The first edition of the Drilling Data Handbook was printed in In more than six decades the book has got improved, adding lots of new technologies and. This book presents the fundamental principles of drilling en­ gineering, with the primary objective of making a good well using data that can be properly evaluated through geology, reservoir engineering, and management. It is written to assist the geologist, drilling engineer. An electronic version of the Field Data Handbook that displays data to help compute results fast, eliminating the time-consuming and error-prone practice of first.

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Drilling Hand Book

Views 28MB Size Report. This content was uploaded by our users and we assume good faith they have the permission to share this book. The first edition of the Drilling Data Handbook was published in Over the more than six following decades the book has been constantly improved, adding . This handbook has been altered you should engineers to help rig personnel do a better job. It summarizes proven drilling techniques and technical data that.

Foreword The first edition of the Drilling Data Handbook was published in Over the more than six following decades the book has been constantly improved, adding lots of new technologies and equipment over the course of its eight updated editions. But its key principle is to remain familiar and friendly to users. Its philosophy has always been to give quick access to the basic information or calculations for the office or field operations. That is why our primary goal is to select and highlight the most important data, charts and formulas. The Drilling Data Handbook combines international and field units for the benefit of a majority of industry professionals from different technical cultures. The success of past editions, along with the continued demand for updated information, have encouraged us to publish this new paper edition. A large number of field personnel have confirmed that they do use the Drilling Data Handbook as their primary reference, now in combination with electronic documents and the internet. This edition refreshes and updates data and references from the eighth edition, and also provides even more information.

Planning a Geothermal Well Overview There are two separate but closely related parts of preparing for a drilling project—planning the well and designing the well. Detailed instructions on how to complete this process for even a single well would need a sizable volume in itself; although that is well beyond the scope of this Handbook, the following discussion will present a sort of checklist that identifies many of the questions that must be considered during these preparations.

The geographical location of the well can have a major impact on cost, schedule, and even well design, but that choice is a function of exploration for the resource, and thus is too variable to be considered as a generic part of well planning. A special consideration in some regions is the possibility of encountering hydrocarbon resources while drilling the geothermal well.

If this is the case, it can affect casing design, rig selection, mud logging requirements, and many other aspects of the well plan. Careful planning is critical for any drilling operation. It will not only minimize cost, but will reduce the risk of injury or property damage from unexpected events. A drilling plan should list and define all the activities required to complete the well, with their related costs and times, and should give sufficient descriptions of individual tasks to make clear the sequence in which they must be performed.

The crux of this technique is that any delay along the chain of sequential operations — the critical path — will cause a delay in project completion, while delay in some other operation may not.

It is also essential that all the contractors and service companies should meet, or at least thoroughly communicate, during the planning stage, so that the plan assigns responsibilities for the various activities and there is no confusion as to what person or company performs each step.

Descriptions in the plan must be relatively detailed. For example, to specify drilling an interval between two given depths and running casing in it would typically require, at minimum, the following information: Management software ranges from simple spreadsheets, through freeware available on the Web, to sophisticated planning tools such as Microsoft Project If one considers commercial planning software specific to drilling, make sure that it can include services that are common in geothermal drilling but not often used in oil and gas, such as mud coolers, high-temperature tools and cement, etc.

Clearly, the drilling plan must also be flexible enough to accommodate unexpected events, or trouble, during the project, and there must be a well-defined process to identify the person who is responsible for changes in the plan. To begin designing the well, a great variety of information is desirable, but it is not always possible to get the complete package. It is worth considerable effort to get as much of it as possible, but sometimes the designer must just go with the best available data.

The desirable information includes, but is not limited to, the following parameters. A given well may serve any one of several different functions— production, injection, exploration, or workover—and the well design will be influenced by its purpose.

High, shallow temperatures or geothermal surface manifestations may require setting the surface casing too shallow, complicate the well design, and require more strings of casing to mitigate well control risks. An alternate location with directional drilling to the target is one option to avoid these shallow hazards. If the surface conditions are unknown, it may be cost effective to drill a small- diameter pilot hole to determine the surface conditions, rather than having to move the hole location after a larger rig and drill pad have been installed.

It is extremely useful to know as much as possible about the prospective reservoir; such information might come from previous temperature and pressure logs in offset wells, nearby thermal gradient holes, or geophysical information.

Clearly, temperature and pressure are crucial, but brine chemistry is also very important because it can have a major impact on casing selection and cost. It is common that, for reasons including the lease, a power sales contract, other financing requirements, or even weather, a drilling project must be completed on a given schedule.

If this is the case, it can complicate planning because of factors ranging from drill rig availability to acquisition of the necessary permits. The well planner has little recourse in dealing with these factors, but it is certainly essential to consider them in the planning process.

Experience in similar wells or general knowledge of the reservoir can sometimes offer a prediction of what problems may be encountered in If this knowledge is available it will guide the preparations in many ways: It may also provide better definition of the best operating envelope weight on bit, rotary speed, hydraulics for the bit in specific formations. The heart of well design is the specification of the casing program, which will be discussed in more detail in the following Chapter.

Drill Rig Selection Most of the criteria used to select a drill rig will be derived from well parameters; specifically diameter, depth, and casing design. Several factors define the minimum hole diameter, and also bear upon whether a core rig can be used for the hole. Diameter is not too important for fracture data, but sometimes a rock mechanics evaluation will need a minimum core diameter.

Larger diameter core also gives better recovery in highly fractured or unconsolidated formation. In general, this means that some kind of logging or sampling tool must be run through the packer into the zone below it, and the size of this tool will determine the minimum size of the packer and thus the hole. Based just on the diameter of the cable head for most logging cables, it would be very difficult to run a pass-through packer in a hole smaller than approximately 10 cm diameter.

The larger-diameter wellbore is particularly important if the flow turns two-phase. If all these factors indicate that a slimhole will satisfy the requirements, then a minerals-type coring rig can often yield significant cost savings for two reasons: Coring rigs see Figure 3 are fundamentally different from rotary rigs in the way that they retrieve core. In a typical coring rig used for minerals exploration, the core is cut by the bit and is stored in a tube in the lower end of the drill string as the hole advances.

At the end of the coring run, a wireline is lowered down the inside of the drill string and is latched into the top of the core tube to retrieve it to the surface. This not only gives a continuous core over the interval of the hole, but is much faster than tripping the drill string to retrieve the core sample as is done in rotary rigs. It is important, however, to be careful in pulling the core tube in a hot well; if swabbing lowers the static head inside the core rods below the saturation pressure of the drilling fluid, it can flash to steam and eject the core barrel, which would be very dangerous.

If a large-diameter hole is required, then a conventional rotary rig see Figure 4 will probably be used and the basic choice to be made is whether it should be a top-drive. In one geothermal reservoir21 , it was reported that bit life was improved three- to six-fold by circulating during trips into the hole. The ability to back-ream is highly useful in coming out of an unstable hole. Top-drive rigs generally cost more in daily rental, but it is often cost-effective to use one. Many considerations will affect the final rig choice but, aside from the purely economic factor of the price quoted by the drilling contractor, the following aspects of the rig should be the minimum list of qualities upon which to make a decision.

Rig capacity: Clearly, the drill string weight, with all the bottom-hole assembly, including an over pull safety factor, is a necessary part of this requirement, but it should be remembered that the casing is often the heaviest load handled during a drilling project. A significant margin of overpull should be available to work drillstring from tight hole and for picking up casing in deviated holes. Rig footprint: The drilling contractor should provide a dimensioned diagram or map of the rig set up in operating mode.

It should clearly show: If the planned drilling operation includes mud pits, or a water well, those should also be on the map. Pump capacity: The pumps must also have enough pressure capacity to give the desired pressure drop through the bit jets, and possibly drive a downhole drilling motor, if that is planned or a likely contingency.

Because of the generally larger hole sizes and volumes in geothermal wells, pumps and pits will be bigger than for oil wells of comparable depth. The pumps should also be able to handle lost circulation material LCM , which is discussed in more detail later. As a primary part of geothermal well control is the ability to pump cooling water into the well, a standby diesel driven mud pump on diesel-electric rigs is desirable.

Figure 5 Top drive, photo courtesy of National Oilwell Varco LCM will also complicate the mud cleaning, because it must be removed before the cuttings and fines can be removed from the drilling fluid. Drill string and BHA: The bottom-hole assembly design should be defined during planning, so the rig must have the correct tools, tongs, and fixtures bit breakers, elevators, etc.

If so, the planner should make certain that it is the correct size, weight, and grade and, if not, the planner should assure that another source of pipe is available. The responsibility for drill pipe inspection and replacement should be specified in the drilling contract.

BOP Equipment: The rig should have at least a mud cross for choke and kill lines, a double gate with blind and pipe rams, an annular and a rotating head. The size and height of this equipment, along with the well head height and cellar depth, dictate the sub base height required for the rig. The rotating head protects personnel from hot drilling fluid coming up through the rotary table.

The other equipment is required for well control, which is discussed in more detail in Section 8. High-temperature capability: This may be especially noticeable in drilling fluid returns, which will probably be much hotter than in conventional drilling.

In most locations, regulatory guidelines will require use of mud coolers when returns exceed a specific temperature, but even with coolers, operating personnel should be aware that hot fluid will create higher-than-normal thermal expansion forces, and that any elastomer seals may become vulnerable to the high temperature.

Rig instrumentation: Detailed requirements will vary from project to project, but a typical set of desirable measurements includes the following: All these measurements should be digitally recorded on a data logger at reasonably short intervals so that they can be easily stored and retrieved, but selecting the interval between measurements is not straightforward. Collecting high-speed data implies very large data files on long drilling projects, which may be a storage problem, but low- speed collection that gives more manageable amounts of data may not give the resolution needed Rig instrumentation is often coordinated between the drilling contractor and mud logging company; see Chapter 9—Logging and Instrumentation.

In general, rig malfunction or breakdown is one of the less likely kinds of drilling trouble. Crew and training: In the course of evaluating proposals from drilling contractors, every effort should be made to find out the experience and qualifications of the rig crew and supervision.

Like many aspects of drilling, selecting a rig often turns out to be more complicated than it first appears. Keys to a successful choice revolve around having a clear and detailed concept of what is needed for the project. It is frequently very valuable to have an experienced geothermal drilling engineer assigned to the specific task of rig selection, because any extra cost incurred here will almost certainly prove to be well-spent. Case Histories of Two Geothermal Wells: To give a more intuitive feel for actual geothermal drilling, case histories for two wells are summarized in Tables III-1 through III In both tables, ROP means rate of penetration.

Steam Well: This well was designed to be a two-leg well with casing to approximately m and two open-hole branches to approximately m, but the first leg encountered no steam entries. It was plugged back and two additional branches were drilled i. Although drilling three legs is not required for all wells in this reservoir, it is not uncommon, and drilling records from this well can be extrapolated back to one- or two-branch wells.

The hole was drilled with mud to the m casing point; then all branches were air-drilled.

DDH - Green Book - Drlling Data Handbook

There was no significant lost circulation in the mud-drilled part of the hole. Other events included milling two windows in the Although more footage was drilled than planned, this was considered a relatively trouble-free well.

Brine Well: This is a self-energized geothermal production well drilled in sedimentary formations. The well is cased to approximately m and has an open-hole production interval from there down to approximately m.

The corrosive nature of the brine requires titanium casing, but standard practice is to avoid drilling inside this very expensive tubular.

i-Handbook

The procedure is to drill Problems in stage-cementing the There were no fishing jobs during drilling. This was also considered a relatively trouble-free well. Table 3- 1 Steam Well Borehole Profile. Bit Diameter, Cm No. Bits Used Avg. Life, m 66 1 Bit Diameter, cm No. Life, m Wellbore Design — Casing and Cement Overview When wells are drilled to depths of more than a few hundred feet, conventional practice is to set successive, separate strings of casing as the well gets deeper.

These criteria apply to most kinds of drilling — onshore or offshore oil and gas, geothermal, or even minerals exploration — and they are further complicated by the ever-present possibility of unexpected trouble, which can mean an extra string of casing is run to prevent or remedy some downhole problem.

This is expensive for more than one reason, as described in more detail below. In general, the well is designed from the bottom up to the surface casing whose depth is limited by the depth that can be safely drilled without BOPE ; that is, the expected depth of the production zone and the expected flow rate will determine the wellbore geometry and casing program and most of the equipment requirements will follow from those criteria.

If there is two-phase flow in the wellbore, larger casing diameter where flow is vapor-dominated will significantly reduce pressure drop, improving productivity. All these factors combine to drive geothermal casing diameters much larger than oil and gas wells of comparable depth — typical casing sizes in geothermal production zones are 20 to 34 cm. However, well control concerns may require requesting permit variations, as these rules were borrowed from oil and gas well experience and can result in well control problems in some geothermal wells.

The two latter points counter each other — it is highly desirable to drill long intervals between running successive casings, but doing so greatly increases the probability of trouble and complicates well control. If a "contingency string" is needed to isolate a troublesome zone, this imposes a significant cost for the additional casing and cementing and for the necessity of larger diameter casing above the contingency string, so that the required bottomhole diameter can be preserved at the designed dimension.

Casing design Given a bottom-hole depth and diameter, determination of the casing intervals above that depends on several factors, including rock properties, formation fluids, surface casing setting depth, well control requirements or regulatory requirements. There are many common reasons to set casing in a particular interval: This often leads to the situation in which the higher pressure of the drilling fluid exceeds the fracture gradient of the formation, leading to lost circulation or even loss of well control.

Many geothermal systems are located in tectonically active regions, which have very low fracture gradients, complicating this part of the casing design.

There are many other reasons that casing might be set at a particular depth, but this list gives a flavor of how variable those reasons can be. Once the general casing profile is selected, the casing for each individual interval, or string, is characterized by three basic measurements: Diameter is straightforward, it is just the nominal outside diameter for that interval although this does not include the couplings, which are larger than the casing body and control the smallest possible inside diameter of the next larger string.

Weight, Casing has to withstand different kinds of loading in different situations, and the most common design criteria are for burst pressure, collapse pressure, and axial tension. As suggested above, the casing design has a significant impact on well cost. Several other considerations in geothermal casing design are the following: Strength at high temperature—Common casing materials lose strength at elevated temperature and the loss is more pronounced in higher grades of steel.

For example, the yield strength of K- 55 casing decreases from MPa 25o C to MPa at o C, but quenched-and-tempered L yield strength decreases from MPa to MPa over the same temperature range23 Casing availability—It is not uncommon for casing procurement to have a very lengthy lead time many months , especially for specialty grades or uncommon sizes. The well designer should check on this early enough in the process to allow adequate procurement time. Alternatives can be pursued if the specified casing is not available in time to meet the schedule, but these usually increase the risk, the cost or both.

Because strength is related to the manufacturing process, the variations in properties should be determined for the pipe being considered. As casing and its connections are cemented in place at one temperature and then cycled up to the reservoir temperature and then back to ambient during a subsequent operation, the casing and connectors may be stressed beyond the yield point , This needs to be taken into consideration in the casing design and connection selection process.

Corrosion resistance—Almost all geothermal reservoirs produce H2S. This limits the available materials for casing to those that meet NACE The materials meeting this specification are the lower strength grades, which limits the design options.

In addition, a number of geothermal reservoirs are plagued by problems driven by the brine chemistry. Brine quality varies greatly, ranging from near-potable in some moderate-temperature systems to highly corrosive with high dissolved solids in some high-temperature systems.

Many techniques — cement-lined casing, exotic alloys, and corrosion-resistant cement — have been applied to the casing corrosion problem, which is especially severe in the Imperial Valley of Southern California.

Shallow and hot, CO2 bearing zones there drive an external corrosion rate approaching 3 mm of carbon steel per year, which once necessitated plugging after 10 to 12 years even when well life was extended by cementing in smaller production strings. Although all of these methods are likely to produce satisfactory casing designs for oil and gas wells with normal temperatures, special designs will be required for high temperature wells, because the casing is stressed beyond its yield point, which is not considered in conventional casing design practice.

The New Zealand Code of Practice describes design parameters specific to the failure modes common in geothermal wells whereas most general drilling engineering handbooks often do not address thermal effects adequately. Engineering judgment is still important and it is a significant benefit to have a veteran drilling engineer with geothermal experience to at least review a proposed casing program.

This forces the cement to flow out the bottom of the casing and up the annulus between the casing and wellbore. In most oil and gas wells, the casing is cemented in place only at the bottom, with a completion fluid between the balance of the casing and the wellbore wall, but geothermal wells must have a complete cement sheath from bottom to surface25 To achieve this, the cement must be all around the circumference of the pipe for the entire length of the pipe.

There are well known methods of getting a good cement job, such as: While it may not be possible to employ all these methods at the same time, careful planning can maximize the successful use of these techniques. This cement has two important functions: The need to provide mechanical strength and corrosion protection implies that in addition to good cementing techniques, geothermal cements should have high bond strength to the casing and should be impermeable.

However, it is also very advantageous for the cement to be light weight at least compared to conventional cement, which has a specific gravity of approximately 1. Light weight is important because of the oft-encountered lost circulation described above.

Recent experience with difficult wells in California26 and Hawaii27 has also shown that reverse circulation foam cementing, where the cement is pumped down the annulus and flows back up drill pipe from the bottom of the casing, has several advantages. Even with light-weight cement, however, it is often impossible to lift a column of cement back to the surface without breaking down the formation.

A similar alternative is to perforate the casing at the top of the first cement after it has cured and force additional cement out into the annulus to extend further toward the surface. This process can be repeated if one squeeze does not completely cement the full annulus.

Drilling Engineering Handbook

However, another string of casing must be run inside to cover the perforations, as they unacceptably compromise the integrity of the well. A more common practice is flushing and backfilling when cement does not reach the surface or the top of a liner. Since any water trapped between casing strings will cause the inner string to collapse when it is heated up, any remedial process must prevent water being trapped.

If cement is not circulated to the surface, the annulus can be immediately flushed with enough water to make sure no cement is left in the annular space usually 1. After the remaining cement has set, an injection rate can be established, fracturing the formation if necessary, and followed by backfilling cement until a pressure increase indicates the annulus has been filled.

This may require a hesitation squeeze, or in the worst cases, a repeat of the annular flushing, followed by another backfill of cement. If cement returns reached the surface, but fell back a short way in a conventional cement job i. This means that small-diameter lines tremie lines are inserted into the annulus and cement is pumped into them to fill the annular volume.

The risk in this is that liquid water or drilling fluid will be trapped between the upper and lower volumes of cement see below in Completions , so all possible precautions should be taken to avoid this.

Since it is difficult to get the tremie pipe below the first centralizer, alternative methods should be considered if the cement falls below the first centralizer. Because of this problem, it is common practice to not put a centralizer on the top two joints of casing. When tremie pipe cannot be used, if the resources are available, the annulus can be dried with steam28 , to assure the absence of liquid. If severe fall back is a possibility, flushing and backfilling is a safer option.

Conventional oil well cements are not only too heavy for many geothermal wells, but are susceptible to attack by acids and by CO2, both of which are common in geothermal reservoirs and both of which degrade the impermeability and strength of the cement. Brookhaven National Laboratory BNL carried out a major research program on geothermal cement, intended to mitigate or eliminate these effects. The BNL worked with cost-sharing industry partners Halliburton, Unocal, and CalEnergy Operating Company toward the specific goal of a lightweight cement with outstanding resistance to acid and CO2 at brine temperatures up to o C.

Drilling Data Handbook

Reviews of this work before36 and after37 Completions are provided in detailed reports. BNL succeeded in synthesizing, hydrothermally, two new cements: Both of these were economical cements because they used inexpensive cement-forming by-products from coal combustion and steel-manufacturing processes. SSAS cements have received less attention than CaP, but autoclave experiments in the lab have demonstrated good performance in high-acid environments and, in fact, after undergoing acid damage, the SSAS cement exhibited a self- repairing characteristic.

Addition of fly-ash further improved its acid resistance, so SSAS is promising as low-cost geothermal well cement in high-acid conditions up to o C. Apart from the requirement for a complete cement sheath around the casing, factors that influence completion design include brine chemistry; multi-branch completions; and whether the production interval is stable enough to be open hole or must be completed with a slotted liner.

Brine chemistry can cause two major problems: Scaling, the buildup of mineral deposits both inside the casing and in the production interval, is a problem in geothermal plants around the world38 , and can lead to frequent workovers.

In severe cases untreated scaling can reduce the flow area of casing by half in a matter of months. Casing scale can sometimes be removed with high-pressure jets39 , but scaling in the wellbore often seals the formation and must be drilled out with an under-reamer an expandable bit that can drill a hole below casing that is larger than the inside diameter of the casing.

It is highly preferable to inhibit or prevent scale formation rather than to remove it, and there are many chemical techniques for this40 , but discussion of those is beyond the scope of this Chapter. Wellhead pressure control can also determine where in the well brines start to flash on their way up the well — within limits, deposition in the formation can be mitigated by running wells with a higher wellhead pressure albeit with reduced flow rate.

When casing is cemented, it is also critical that no water be trapped between the cement and the casing, especially in intervals where one casing is inside another, because the water can thermally expand as the well goes on production and heats up.

The casing will almost certainly collapse if the trapped-water location has formation outside it, the fracture gradient is usually low enough to allow the pressure to bleed off into a fracture. These failures can be serious Finally, it is necessary to decide whether the production interval of the well is competent enough formation so that it can be left as-drilled open-hole completion or whether a slotted liner will be necessary to protect against sloughing or caving into the wellbore.

Some indications can be gained from the geologic samples acquired during drilling, or from imaging logs, if available, but this decision is often made based on experience gained from other wells in the same reservoir. Large hole volumes and frequent lost circulation mean that expensive mud has a significant impact on drilling cost. Drilling records from a number of geothermal wells in several reservoirs showed the typical property ranges below: Oil, fresh water, or salt water can be used as a base liquid in drilling muds, but oil and salt water are almost totally restricted to hydrocarbon drilling.

Fresh water muds are used for geothermal drilling.

Geothermal brine that is produced from nearby wells is sometimes used when drilling without returns. Active solids are the clays and polymers added to the water to produce a colloidal suspension. They determine the viscosity of the mud and are known as viscosifiers.

Inert solids are those added to the mud either by drilling i. These solids increase the density of the mud without appreciably affecting the viscosity. There are also soluble components of the system; products in solution in the base liquid that cannot be filtered or removed mechanically. These ions must be chemically analyzed and chemically treated. Undesirable ions such as calcium, magnesium, arsenic, and chlorine may be present in the make-up water or they may be present in drilled formations and become dissolved in the mud system.

Some water sources may contain too many undesirable ions to treat out, and thereby require locating a better source of water. Historically, most geothermal drilling fluids that are liquids have been a fairly simple mixture of fresh water and bentonite clay, possibly with polymer additives Aerated mud or water has a gas, usually air but sometimes nitrogen if corrosion is serious, injected into the liquid to lighten it; aerated mud is common where lost circulation is a significant problem.

Aerated fluids have been used extensively internationally, at least since the early 's, offering many advantages. B34 Polar modulus of drill collars in3-mm3 ……………………..

B35 Drill-collar Assembly. Rigidity R………………………….. Shoulder modifications for low-torque connections. Dimensions of low-torque shouldered………………. B38 Spiral drill collars Drilco …………………………………….

B50 Stretch of suspended drill pipe………………………….. Calculation examples… B60 C casing, tubing line pipe standards Tensile requirements. C6 Efficiency of a connection………………………………… C7 Make-up torque……………………………………………….

C8 Geometrical characteristics and mechanical properties of small-diameter tubing…………………………….

C9-C15 Geometrical characteristics and mechanical properties of tubing……………………………………………. CC87 Geometrical characteristics and mechanical properties of line pipe, risers and conductor pipe……………….. CC90 API and buttress casing thread forms. API round threads form. Buttress thread form…………………..

C91 API tubing thread form………………………………….. C92 Effect of tensile load on collapse resistance ………….. C93 Ellipse of biaxial yeld stress. Effect of tensile load on collapse resistance…………………………………….. C95 Quantitative influence of temperature and pressure variations on the stresses in a partially-cemented casing string……………………………………………….. D4-D5 Capacities of drill pipes………………………………….. D6-D7 Capacities of drill collars………………………………… D8 Capacities and displacements of casing……………….

D9-D10 Capacities and displacements of tubings……………… D11 Annular volume between drill collar and open hole liters per meter ………………………………………….. D12 Annular volume between drill pipe and open hole liters per meter ………………………………………….. D13 Annular volume between drill pipe and casing liters per meter …………………………………………. DD15 Annular volume between casing and open hole liters per meter …………………………………………. D16 Annular volume between two string of casing liters per meter ………………………………………….

DD19 Annular volume between casing and tubing liters per meter ……………. E1 IADC roller bit classification system……………………. E3 How to use the roller bit table………………………… E19 Turbodrilling E20 Performance curves on turbodrill Specific gravity d, constant flow rate Qn …………………………………….

E21 Turbodrill specifications Specific gravity of mud 1. EE24 Performance curves of positive displacement motors for different flow rates Q………………………………… E25 Specifications of positive displacement motors Moineau type ………………………………………… EE29 F hoisting and derrick floor equipment Hoisting mechanics. Reeving function……….. F1 Hoisting mechanics. F2 API wire rope. Factor of safety RP 9B, May 30, F3-F4 API wire rope……………………………………………… F5 Typical sizes and constructions of wire rope………..

F6-F7 API classification of bright uncoated or drawn galvanized wire rope. Class 6 x 7. F8 API classification of bright uncoated or drawn galvanized wire rope. Classes 6 x 19 and 6 x Class 6 x F10 API classification of bright uncoated or drawn galvanized wire rope continued.

F11 API classification of bright uncoated or drawn galvanized wire rope continued. FF13 API classification of bright uncoated or drawn galvanized wire rope continued. F14 API classification of bright uncoated or drawn galvanized wire rope continued. F15 API classification of bright uncoated or drawn galvanized wire rope continued.

Class 8 x F16 API classification of bright uncoated or drawn galvanized wire rope continued. Class 18 x 7. Fiber Core FC. Class 19 x 7. Metal Core. F18 API classification of bright uncoated or drawn galvanized wire rope continued. F19 API wire rope. F20 Sheave grooves. F21 Work done by a drilling line……………………………… F22 Cutoff practice for drilling lines.

Cutoff length as a function of derrick or mast height and drum diameter API RP 9B, 9th edition, may 30, ……………………..

F23 Cutoff practice for drilling lines continued. F25 Elevator link arms. Remaining capacities of work link arms. Dimensions and nominal capacity of link arms per set …………………………………………………. F30 Brake blocks……………………………………………… F34 Chains continued. F35 Chains continued ……………………………………….. F38 Tension in slings. Two-wire slings…………………….. F39 G pumping and pressure losses Mud pumps…………….. G1 Pumping power……………..

G2 Output in liters per stroke double acting duplex pumps based on liner size and piston rod diameter…….. G3-G4 Triplex pumps. Maximum pressure based on liner kPa ………………………………………………………… G6 Mud cycle time…………………………………………….. G8-G9 Amount of drilled cuttings in mud……………….. G10 Annular mud specific gravity dann…………………… G11 Hydraulics…………………………………………………….. G12 Rheology………………………………………………… G14 Pressure losses General …………………….

G15 Pressure loss equations………………………………… GG18 Pressure drop in orifices……………………. G20 Pressure loss calculation……………….. GG22 Table of coefficients B………………………. GG29 Table of coefficients N1. Calculation of pressure losses in surface equipment………………………..

Calculation of pressure losses in drill pipes……………………………….. GG44 Table of coefficients N3.

Calculation of pressure losses in drill collars………………….. GG46 Calculations of pressure drop in nozzles. Combination of three nozzles……………………………………. Combination of two nozzles………………………………….. Combinations of three nozzles….. G56 Table of nozzle areas. Combinations of two nozzles……. G57 Table of nozzle areas…………………………. G58 Table of coefficients N4. G68 H drilling mud Relationship between mud weight and pressure head of mud…………………. Weight in kg of calcium carbonate to add to 1 m3 of mud M ………..

H7 Ternary diagram for determining solid content of mud water base muds ……………………………….. H9 Properties of sodium chloride solutions……………….. H10 Properties of calcium chloride solutions…………. H11 Properties of potassium chloride solutions……… H12 Properties of sodium carbonate Na2CO3 solutions…. H13 Properties of potassium carbonate K2CO3 solutions.. H14 Properties of sodium bromide NaBr solutions….. H15 Effect of temperature on densities of calcium chloride and sodium chloride solutions Field Data Handbook, Dowel Schlumberger …………………………………….

H20 I cementing General data units commonly used in cementing… I1 Correlation between sacks and tons of cement…….. I4 Preparation of freshwater slurry……………….. I5 Cement slurry freshwater ……………………………….. I9 Preparation of one cubic meter of saturated salt-water slurry……………………………………………….. I10 Preparation of bentonite cements……….. Class G per kg of cement ……………………………………………….. I13 Preparation of one cubic meter of bentonite cement slurry - Class G cement……………………..

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