperature, T, its pressure, p will vary with height, h, as:where: g = the acceleration due to gravityT = Absolute temperaturek = Boltzmann constantM = mass of a single molecule of gasp = pressureh = heightThis is known as the barometric formula, and may bederived from assuming the pressure is hydrostatic.If there are multiple types of molecules in the gas,the partial pressur 103. Pore pressureThe pressure of fluids within the pores of a reservoir, usuallyhydrostatic pressure, or the pressure exerted by a column ofwater from the formation's depth to sea level. Whenimpermeable rocks such as shales form as sediments arecompacted, their pore fluids cannot always escape and mustthen support the total overlying rock column, leading toanomalously high formation pressures. 104. If the rock has undergone a "normal" packing, we run therisk abnormally high pore pressures (includinghe abnormally high porosity).The pore liquid can not disappear out of the rock at the timeof deposition pressed together and matured.It requires dense materials, and therefore we find this mostoften in limestone and clayrocks. If there is a lot of sand present,the rock is much more permeable and pore liquid willeasier out under compression. 105. Darcy's lawDarcy's law is a phenomenologically derived constitutiveequation that describes the flow of a fluid througha porous medium. The law was formulated by HenryDarcy based on the results of experiments[1] on the flowof water through beds of sand. It also forms the scientific basis offluid permeability used in the earth sciences, particularlyin hydrogeology. 106. BackgroundAlthough Darcy's law (an expression of conservationof momentum) was determined experimentally byDarcy, it has since been derived from the Navier-Stokes equations via homogenization. It is analogousto Fourier's law in the field of heat conduction, Ohm'slaw in the field of electrical networks, or Fick'slaw in diffusion theory.One application of Darcy's law is to water flowthrough an aquifer; Darcy's law along with theequation of conservation of mass are equivalent tothe groundwater flow equation, one of the basicrelationships of hydrogeology. Darcy's law is alsoused to describe oil, water, and gas flows throughpetroleum reservoirs. 107. DescriptionDarcy's law is a simple proportional relationship betweenthe instantaneous discharge rate through a porousmedium, the viscosityof the fluid and the pressure dropover a given distance.Diagram showing definitionsand directions for Darcy'slaw. 108. The total discharge, Q (units of volume per time, e.g.,m/s) is equal to the product of the permeability of themedium, k (m2), the cross-sectional area to flow, A (unitsof area, e.g., m2), and the pressure drop (Pa), all dividedby the viscosity, (Pa.s) and the length the pressure dropis taking place over. The negative sign is needed becausefluids flows from high pressure to low pressure. So if thechange in pressure is negative (where Pa > Pb) then theflow will be in the positive 'x' direction. Dividing both sidesof the equation by the area and using more generalnotation leads to 109. where q is the flux (discharge per unit area, with units oflength per time, m/s) and is the pressuregradient vector (Pa/m). This value of flux, often referred toas the Darcy flux, is not the velocity which the watertraveling through the pores is experiencing. The porevelocity (v) is related to the Darcy flux (q) bythe porosity (n). The flux is divided by porosity to accountfor the fact that only a fraction of the total formation volumeis available for flow. The pore velocity would be thevelocity a conservative tracer would experience if carriedby the fluid through the formation. 110. Darcy's law is a simple mathematical statement whichneatly summarizes several familiar propertiesthat groundwater flowing in aquifers exhibits,including:If there is no pressure gradient over a distance, noflow occurs (these are hydrostatic conditions), if thereis a pressure gradient, flow will occur from highpressure towards low pressure (opposite the directionof increasing gradient - hence the negative sign inDarcy's law), the greater the pressure gradient(through the same formation material), the greater thedischarge rate, and the discharge rate of fluid willoften be different through different formationmaterials (or even through the same material, in adifferent direction) even if the same pressuregradient exists in both cases. 111. A graphical illustration of the use of the steady-stategroundwater flow equation (based on Darcy'slaw and the conservation of mass) is in theconstruction of flownets, to quantify the amountof groundwater flowing under a dam.Darcy's law is only valid for slow, viscous flow;fortunately, most groundwater flow cases fall in thiscategory. Typically any flow with a Reynoldsnumber less than one is clearly laminar, and it wouldbe valid to apply Darcy's law. Experimental tests haveshown that flow regimes with Reynolds numbers upto 10 may still be Darcian, as in the case ofgroundwater flow. The Reynolds number (adimensionless parameter) for porous media flow istypically expressed as 112. where is the density of water (units of mass pervolume), v is the specific discharge (not the porevelocity with units of length per time), d30 is arepresentative grain diameter for the porous media(often taken as the 30% passing size from a grainsize analysis using sieves - with units of length),and is the viscosity of the fluid. 113. Additional forms of Darcy's lawFor very short time scales, a time derivative of fluxmay be added to Darcy's law, which results in validsolutions at very small times (in heat transfer, this iscalled the modified form of Fourier's law), 114. where is a very small time constant which causesthis equation to reduce to the normal form of Darcy'slaw at "normal" times (> nanoseconds). The mainreason for doing this is that the regular groundwaterflow equation (diffusion equation) leadsto singularities at constant head boundaries at verysmall times. This form is more mathematicallyrigorous, but leads to ahyperbolic groundwater flowequation, which is more difficult to solve and is onlyuseful at very small times, typically out of the realm ofpractical use.Another extension to the traditional form of Darcy'slaw is the Brinkman term, which is used to accountfor transitional flow between boundaries (introducedby Brinkman in 1947), 115. where is an effective viscosity term. This correctionterm accounts for flow through medium where thegrains of the media are porous themselves, but isdifficult to use, and is typically neglected.Another derivation of Darcy's law is used extensivelyin petroleum engineering to determine the flowthrough permeable media - the most simple of whichis for a one dimensional, homogeneous rockformation with a fluid of constant viscosity. 116. where Q is the flowrate of the formation (in units ofvolume per unit time), k is the relative permeability ofthe formation (typically in millidarcies), A is the cross-sectionalarea of the formation, is the viscosity ofthe fluid (typically in units of centipoise, and L isthe length of the porous media the fluid will flowthrough. represents the pressure change per unitlength of the formation. This equation can also besolved for permeability, allowing for relativepermeability to be calculated by forcing a fluid ofknown viscosity through a core of a known length andarea, and measuring the pressure drop across thelength of the core. 117. Hole sections and welltrajectoryDrilling starts with 36 "holes down to 60-100mCasing (30 ") at an early stage because of the dangerof infill of soft sediments. Casing is cast ontothe formation of cement on the outside.Next section is drilled with a 26 "crown to depths ofbetween 400-800m. Casing (20 ") is the samewith cement on the outside.On top of this place BOP 118. Production pipe cold tubing placed inside the well, alittle above the bottom.At the bottom is a "production packer" placed.100-500 from the top of the subsurface safety valve(surface controlled sub surfacevalve, SCSSV) locatedto ensure accidental outflow from the well.At the top is placed a valvesystem (production street) where we can controlproduction. 119. Next section is drilled with a 17 crown andcasing at 13 5/8Often the last section with 12 crown and9 5 /8" casing. We are now down in the reservoirand the well can be prepared for production.In some wells we drill even a section before thereservoir is reached. This section is drilled with8 "crown andcasing 7". It is plain that this casing mounted on the 95 / 8"casing. This called for the liner. 120. Units 121. Well controlPrimary well control is the name of theprocess which maintains a hydrostaticpressure in the well bore greater thanthe pressure of the fluids in theformation being drilled, but less thanthe formation fracture pressure. Ifhydrostatic pressure is less thanformation pressure then formationfluids will enter the well bore. 122. If the hydrostatic pressure in thewellbore exceeds the fracturepressure of the formation pressurethen the fluid in the well will be lost. Inan extreeme case of lost circulationthe formation pressure may exceedhydrostatic pressure allowingformation fluid enter the well. 123. An over balance of hydrostaticpressure over formation pressure ismaintained, this excess is generallyreferred to as trip margin. 124. Secondary Well ControlIf the pressure of the fluids in thewellbore (i.e. mud) fail to preventformation fluids entering the wellbore,the well will flow. Thisprocess is stoppedusing a blow outpreventer to preventthe escape of wellborefluids from the well. 125. This is the initial stage of secondarywell control. Containment of unwantedformation fluids. 126. Tertiary well controlTertiary well control describes the thirdline of defence. Where the formationcannot be controlled primary orsecondary well control (hydrostaticand equipment). An undergroundblowout for example. However in wellcontrol it is not allways used asqualitative term. Unusual well controloperations listed below areconsidered under this term: 127. a) A kick is taken with the kick offbottomb) The drill pipe plugs of during a killoperationc) There is no pipe in the holed) Hole in drill stringe) Lost circulationf) Excessive casing pressureg) Plugget and stuck off bottomh) Gas percolation without gasexpansion 128. We could also include operations likestripping or snubbing in the hole, ordrilling relief wells. The point toremember is what is the well status atshut in? This determines the methodof well control. 129. Formation pressureFormation pressure or pore pressureis said to be normal when it is causedsolely by the hydrostatic head of thesubsurface wather contained in theformations and there is pore to porepressure communication with theatmosphere. 130. Dividing this pressure by the true verticaldepth gives an average pressuregradient of the formation fluid, normallybetween 0.433 psi/ft and 0.465 psi/ft.The North Sea area pore pressureaverages 0.452 psi/ft. In the absence ofaccurate data, 0.465 psi/ft which is theaverage pore pressure gradient in theGulf of Mexico is often taken to be thenormal pressure gradient.Note: The point at which atmosphericcontact is established may notnecessarily be at sea-level or rig sitelevel. 131. Normal formation pressureNormal formation pressure is equal tothe hydrostatic pressure of waterextenting from the surface to thesubsurface formation. Thus the normalformation pressure gradient in anyarea will be equal to the hydrostaticpressure gradient of the wateroccupying the pore spaces of thesubspace formation in that area. 132. The magnitude of the hydrostaticpressure gradient is affected by theconcentration of dissolved solids(salts) and gases in the formationwater.Increasing the dissolved solids (highersalt concentration) increases theformation pressure gradient whilst anincrease in the level of gases insolution will decrease the pressuregradient. 133. Abnormal pressureEvery pressure whis does not conform withthe definition given for normal pressure isabnormal.The principal causes of abnormal pressuresare:Under compaction in shalesWhen first deposited, shale has a highporosity. More than 50% of the total volumeof uncompacted clay-mud may consist ofwater in which it is laid. During normalcompaction, a gradual reduction in porosityaccompanied by a loss of formation water issqueezed out. As a result, water must beremoved from the shale before further 134. Not all of the expelled liquid is water,hydrocarbons may also be flushed fromthe shale.If the balance between the rate ofcompanction and fluid expulsion isdisrupted such that fluid removal isimpeded then fluid pressures within theshale will increase. The inability of shaleto expel water at a sufficient rate resultsin a much higher porosity than expectedfor the depth of shale burial in that area. 135. Salt bedsContinous salt depositions over largeareas can cause abnormal pressures.Salt is totally impermeable to fluids andbehave plastically. It deforms and flowsby recrystallisation. Its properties ofpressure transmission are more likefluids than solids, thereby exertingpressures equal to the overburden loadin all directions. The fluids in theunderlying formations cannot escape asthere is no communication to the surfaceand thus the formations become overpressured. 136. MineralisationThe alteration of sediments and theirconstituent minerals can result invariations of the total volume of theminerals present. An increase in thevolume of these solids will result in anincreased fluid pressure. An exampleof this occurs when anhydrite is laiddown. If it later takes on watercrystallisation, its structure changes tobecome gysum, with a volumeincrease of around 35%. 137. Tectonic causesIs a compacting force that is appliedhorizontally in subsurface formation. Innormal pressure environments water isexpelled from clays as they are beingcompacted with increasing overburdenpressures. If however an additional horizontalcompacted with increasing overburdenpressures. If however an additional horizontalcompacting force squeezes the clays laterallyand if fluids are not able to escape at a rateequal to the reduction in pore volume theresult will be an increase in pore pressure. 138. Formation fracture pressureIn order to plan to drill a well safely itis necessary to have some knowledgeof thefracture pressures of the formation tobe encountered. The maximumvolume of any uncontrolled influx tothe wellbore depends on the fracturepressure of the exposed formations. 139. Formation fracture pressureIn order to plan to drill a well safely itis necessary to have some knowledgeto the fracture pressures of theformation to be encountered. Themaximum volume of any uncontrolledinflux to the wellbore depends on thefracture pressure of the exposedformations. 140. If well bore pressures were to equal or exceed thisfracture pressure, the formation would break down asfracture was initiated, followed by loss of mud, loss ofhydrostatic pressure and loss of primary control.Fracture pressures are related to the weight of theformation matrix (Rock) and the fluids (water/ oil)occupying the pore space with in the matrix, above thezone of interest. These who factors combine to producewhat is known as the overburden pressure. Assumingthe average density of a thick sedimentary sequence tobe the equivalent of 19.2 ppg then the overburdengradient is given by0.052 * 19.2 = 1.0 psi/ftSince the degree of compaction of sediments is knownto vary with depth the gradient is not constant. 141. Onshore, since the sediments tend tobe more compacted, the overburdengradient can be taken as being closeto 1.0 psi/pf due to the effect of thedepth of seawater and largethicknesses of unconsolidatedsediment. This makes surface casingseats in offshore wells much morevulnerable to break down and is thereason why shallow gas kicks shouldnever be shut in. 142. Leak-off testsThe leak-off test establishes apractical value for the input intofracture pressure predictions andindicates the limit of the amount ofpressure that can be applied to thewellbore over the next section of holedrilled. It provides the basic dataneeded for further fracture calculationsand it also tests the effectiveness ofthe cement job. 143. The test is performed by applying anincremental pressure from the surface to theclosed wellbore/ casing system until it can beseen that fluid is being injected into theformation. Leak-off tests should normally betaken to this leak-off pressure unless itexceeds the pressure to which the casingwas tested. In some instances as whendrilling development wells this might not benecessary and a formation competecy test,where the pressure is only increased to apredermined limit, might be all that isrequired. 144. Leak-off test procedureBefore starting, gauges should bechecked for accuracy. The upperpressure limit should be determined.1. The casing should be tested prior todrilling out the shoe2. Drill out the shoe and cement,exposing 5-10 ft of new formation3. Circulate and condition the mud,check mud density in and out 145. 4. Pull the bit inside the casing. Line up cementpump and flush all lines to be used for the test.5. Close BOPs6. With the well closed in, the cement pump isused to pump a small volume at a time into thewell typically a or bbl per min. Monitor thepressure build up and accurately record thevolume of mud pumped. Plot pressure versusvolume of mud pumped7. Stop the pump and when any deviation fromlinearity is noticed between pump pressure andvolume pumped8. Bleed off the pressure and establish theamounts of mud, if any, lost to the formation 146. Working example of leak-off testprocedure (floating rigs)Operational drilling procedures forfloating rigs is designed to determinethe equivalent mud weight at whichthe formation will accept fluid. Thistest is not designed to bread down orfracture the formation. This test isnormally performed at each casingshoe 147. Prior to the formation leak-off, havehandy a piece of graph paper, penciland straight edge (ruler). Utilising thehigh pressure cement pumping unit,perform leak-off as follows: 148. 1. Upon drilling float equipment, cleanout rat hole and drill 15 ft of newhole. Circulate and condition holeclean. Be assured mud weight in andmud weight out balance for mostaccurate results.2. Pull bit up to just above casing shoe.Install head on DP 149. 3. Rig up cement unit and fill lines withmud. Test lines to 2500 psi. Breakcirculation with cement unit, beassured bit nozzles are clear. Stoppumping when circulation established.4. Close pipe rams. Position and setmotion compensator, overpull drillpipe(+/- 10,000 lbs), close choke/ killvalves. 150. 5. At slow rate (1/4 or BPM), pumpmud down DP6a Pump bbl record pressure ongraph paperb Pump bbl record pressure ongraph paperc Pump bbl record pressure ongraph paper 151. d Pump bbl record pressure ongraph papere Pump bbl record pressure ongraph paperf Continue this slow pumping. Recordpressure at bbl increments until twopoints past leak-off.g Upon two points above leak-off, stoppumping. Allow pressure to stabilize.Record this stabilized standing pressure(normally will stabilixe after 15 mins orso) 152. h Bleed back pressure into cementunit tanks. Record volume of bleedbacki Set and position motioncompensator, open rams.j Rig down and cement unit lines.Proceed with drilling operations.k Leak-off can be repeated after step6 if data confirmation is required,otherwise leak-off test is complete. 153. Note: For 20 and 13 3/8 csg leak-offtests, plot pressure every bbl. Resultswill be the same.It should be noted that in order to obtainthe proper leak-off and pumping rateplot, it will be necessary to establish acontinous pump rate at a slow rate inorder to allow time to read the pressureand plot the point on the graph. (Barrelspumped vs. pressure-psi), normally BPM is sufficient time. 154. A pressure gauge of 0-2000 psi with20 or 25 increments is recommended.Note: In the event Standing Pressureis lower than leak-off point. Usestanding pressure to calculateequivalent mud weight. Always notevolume of mud bled back into tanks. 155. Rig components 156. An introduction to petroleum geologySedimentologyThe great majority of hydrocarbon reserves worldwideoccur in sedimentary rocks.It is therefore vitally important to understand the nature anddistribution of sediments as potential hydrocarbon sourcerocks and reservoirs. Two main groups of sedimentary rocksare of major importance as reservoirs, namely siltstones andsandstones (clastic sediments) and limestones anddolomites (carbonates). Although carbonate rocks formthe main reservoirs in certain parts of the world (e.g. in theMiddle East, where a high proportion of the worlds giantoilfields are reservoired in carbonates), clastic rocks formthe most significant reservoirs throughout most of theworld. 157. CLASSIFICATION OF SEDIMENTARYROCKS 158. Texture in Granular SedimentsThe main textural components of granular rocks include:grain sizegrain sortingpackingsediment fabricgrain morphologygrain surface texture 159. Grain size 160. Sorting 161. Grain shape 162. Packing 163. Sand and sandstoneSands are defined as sediments with a mean grain sizebetween 0.0625 and 2 mm which, on compaction andcementation will become sandstones. Sandstones form thebulk of clastic hydrocarbon reservoirs, as they commonlyhave high porosities and permeabilities.Sandstones are classified on the basis of their composition(mineralogical content) and texture (matrix content). The mostcommon grains in sandstones are quartz, feldspar andfragments of older rocks. These rock fragments may includefragments of igneous, metamorphic and older sedimentaryrocks. 164. Classification of sands and sandstones 165. PorosityTotal porosity () is defined as the volume of void (pore)space within a rock, expressed as a fraction or percentage ofthe total rock volume. It is a measure of a rocks fluid storagecapacity.The effective porosity of a rock is defined as the ratio of theinterconnected pore volume to the bulk volumeMicroporosity (m) consists of pores less than 0.5 microns insize, whereas pores greater than 0.5 microns formmacroporosity (M) 166. PermeabilityThe permeability of a rock is a measure of its capacity totransmit a fluid under a potential gradient (pressure drop).The unit of permeability is the Darcy, which is defined byDarcys Law. The millidarcy (1/1000th Darcy) is generallyused in core analysis. 167. Controls on Porosity andPermeabilityThe porosity and permeability of the sedimentary rockdepend on both the original texture of a sediment and itsdiagenetic history. 168. Grain sizeIn theory, porosity is independent of grain size, as it ismerely a measure of the proportion of pore space in the rock,not the size of the pores. In practice, however, porositytends to increase with decreasing grain size for tworeasons. Finer grains, especially clays, tend to have lessregular shapes than coarser grains, and so are often lessefficiently packed. Also, fine sediments are commonly bettersorted than coarser sediments. Both of these factors resultin higher porosities.For example, clays can have primary porosities of 50%-85%and fine sand can have 48% porosity whereas the primaryporosity of coarse sand rarely exceeds 40%.Permeability decreases with decreasing grain size becausethe size of pores and pore throats will also be smaller,leading to increased grain surface drag effects. 169. Porosity: Function of grain sizeand sorting 170. Grain Shape The more unequidimensional the grain shape, the greater theporosity As permeability is a vector, rather than scalar property, grainshape will affect the anisotropy of the permeability. The moreunequidimensional the grains, the more anisotropic thepermeability tensor.Packing The closer the packing, the lower the porosity andpermeabilityFabric Rock fabric will have the greatest influence on porosity andpermeability when the grains are non spherical (i.e. are eitherdisc-like or rod-like). In these cases, the porosity andpermeability of the sediment will decrease with increasedalignment of the grains.Grain Morphology and Surface Texture The smoother the grain surface, the higher the permeability 171. Diagenesis (e.g. Compaction,Cementation)Diagenesis is the totality of physical and chemicalprocesses which occur after deposition of asediment and during burial and which turn thesediment into a sedimentary rock. The majority ofthese processes, including compaction,cementation and the precipitation of authigenicclays, tend to reduce porosity and permeability,but others, such as grain or cement dissolution,may increase porosity and permeability. In general,porosity reduces exponentially with burial depth,but burial duration also an important criterion.Sediments that have spent a long time at greatdepths will tend to have lower porosities andpermeabilities than those which have been rapidlyburied. 172. Changes of porosity with burialdepth 173. Drilling bits 174. Wireline operations at Varg A 175. Measurement While Drilling