Well engineering and construction ch 7, 8, 9, 10, 16 17

Well Engineering & Construction 24 Kilometers Hussain Rabia Index Well Engineering & TOC Previous Next Table of Contents Construction Chapter : Pore Pressure Chapter : Formation Integrity Tests 49 Chapter : Kick Tolerance 71 Chapter : Casing Properties 101 Chapter : Casing Design Principles 145 Chapter : Cementing 203 Chapter : Drilling Fluids 267 Chapter : Practical Rig Hydraulics 305 Chapter : Drill Bits 339 Chapter 10 : Drillstring Design 383 Chapter 11 : Directional Drilling 443 Chapter 12 : Wellbore Stability 531 Chapter 13 : Hole Problems 575 Chapter 14 : Horizontal & Multilateral Wells 631 Chapter 15 : High Pressure & High Temperature Wells 681 Chapter 16 : Rig Components 717 Chapter 17 : Well Costing 749 Well Engineering &Construction i TOC Previous Next D RILLING F LUIDS Contents Drilling Fluid Selection: data Requirements Drilling Fluid Functions Drilling Fluid Additives Drilling Fluid Types Drilling Mud Properties Drilling Fluid Problems Solids Control Equipment Learning Milestones I.N .T .R O D .U .C T I O N Drilling mud is one of the most important elements of any drilling operation The mud has a number of functions which must all be optimised to ensure safety and minimum hole problems Failure of the mud to meet its design functions can prove extremely costly in terms of materials and time, and can also jeopardise the successful completion of the well and may even result in major problems such as stuck pipe, kicks or blowouts There are basically two types of drilling mud: water-based and oil-based, depending on whether the continuous phase is water or oil Then there are a multitude of additives which are added to either change the mud density or change its chemical properties 1.0 D RILLING F .LUID S .ELECTION : DATA R .EQUIREMENTS The following information should be collected and used when selecting drilling fluid or fluids for a particular well It should be noted that it is common to utilise two or three different fluid types on a single well Well Engineering &Construction 267 TOC DRILLING FLUIDS Drilling Fluid Functions Previous Next • Pore pressure /fracture gradient plots to establish the minimum / maximum mud weights to be used on the whole well, see Chapters One and Two for details • Offset well data (drilling completion reports, mud recaps, mud logs etc.) from similar wells in the area to help establish successful mud systems, problematic formations, potential hazards, estimated drilling time etc • Geological plot of the prognosed lithology • Casing design programme and casing seat depths The casing scheme effectively divides the well into separate sections; each hole section may have similar formation types, similar pore pressure regimes or similar reactivity to mud • Basic mud properties required for each open hole section before it is cased off • Restrictions that might be enforced in the area i.e government legislation in the area, environmental concerns etc 2.0 D RILLING F .LUID F .UNCTIONS The drilling mud must perform the following basic functions: To control sub-surface pressures by providing hydrostatic pressure greater than the formation pressure This property depends on the mud weight which, in turn, depends on the type of solids added to the fluid making up the mud and the density of the continuous phase To remove the drilled cuttings from the hole The removal of cuttings depends on the viscous properties called "Yield Point" which influences the carrying capacity of the flowing mud and "gels" which help to keep the cuttings in suspension when the mud is static The flow rate of mud is also critical in cleaning the hole To cool and lubricate the drill bit and drillpipe 268 Well Engineering & Construction Drilling Fluid Additives TOC Previous Next DRILLING FLUIDS To prevent the walls of the hole from caving This function is provided by the formation of a stable mud cake on the walls of the wellbore, somewhat like plastering the walls of a room to keep them from flaking To release the drilled cuttings at the surface To prevent or minimise damage to the formations penetrated by having minimum fluid loss into the formation To assist in the gathering of the maximum information from the formations being drilled To suspend the cuttings and weighing material when circulation is stopped (gelation) This property is provided by gels and low shear viscosity properties To minimise the swelling stresses caused by the reaction of the mud with the shale formations This reaction can cause hole erosion or cavings resulting in an unstable wellbore (See Chapter 13 ) Minimisation of wellbore instability is provided by the "inhibition" character of the drilling mud The chemical additives required to achieve the above functions will be explained in the following section 3.0 D RILLING F .LUID A .DDITIVES There are many drilling fluid additives which are used to develop the key properties of the mud The variety of fluid additives reflect the complexity of mud systems currently in use The complexity is also increasing daily as more difficult and challenging drilling conditions are encountered We shall limit ourselves to the most common types of additives used in water-based and oilbased muds These are: • Weighting Materials Well Engineering & Construction 269 DRILLING FLUIDS TOC Weighting Materials Previous Next • • • • • • • Viscosifiers Filtration Control Materials Rheology Control Materials Alkalinity and pH Control Materials Lost Circulation Control Materials Lubricating Materials Shale Stabilizing Materials WEIGHTING MATERIALS 3.1 Weighting materials or densifers are solids material which when suspended or dissolved in water will increase the mud weight Most weighting materials are insoluble and require viscosifers to enable them to be suspended in a fluid Clay is the most common viscosifier Mud weights higher than water (8.3 ppg) are required to control formation pressures and to help combat the effects of sloughing or heaving shales that may be encountered in stressed areas Table 7.1 gives a list of the most commonly used weighting materials The specific gravity of the material controls how much solids material (fractional volume) is required to produce a certain mud weight For example, to produce a mud weight of 19 ppg (2.28 gm/cc), the solids content from using only barite (sg = 4.2) is 39.5% compared with haematite (sg = 5.2) with solids content of 30% Table 7.1 : Materials used as densifiers, After Reference Material Principal Component Specific Gravity %Acid Soluble Galena PbS 7.4-7.7 Haematite Fe2O3 4.9-5.3 50+ Magnetite Fe3O4 5.0-5.2 Illmenite FeO.TiO2 4.5-5.1 20 Barite BaSO4 4.2-4.6 Siderite FeCO3 3.7-3.9 95+ 270 Well Engineering & Construction Weighting Materials TOC Previous Next Celestite SrSO4 3.7-3.9 Dolomite CaCO3.MgCO3 2.8-2.9 99 Calcium Carbonate CaCO3 2.6-2.8 99 3.1.1 DRILLING FLUIDS DESCRIPTION OF MOST COMMONLY USED WEIGHTING MATERIALS Barite Barite (or barytes) is barium sulphate, BaSO4 and it is the most commonly used weighting material in the drilling industry Barium sulphate has a specific gravity in the range of 4.20 4.60 The specific gravity of Most commercial barite contain impurities including quartz, chert, calcite, anhydrite, and various silicates which slower its specific gravity It is normally supplied to a specification where the specific gravity is about 4.2 Barite is preferred to other weighting materials because of its low cost and high purity Barite is normally used when mud weights in excess of 10 ppg are required Barite can be used to achieve densities up to 22.0 ppg in both water- based and oil -based muds However, at very high muds weights (22.0 ppg), the rheological properties of the fluid become extremely difficult to control due to the increased solids content Iron Minerals Iron ores have specific gravities in excess of They are more erosive than other weighting materials and may contain toxic materials The mineral iron comes from several iron ores sources including: haematite/magnetite, illmenite and siderite The most commonly used iron minerals are: Iron Oxides: principally haematite, Fe2O3 Haematite can be used to attain densities up to 22.0 ppg in both water- based and oil -based drilling fluids Iron oxides have several disadvantages including: magnetic behaviour which influences directional tool and magnetic logs, toxciticity and difficulty in controlling mud properties Well Engineering & Construction 271 TOC DRILLING FLUIDS Weighting Materials Previous Next Iron Carbonate: Siderite is a naturally occurring ferrous carbonate mineral (FeCO3) It has a specific gravity ranging from 3.70 - 3.90 Both water- based and oil- based muds can be successfully weighted with siderite to 19.0 ppg Illmenite: The mineral illmenite, ferrous titanium oxide (FeTiO3), has a specific gravity of 4.60 It is inert but abrasive Ilmenite can be used to attain densities up to 23.0 ppg in both water-based and oil- based drilling fluids Illmenite is the main source of titanium Calcium Carbonates Calcium carbonate (CaCO3) is one of the most widely weighting agents especially in nondamaging drilling fluids Its main advantage comes from its ability to react and dissolve in hydrochloric acid Hence any filter cake formed on productive zones can be easily removed thereby enhancing production It has a specific gravity of 2.60 - 2.80 which limits the maximum density of the mud to about 12.0 ppg Calcium carbonate is readily available as ground limestone, marble or oyster shells Dolomite is a calcium - magnesium carbonate with a specific gravity of 2.80 - 2.90 The maximum mud density achieved is 13.3 ppg Lead Sulphides Galena (PbS) has a specific gravity of 7.40 - 7.70 and can produce mud weights of up to 32 ppg Galena is expensive and toxic and is used mainly on very high pressure wells Soluble Salts Soluble salts are used to formulate solids free fluids and are used mainly as workover and completion fluid Depending on the type of salt used, fluid densities ranging from 9.0 - 21.5 ppg (sg =1.08 - 2.58) can be prepared Table 7.2 gives the maximum densities that can be attained for single salt systems Table 7.2 Maximum Densities Of Single Salt Brines, After Baroid Material 272 Well Engineering & Construction g/cm3 lb/gal Viscosifiers TOC Previous Next Potassium Chloride (KCl) 1.16 9.7 Sodium Chloride (NaCl) 1.20 10.0 Sodium Formate (NaHCO2) 1.33 11.1 Calcium Chloride (CaCl2) 1.42 Potassium Formate (KHCO2) 1.60 Calcium Bromide (CaBr2) 1.85 15.4 Caesium Formate 2.36 19.7 Zinc Bromide (ZnBr2) 2.46 20.5 3.2 DRILLING FLUIDS 11.8 13.3 VISCOSIFIERS The ability of drilling mud to suspend drill cuttings and weighting materials depends entirely on its viscosity Without viscosity, all the weighting material and drill cuttings would settle to the bottom of the hole as soon as circulation is stopped One can think of viscosity as a structure built within the water or oil phase which suspends solid material In practice, there are many solids which can be used to increase the viscosity of water or oil The effects of increased viscosity can be felt by the increased resistance to fluid flow; in drilling this would manifest itself by increased pressure losses in the circulating system A list of some of the materials used to provide viscosity to drilling fluids is given in Table 7.3 We will begin our discussion of viscosifers with clay minerals Table 7.3 Materials used as viscosifiers, After Reference Material Bentonite CMC PAC Xanthan Gum HEC Guar Gum Resins Silicates Synthetic Polymers Principal Component Sodium/Calcium Aluminosilicate Sodium Carboxy-methyle cellulose Poly anionic Cellulose Extracellullar Microbial Polysaccharide Hyroxy-ethyl Cellulose Hydrophilic Polysaccharide Gum Hydrocarbon co-polymers Mixed Metal Silicates High molecular weight Polyacrylamides/polyacrylates Well Engineering & Construction 273 TOC DRILLING FLUIDS Viscosifiers Previous Next 3.2.1 CLAYS Clays are defined as natural, earthy, fine-grained materials that develop plasticity when wet They are formed from the chemical weathering of igneous and metamorphic rocks The major source of commercial clays is volcanic ash; the glassy component of which readily weathers very readily, usually to bentonite A clay particle has a characteristic atomic structure in which the atoms form layers, see Figure 7.1 There are three layers which give the clays their special properties: • tetrahedral layers: These are made up of a flat honeycomb sheet of tetrahedra containing a central silicon atom surrounded by four oxygens The tetrahedra are linked to form a sheet by sharing three of their oxygen atoms with adjacent tetrahedra • Octahedral layers: These are sheets composed of linked octahedras, each made up of an aluminium or magnesium atom surrounded by six oxygens Again, the links are made up by sharing oxygen atoms between two or three neighboring octahedras • Exchangeable layers: These are layers of atoms or molecules bound loosely into the structure, which can be exchanged with other atoms or molecules These exchangeable atoms or molecules are very important as they give the clays their unique physical and chemical properties The nature of the above layers and the way they are stacked together define the type of clay mineral For this reason, they are several types of clays available The most widely used clay is bentonite Bentonite This is the most widely used additive in the oil industry The name, bentonite, is a commercial name used to market a clay product found in the Ford Benton shale in Rock Creek, Wyoming, USA Bentonite is defined as consisting of fine-grained clays that contain not less than 85% Montmorillonite which belongs to the class of clay minerals known as smectites Bentonite 274 Well Engineering & Construction WE L L C O S T I N G 17 TOC Estimation of P50 Value Previous Next Table 17.4 gives detailed time estimates for every individual operation on the 36” hole / 30“conductor based on the best times recorded in the area Because of the way the P10 value is derived, it is unlikely that this value can be met exactly more than 10% of the time Indeed, some may argue that it is more difficult to produce a P10 value than a P50 value After all, the P50 value is based on the most likely time to carry out a given operation which can be easily established 8.5 ESTIMATION OF P50 VALUE Assume that the approach for calculating well costs was based on first estimating the P10 value The P50 value should then be derived from the assumed P10 value This P50 probability of any event occurring should be derived from “engineering judgment” by the drilling engineer and is an estimate of the normal expected occurrence frequency for that event As an example, consider the top hole section in an offshore operation where 36” hole is drilled and 30” conductor is run and cemented The following events may occur and increase drilling time: Potential Problem Time Implication P50 of Problem Result Occurring Boulder in 36” hole Cement job on 30” conductor slump Boulder double drilling time Losses during cement job requiring two top jobs This may happen on a new rig or with new crew 10% hrs rig time 40% hours rig time 0.1 20% hours rig time 0.05 Problems rigging up diverter Total 766 Well Engineering & Construction Time Delay (result x prob) ( days) 0.02 0.17 days TOC Previous Next WE L L C O S T I N G Estimation of P90 Value Hence if the P10 time for drilling 36” hole, running and cementing 26” conductor is 1.5 days, then the P50 value is: 1.5 + 0.17 =1.67 days The same logic can be applied to all hole sections citing all known hole and equipment problems and assigning probabilities to them The reader should not take this approach as a license to increasing drilling time but merely to obtain realistic drilling times Indeed, the P50 estimate obtained should be close to the average drilling time in the area The onus is on the engineers and crews to approach the P10 value and may even improve upon it This can be achieved by innovation through improved well designs, modification of equipment or new practices such as “Technical Limit Drilling” on page 768 8.6 ESTIMATION OF P90 VALUE Applying the same approach as for the P50 value, the P90 for the 36” hole may be derived as follows: Potential Problem Boulder in 36” hole Cement job on 30” conductor slump Problems rigging up diverter Time Implication P90 of Problem Occurring Boulder double 30% drilling time Losses during 50% cement job requiring two top jobs This my 40% happen on a new rig or with new crew Result hrs rig time Time Delay (result x prob) ( days) 0.05 hours rig time 0.13 hours rig time 0.1 Total 0.28 days The P90 value is the P10 value plus 0.28 days, i.e 1.78 days Well Engineering & Construction 767 17 TOC WE L L C O S T I N G Technical Limit Drilling Previous Next It is recommended that for each area, a list of potential problems is complied and probabilities of problems occurring are established to help in future cost estimates The reader should note that drilling operation follow a learning curve where the first well typically takes longer than the average well and the last few wells take less time than the average 9.0 T .ECHNICAL L .IMIT D .RILLING Technical Limit Drilling (TLD) is defined as follows: A theoretical limit representing a stretched target of what is theoretically possible in a perfect world where both ideal and optimised drilling conditions The difference between historical performance and TLD represents an opportunity to reduce costs Traditionally, planning time for well engineering has been very small in comparison with other industries as shown below: Planning Time Comparison 1.Construction industry spends up to 15% of its budget on up front planning 2.Drilling industry spends less than 5% on well engineering TLD requires very detailed planning of every aspect of the drilling operation and this usually requires every process to be broken down into its smallest possible constituent and the time for each constituent to be established 9.1 BASIS OF TLD TLD requires detailed numerical answers to the following questions: 768 Well Engineering & Construction Basis of TLD TOC Previous Next 1.What is the current performance? This gives the normal average 2.What is possible? This gives the theoretical limit 3.What is needed to get there? This determines the resource investment to achieve TLD WE L L C O S T I N G Figure 17.2 Technical Limit Time Invisible Lost Time Conventional NPT Total Historical Drilling Time TLD requires that drilling estimates are made without the inclusion of invisible lost time or non-productive time, Figure 17.2 Non productive time was discussed in detail in “Non Productive Time (NPT)” on page 762 Invisible Lost Time: This time is usually absorbed in productive time and is made up of the total of previously acceptable wasteful events such as 3: Use of sub-optimal equipment Lack of personnel Application of sub-optimal operations and procedures Examples of invisible lost time 3: Bit trips before reaching TD Wiper trips Check trips Mud conditioning Double checking directional motors and MWD tools Well Engineering & Construction 769 17 TOC WE L L C O S T I N G Cost Reduction Previous Next As an example of what can be achieved using the technical limit and unlimited number of experts, consider the process of changing the car’s tyres: A team of Formula One can change tyres in seconds It takes a garage mechanic 2- minutes to change one tyre It takes an ordinary driver 5-15 minutes to change one tyre In summary, time estimates for TLD are meant to use the limits of current technology with no restriction on equipment or personnel Clearly, TLD can only be applied by a very few companies that have very large resources.In the author’s opinion, most companies would opt to calculating the P10 value using the best performance from offset wells 10.0 COST REDUCTION The objective of all E&P companies is to drill and produce wells in the least possible time, consistent with safe operations In the oil industry, time really means money The longer an operation takes, the more it will cost This is because as you spend more time say on drilling operations, the company will be paying more money for equipment and people which will make the operation more expensive Also any delay to drilling operations will mean a delay to actual production If there is no production, there is no income and the company is not making money There are two elements of costs which must be controlled: Capital Expenditure (Capex): This includes the cost of finding and developing an oil/gas field The cost of drilling operations is the major cost element and must be kept to an acceptable value Operating Cost (OPEX): This includes the actual cost of production: cost of maintaining the platform, wells, pipelines etc We will not be concerned with these costs as they are part of production operations E&P companies aim to reduce time to develop fields in order to reduce CAPEX and OPEX At the time of writing this book, there are several ways of judging a minimum price per 770 Well Engineering & Construction TOC Previous Next WE L L C O S T I N G Drilling Contracting Strategies barrel of oil In the North Sea, it is accepted that the principle of 1/3/3 results in a profitable operation The 1/3/3 stands for: $1 for finding, $3 for developing and $3 for production This gives a combined cost of $7 per barrel In the Middle East, this combined cost can be as low as $2 for some giant fields In general the more remote the area the more expensive is the final cost of barrel of oil This is particularly true for deep waters in hostile environments The following is a list of measures to reduce costs: Technical innovation Productivity improvement: e.g faster drilling operations Increased operational effectiveness Incentive contracts (sharing gains and pains) Less people Cost reduction is a wide subject and is beyond the scope of this book We will only concentrate on the most important aspects relating to drilling operations, namely, drilling contracting strategies 11.0 DRILLING CONTRACTING STRATEGIES There are basically four types of contracts which are currently used in the oil industry: Conventional Integrated Services (IS) Integrated Project Management (IPM) Turn Key The type of drilling contract used can mean the difference between an efficient and a less efficient operation The operator must weigh all the relevant factors before opting to one of Well Engineering & Construction 771 17 TOC WE L L C O S T I N G Conventional Contract Previous Next the above strategies Indeed, going for one type, say turn key, can mean that the operator has no control over the operation whatsoever and has no means of building knowledge for future operations 11.1 CONVENTIONAL CONTRACT In this type of contract, the E&P company does every thing using its own staff or contractors This is the most involved type of contract and can mean handling up to 100 contracts per well In this contract, the operator has total control over the operation and carries full risk The contractor has no risk and it could be argued that the contractor has no incentive in speeding up the operation This type of contract has the advantage that lessons learnt during drilling operations are kept within the company and used to improve future operations Nowadays, only large operators opt for this type of contract A variation of the above contract is to include an incentive clause for completing operations early or if a certain depth is reached within an agreed time scale The contractor will be paid a certain percentage of the savings made if operations are completed ahead of the planned agreed drilling time 11.2 INTEGRATED SERVICES (IS) In this type of contract, major services are integrated under two or three main contracts These contracts are then given to lead contractors who, in turn, would subcontract all or parts of the contract to other subcontractor The lead contractor hold total responsibility for his contract and is free to choose its subcontractors The operator still holds major contracts such as rig, wellheads and casing Also the operator appoints one of its staff to act as a coordinator for the drilling operation 772 Well Engineering & Construction TOC Previous Next 11.3 WE L L C O S T I N G Integrated Project Management (IPM) INTEGRATED PROJECT MANAGEMENT (IPM) In this type of contract, a main contractor is chosen This contractor is the Integrated Project Management (IPM) contractor The contractor is responsible for 20-30 service companies Service companies may be responsible for other service companies The drilling operation will be controlled by a representative from the IPM contractor The operator may hold one or two major contracts There is also a built-in incentive in the contract between the IPM contractor and the operator This is either based on the time-depth curve, safety or other criteria An incentive contract based on beating the time curve is the most common one In this type, an agreed time-depth curve is first established If the IPM contractor beats this time curve, then he is eligible for all or a percentage of the savings In the author’s experience, this type is one of the worst kind of contracts for the operator because: 11.4 • There is virtually no learning for the operator Lessons learnt are lost as the IPM contractor traditionally has a large staff turnover Electronic means of gathering information and building knowledge bases are alleviating this problem However, there is no substitute for hands on experience of drilling problems and passing this knowledge to new staff and trainees • The incentive contract is built on a time-depth curve developed and based on the contractor’s experience Use of better equipment and personnel may beat the IPM contractor’s time-curve • Experience in drilling HPHT wells in the North Sea has shown that an operator can beat the P10 curve developed by any contractor Incentives are usually given to contractors when beating the P50 time -depth curve, which has a less stringent time estimate TURN KEY CONTRACT This is the easiest of all the above contracts The operator chooses a contractor The contractors submits a lump sum for drilling a well: from spud to finish with operator Well Engineering & Construction 773 17 TOC WE L L C O S T I N G Current And Future Trends In Drilling Contracts Previous Next virtually not involved The contractor carries all risks if the well comes behind time and also gains all benefits if he should drill the well faster Contractors only opt for this type of contract if they know the area extremely well or during times of reduced activities The operator opts for this type of contract if he has a limited budget or has no knowledge of drilling in the area 11.5 CURRENT AND FUTURE TRENDS IN DRILLING CONTRACTS There are two new development in drilling and production contracts: • Production Sharing Agreement • Capital Return Agreement Plus Agreed Production These new types of contracts were initially initiated in some Middle Eastern countries attempting to draw western investment These contracts are still developing in nature and have now been used by a number of third world countries A Production Sharing Agreement stipulates that the contractor will be paid a certain percentage of the produced fluids (oil or gas) in return for the services of the contractor in drilling and producing the wells The agreement may be time-dependent running for a fixed number of years or may include an initial payment for the contractor in addition to a percentage of the production A Capital Return Agreement Plus Agreed Production stipulates that the contractor will develop a field using his own finance In return, the operator (or national oil company) will pay the contractor all his capital expenditure plus an agreed percentage of the production In Iran where this type of contract is used, the agreed production is limited to a fixed number of years The ownership of the field and its facilities always remain with the operator 774 Well Engineering & Construction TOC Previous Next WE L L C O S T I N G Current And Future Trends In Drilling Contracts Table 17.5 AFE For Well Pak-1 Based On P50 Estimate Cost Description Comments Code Lump Unit Sum Cost Qty Days Sub Totals Totals SITE COSTS 110 Site Planning Survey 10,000 10,000 sub total 120 Site Construction 10,000 Road Construction Site Construction 1,816,079 1,816,079 Airstrip Construction Waterline Construction Constr'n Equip Mob Constr'n Equip Demob Road Maintenance Water Well Water Pump sub total 130 Site Reinstatement 1,816,079 15,000 15,000 sub total 15,000 1,841,079 RIG COSTS 201 Rig Operating Day rate 14,500 59.00 sub total 220 Rig Mob / Demob 230 Additional Rig Charges 855,500 690,000 690,000 sub total 690,000 94,027 94,027 sub total 240 855,500 94,027 Supervision 1,931 sub total 59 113,904 113,904 1,753,431 TANGIBLES 201 Casing 561,189 sub total 561,189 561,189 Well Engineering & Construction 775 17 TOC WE L L C O S T I N G Current And Future Trends In Drilling Contracts Previous Next 211 Wellhead & Accessories 84,775 sub total 221 84,775 84,775 Other Tangibles 25,000 sub total 25,000 25,000 670,964 MATERIALS/SUPPLIES 301 Rock Bits 305 Coreheads / Spares 218,428 sub total 218,428 sub total 310 Diamond / PDC bits 315 Mud Products 46,250 sub total Cement Products 325 Solids Ctrl Consumables 155,000 155,000 155,000 25,000 sub total 25,000 25,000 Other Materials / Supplies 35,000 sub total 335 350,000 350,000 sub total 330 46,250 46,250 350,000 sub total 320 218,428 35,000 35,000 Fuel & Lubes 180,000 sub total 180,000 180,000 1,009,678 TRANSPORTATION 410 Supply & standby boats N/A sub total 420 Air Support General 48,447 sub total 440 Shipping/Freight/Customs 48,447 General 181,474 sub total 450 Equipment Transport 181,474 181,474 Loads sub total 776 48,447 Well Engineering & Construction 300,000 300,000 300,000 529,921 TOC Previous Next WE L L C O S T I N G Current And Future Trends In Drilling Contracts SERVICES 501 Radio / Comms Services General 1,104 59 sub total 503 65,130 Rig Positioning sub total 506 Diving (ROV) sub total 509 Logging (wireline) 302,027 302,027 sub total 512 302,027 M.W.D 10,884 10,884 sub total 515 10,884 Downhole Motors 81,519 81,519 Personnel sub total 518 81,519 Solids Control Equipment 46406 46,406 sub total 521 46,406 Fishing 10,000 10,000 sub total 524 65,130 10,000 Mud Logging Unit & Personnel 1,610 59 95,013 0 sub total 527 95,013 Mud Engineering 1,371 50 sub total 530 Cementing 533 Jars & Shock Subs 68,567 75,645 59 30,000 59 sub total 539 75,645 75,645 sub total 536 68,567 30,000 30,000 Downhole tools 65,000 65,000 sub total 65,000 Directional Engineering sub total Well Engineering & Construction 777 17 TOC WE L L C O S T I N G Current And Future Trends In Drilling Contracts Previous Next 542 545 Directional Navig'n Tools sub total Surveying (inc Personnel) 23,525 23,525 sub total 548 Casing Services (inc Pers'l) 551 Other Equipment Rental 23,525 47,638 47,638 sub total 47,638 Miscellaneous Rentals 6,192 6,192 sub total 554 6,192 Other Services 720,000 720,000 sub total 720,000 1,647,546 BASE EXPENSES 620 Crane Hire 641 Local Labour / Land Lease 415 59 130 59 sub total sub total 642 Dockers not applicable Base Run Costs & Maint 662 Security 0 1,373 59 1,786 59 sub total sub total 663 7,662 7,662 sub total 661 Storage & Warehouse 80,994 80,994 105,389 105,389 sub total 664 Base Equipment & Repairs 665 General Base Expenses sub total sub total O/HEADS (DRILLING) 778 Well Engineering & Construction 0 194,045 Learning Milestones TOC Previous Next 652 Office Costs Drilling Management 20,000 WE L L C O S T I N G 20,000 sub total 20,000 20,000 O/HEADS (PET'L ENG.) 642 Petroleum Engineer Well Test Planning 10,000 10,000 sub total 10,000 10,000 GEOLOGICAL SERV'S 301 Wellsite Geology 845 59 sub total 302 Core Handling 303 Core Analysis 49,848 not applicable sub total not applicable sub total 335 Geochemistry 336 Biostratigraphic Analysis 10,000 10,000 sub total 10,000 8,000 8,000 sub total 337 8,000 Sedimentology 0 sub total 501 Data Transmission 87 59 sub total 610 49,848 Geology Dept Overheads sub total TOTAL WELL COST ESTIMATE 5,146 5,146 1,557 59 91,848 91,848 164,842 USD 7,841,505 12.0 LEARNING MILESTONES In this chapter, you should have learnt to: List factors affecting well costs Estimate drilling time Well Engineering & Construction 779 17 TOC WE L L C O S T I N G References Previous Next List elements of well costing Calculate well costs Understand Non Productive Time (NPT) Understand risked well cost estimates Understand Technical Limit Drilling Understand Drilling Contracting Strategies 13.0 REFERENCES Rabia H (2000) “Drilling Optimisation” Report on North Drilling Practices to various companies Rabia H (1997) “Risk assessment in cost estimation” various internal reports for BG International Schreuder J and Sharpe P“(1999) “Drilling the limit- a key to reduce well costs” SPE 57258, SPE Asia Pacific Improved Oil Recovery Conference, Kuala Lumpur, 25-26th October Rabia H (2001) “Drilling cost estimation” Entrac Seminars 780 Well Engineering & Construction