# Chapter 3: Drilling Rigs ## Learning Objectives By the end of this chapter, you will be able to: - Identify the four fundamental functions of a drilling rig and the operations a rig performs over the life of a well - Describe the major rig types, onshore and offshore, and the factors that determine where each is used - Explain the five rig systems — hoisting, rotary, circulating, power, and well control — and identify the principal equipment in each - Analyze the block-and-tackle mechanics of the hoisting system, including fast line tension, derrick load, and the limitations of the hookload measurement - Calculate mud pump output from pump geometry and stroke rate - Describe the typical drillstring components: drill pipe, heavy weight drill pipe, drill collars, stabilizers, and bits - Evaluate rig selection criteria and contract types for a drilling program --- ## 3.1 What a Rig Does ### 3.1.1 The Four Functions A useful mental model for a drilling rig is a hand drill scaled up by several orders of magnitude. When you drill a hole in a wall, your drill provides rotation, your arm provides axial force (and absorbs the reactive torque), and the spiral flutes of the drillbit carry the cuttings out of the hole. A drilling rig does exactly the same jobs — but the "bit" is at the end of a string of pipe that may be three miles long, the axial forces are measured in hundreds of thousands of pounds, and the cuttings are carried out of the hole by a circulating fluid rather than by gravity or bit rotation. Every drilling rig, regardless of size or type, performs four fundamental functions: 1. **Hoisting** — moving the drillstring and casing up and down in the well 2. **Rotating** — turning the drillstring (and, when required, the casing) 3. **Circulating** — pumping fluids into and out of the well 4. **Maintaining well control** — controlling downhole pressures and preventing blowouts Each function is performed by a dedicated system of equipment, and these systems — plus the power system that drives them all — organize this entire chapter. ```{figure} ../figures/ch03/slide_03.png :name: fig-rig-systems-overview :width: 90% :align: center The systems of a rotary drilling rig. The hoisting system (mast, drawworks, crown and travelling blocks) and rotary system (top drive, drillstring) occupy the derrick; the circulating system (mud pumps, hose, swivel) and solids control system (shale shakers, mud pits, mixers) occupy the "backyard"; the well control system (BOPs, accumulators, choke and kill manifold) sits at the wellhead; and the power system (diesel generators) drives everything. ``` ### 3.1.2 Rig Operations Over the life of a well, the rig performs a sequence of distinct operations: - **Drilling** — the bit is on bottom, making new hole - **Tripping** — pulling the drillstring and drillbit out of the hole (tripping out) or running it back in (tripping in), for example to change a worn bit or after the section of hole has been successfully drilled - **Running casing** — tripping steel casing into the drilled hole - **Cementing** — pumping cement down the casing and up the annulus to seal it in place - **Formation evaluation** — logging, coring, and testing to measure what rock the well has penetrated - **Completion (and re-completion)** — preparing the well for production (perforating, installing pumps, etc.) - **Workover** — re-entering a producing well to repair or replace downhole equipment or service the casing - **Abandonment** — plugging the well, temporarily or permanently The time split among these operations is worth remembering: **drilling occupies only about a quarter to a third of total rig time.** Tripping accounts for roughly another third, and running casing and cementing for the remaining third. This is why so much engineering effort goes into technologies that reduce tripping and connection time — a rig that only makes hole one-third of the time has two-thirds of its schedule available for improvement. Workover and abandonment operations typically do not use the full drilling rig. A **workover rig**, a smaller, truck-mounted unit that is faster to move and rig up, performs these tasks at much lower cost. --- ## 3.2 Rig Types ### 3.2.1 Land Rigs Onshore rigs are designed to be mobile and general-purpose. The entire rig, derrick, drawworks, pumps, pits, and power, breaks down into truckloads and moves from location to location. A modern land rig can rig down, move, and rig up on a new pad in days; on multi-well pads, many rigs can **skid** or "walk" between wellheads without disassembly at all. ```{figure} ../figures/ch03/slide_04.png :name: fig-land-rigs :width: 90% :align: center Land drilling rigs. Left: a telescoping-mast rig in northern Alberta, with pipe handling equipment, mud system, and storage arranged around the elevated rig floor. Right: a rig in the Netherlands, enclosed by a sound wall — standard practice in densely populated regions. ``` Land rigs are classified by how many joints of drill pipe fit in the derrick as a **stand**: - **Single / super single** — one joint per stand (~30–45 ft); super singles use long Range 3 joints - **Double** — two-joint stands (~60 ft) - **Triple** — three-joint stands (~90 ft); the standard for large land rigs, requiring a derrick roughly 190 ft tall - **Quad** — four-joint stands (~120 ft); rare, because the derrick becomes impractically tall and difficult to transport The taller the derrick, the more pipe moves per connection during tripping — a triple pulls 90 ft of pipe per cycle where a single pulls 30 ft — which directly reduces trip time on deep wells. Most modern North American masts are **self-erecting**: the rig uses its own drawworks and an A-frame to pull the assembled mast from horizontal to vertical, eliminating the crane rental that older rigs required during rig-up. ```{figure} ../figures/ch03/slide_09.png :name: fig-raising-mast :width: 85% :align: center Raising a portable mast. The mast is assembled horizontally on the ground, then pulled vertical using the rig's own drawworks acting through an A-frame. ``` **Environment shapes rig design and operations.** In northern Canada, rigs move on frozen winter roads; when the spring thaw softens the ground, rigs cannot move until the next freeze, producing a flurry of rig moves each April before the roads close. In Europe and in populated basins like Colorado's Front Range, rigs operate next to homes and towns, and sound walls, directed lighting, and traffic management are standard, with the community-relations consequences discussed in Chapter 22. ### 3.2.2 Offshore Rigs Offshore, the rig type is dictated primarily by water depth: - **Jackup rigs** — self-elevating platforms whose legs stand on the seabed; used in shallow water (up to ~400 ft) - **Platform rigs** — permanent rigs mounted on fixed production platforms - **Semi-submersible rigs** — floating rigs ballasted for stability, held on station by mooring or dynamic positioning; used in deep water - **Drillships** — ship-hulled vessels with a drilling derrick amidships; the most mobile deepwater option, used for exploration in remote locations; held on station by dynamic positioning Rig day rates span more than an order of magnitude: roughly \$25,000–\$100,000/day for land rigs and \$250,000–\$1,000,000/day for deepwater floaters. This cost difference drives every aspect of offshore well planning: a day saved offshore is worth ten days saved on land. --- ## 3.3 The Hoisting System The hoisting system raises and lowers everything that goes into the well. Its job sounds simple, but the loads are enormous: drillstrings weigh 20–50 lb/ft, so a 15,000 ft string weighs several hundred thousand pounds, and casing strings can weigh more. The derrick and hoisting equipment must carry these loads safely while positioning the string with precision. ### 3.3.1 Block-and-Tackle Arrangement ```{figure} ../figures/ch03/slide_07.png :name: fig-hoisting-schematic :width: 85% :align: center The hoisting system: block-and-tackle arrangement (a), and free-body diagrams of the travelling block (b) and crown block (c). The drawworks reels in the fast line; the deadline is anchored near the rig floor. ``` On many rigs, the load is carried on a wire rope (the **drilling line**) reeved multiple times between two pulley sets: - The **crown block** — the stationary pulley set at the top of the derrick - The **travelling block** — the moving pulley set from which the hook (and top drive) hangs One end of the drilling line spools onto the **drawworks**, a large winch with a powerful motor and brakes, and is called the **fast line**, because it moves fastest as the blocks travel. The other end, the **deadline**, is anchored to a **deadline anchor** at the rig floor and does not move. If the drilling line is strung with $N$ lines between the crown and travelling blocks, each line carries $1/N$ of the hookload $W$ (neglecting friction): $$F_\text{fast line} = \frac{W}{N}$$ The block-and-tackle thus acts as a force multiplier: the drawworks needs to pull only a fraction of the hookload, at the cost of reeling in $N$ feet of line for every foot the block rises. The total load on the derrick includes the hookload plus the fast line and deadline tensions: $$F_\text{derrick} = W + \frac{W}{N} + \frac{W}{N} = W\left(\frac{N+2}{N}\right)$$ ### 3.3.2 Drawworks and Braking ```{figure} ../figures/ch03/slide_10.png :name: fig-drawworks :width: 85% :align: center A drawworks, with the drum of drilling line in the center and brakes at either side. Braking systems include band brakes, disc brakes, and auxiliary brakes (hydromatic, eddy-current, and magnetic particle types). ``` The drawworks raises the string with its motor, but it *lowers* the string mostly on its **brakes**. When lowering a string that weighs half a million pounds, the brakes dissipate the potential energy of the descending load. Braking systems include mechanical band and disc brakes and auxiliary brakes (hydromatic, electro-dynamic eddy-current, and magnetic particle brakes). The newest electric drawworks can regeneratively brake through the motor itself, giving smooth, precisely controlled motion; most rigs, however, still lower the string in small mechanical increments — one reason precise automated control of weight on bit remains an engineering challenge. ### 3.3.3 Crown Block, Travelling Block, Elevators, and Bails ```{figure} ../figures/ch03/slide_11.png :name: fig-crown-block :width: 80% :align: center A crown block from an offshore rig. The sheaves (pulleys) run side by side on bearings; the scale of the equipment is apparent against the person in the photograph. ``` Modern travelling blocks run on rails in the derrick rather than hanging free: a free-swinging multi-ton block is a serious hazard. To grab pipe, the hoisting system uses the **elevators and bails**: hinged arms (bails) hanging below the travelling block that end in a latching collar (the elevator). The elevator latches around the pipe below the **tool joint** — the enlarged threaded connection at the end of each joint — whose lip provides the shoulder the elevator lifts against. Elevators can hoist and lower pipe but cannot rotate it. ```{figure} ../figures/ch03/slide_14.png :name: fig-elevators-bails :width: 80% :align: center Elevators and bails, hanging below the top drive. The elevator latches beneath the tool joint of the drill pipe, allowing the hoisting system to lift the string without screwing into it. ``` ### 3.3.4 The Deadline Anchor and the Hookload Measurement ```{figure} ../figures/ch03/slide_15.png :name: fig-deadline-anchor :width: 80% :align: center The deadline anchor. The load sensor on the anchored (stationary) end of the drilling line is the rig's primary hookload measurement. ``` The rig's measurement of hookload — the single most important drilling measurement, from which weight on bit is inferred, comes from a load sensor on the deadline anchor. Because the deadline carries $1/N$ of the load, deadline tension × $N$ estimates the hookload. It is worth understanding when this measurement is accurate and when it is not: - **Accurate:** when the system is static, at the block position where it was calibrated. - **Inaccurate when moving:** the measurement does not account for (1) the *inertia* of the massive blocks and string during acceleration, (2) *sheave friction* in the block-and-tackle, (3) the changing *weight of suspended drilling line* as the block position changes, and (4) *line stretch*, which absorbs vibration and bounce before it reaches the sensor. The surface weight-on-bit reading, calculated as hookload off bottom minus hookload on bottom, inherits all of these errors, plus friction between the drillstring and the wellbore. This is why downhole measurements (Chapter 21) often differ substantially from surface readings, particularly in deviated wells. --- ## 3.4 The Rotary System ### 3.4.1 Top Drive vs. Kelly and Rotary Table Two generations of technology can rotate the drillstring: **Rotary table and kelly (legacy):** A rotating section of the rig floor (the rotary table) turns a square or hexagonal pipe (the **kelly**) that slides vertically through a matching bushing while rotating with it. Drilling progresses one kelly length at a time. **Top drive (modern):** A large electric motor suspended in the derrick screws directly into the top of the drillstring and rotates it. The top drive travels up and down with the travelling block. ```{figure} ../figures/ch03/slide_16.png :name: fig-kelly-topdrive :width: 85% :align: center The kelly (left) and top drive (right). Nearly all modern rigs drill with a top drive; the kelly and rotary table linger only as a backup. ``` The top drive won decisively and is used almost exclusively today. Its advantages: - **Connection time:** can drill down a full 90+ ft stand before making a connection (a kelly drills only one kelly length, ~30–45 ft, at a time) - **Crew safety:** fewer connections means less exposure to pipe-handling hazards - **Backreaming:** can pull out of the hole while rotating and circulating simultaneously - **Forward reaming:** while tripping in, can quickly drill through tight spots or bridges without picking up a kelly - **Directional control:** maintains toolface orientation while drilling directionally - **Casing running and coring:** can rotate and fill casing with standard tools, and core ~90 ft continuously Its disadvantages: cost, weight in the derrick, more involved maintenance, and difficulty of retrofitting older rigs, have not stopped its adoption. The overwhelming majority of land and offshore rigs now drill with top drives. ```{admonition} Field Note :class: note Drillers initially resisted top drives. The rotary table was simple, visible, and understood; the top drive was an expensive machine hidden up in the derrick. It took years, and consistent performance gains, for the technology to win acceptance. Early adopters suffered due to low reliability, and lower performance of early hydraulic top drives before electric, inverter driver, top drives became the industry standard. Technology adoption in drilling is as much about people as machines. ``` ### 3.4.2 Slips When the top drive is disconnected from the string, at every connection, the string must hang from something. That something is the **slips**: a tapered, wedge-shaped gripping tool set into the bushing in the rig floor. The geometry is self-energizing: the heavier the string, the harder the taper squeezes the pipe. To release, the driller simply picks up on the string and the slips pop free. ```{figure} ../figures/ch03/slide_18.png :name: fig-slips :width: 85% :align: center Slips. The tapered wedge grips the pipe in the rotary bushing; string weight drives the gripping force (right), making the slips self-energizing. ``` Dropping a drillstring, letting it fall into the hole unsecured, is among the most expensive rig-floor errors. The recovery operation (fishing, Chapter 21) can take days; if the fish cannot be recovered, the hole may have to be cemented and sidetracked. ### 3.4.3 Making Connections A **connection** is the sequence of adding (or removing) a joint or stand of pipe: 1. Stop drilling; pick up off bottom; set the slips 2. Disconnect (break out) the top drive from the string 3. Add or remove pipe, torque the connections together (making up) to a specified torque 4. Reconnect the top drive, pull out of slips, tag bottom and resume drilling Historically, make-up and break-out torque came from crew members swinging chains and later manual **tongs**, two large wrenches operated with cathead-driven chains, among the most dangerous jobs on the rig floor. Modern rigs use an **iron roughneck**: a machine that slides to well center, grips the pipe, and applies precise make-up or break-out torque with no human hands on the pipe. ```{figure} ../figures/ch03/slide_19.png :name: fig-connections :width: 85% :align: center Making connections: manual tongs (left) versus the iron roughneck (right), which mechanizes the highest-risk routine task on the rig floor. ``` During tripping, stands may be racked back vertically in the derrick on the **monkey board**, historically handled by the **derrickman** working at height with minimal fall protection. Automated pipe-racking machines now perform this job on newer rigs, one of the clearest examples of mechanization removing people from high-risk positions. Smaller rigs may store pipe on the ground and bring up each stand of pipe up to the rig floor with an automated or manual pipe handler. ```{figure} ../figures/ch03/slide_20.png :name: fig-derrickman :width: 75% :align: center The derrickman on the monkey board, racking stands of drill pipe in the derrick. On modern rigs this task is increasingly performed by automated pipe-handling machinery. ``` Note the division of labor between systems: **only the top drive can rotate the string.** When tripping on the elevators alone, the string can be hoisted and lowered but not rotated. --- ## 3.5 The Circulating System ### 3.5.1 The Flow Path ```{figure} ../figures/ch03/slide_21.png :name: fig-circulating-system :width: 90% :align: center The circulating system. Mud pumps draw from the pits and discharge through the standpipe and rotary hose to the swivel, down the drillstring, out the bit, and up the annulus; returns flow across the shale shakers and back to the pits. ``` The circulating system is a closed loop: 1. **Mud pumps** pressurize the drilling fluid and pump it into the **standpipe**, a rigid pipe running up the derrick leg 2. The flexible **rotary hose** connects the standpipe to the **swivel**, which passes fluid from the stationary hose into the rotating drillstring (motors and fluid must be kept separate; the swivel is the rotating seal that makes this possible) 3. The fluid travels down the hollow drillstring, out the **bit nozzles**, and picks up cuttings at the bottom of the hole 4. It returns up the **annulus**, the space between the drillstring and the wellbore wall 5. At surface, the returns flow through the **mud return line** to the **solids control equipment**, and the cleaned fluid returns to the **mud pits** for reuse At the top of the annulus, the well is open to the atmosphere: annular pressure at surface is zero (gauge) during normal drilling. Gauge pressure (psig) is measured relative to atmospheric pressure; absolute pressure (psia) includes it. Drilling calculations use gauge pressure: the ~14.7 psi of the atmosphere is negligible against the thousands of psi in the wellbore. ### 3.5.2 Mud Pumps ```{figure} ../figures/ch03/slide_22.png :name: fig-mud-pumps :width: 85% :align: center A triplex mud pump. Positive-displacement piston pumps provide the hydraulic power for the circulating system, operating at pressures up to 5,000–7,500 psi. ``` Mud pumps are large positive-displacement piston pumps, designed around three ratings: - **Pressure** — up to typically 5,000–7,500 psi (limited by pop-off relief valves and the standpipe manifold rating), needed to circulate heavy muds in deep wells - **Flow rate** — must exceed the minimum needed to clean the hole and carry cuttings to surface - **Hydraulic horsepower** — the product of pressure and flow rate; particularly important when running downhole motors, which are powered by the mud flow Pumps are configured as **duplex** (two pistons, double-acting) or, most commonly, **triplex** (three pistons, single-acting). Output pressure and flow rate are adjusted by changing the **liner** (cylinder sleeve) size: small liners give high pressure at low flow; large liners give high flow at lower pressure. Stroke phasing among the pistons and **pulsation dampeners** smooth the discharge pressure. There is no direct flow meter on a standard rig. Flow rate is *calculated* from pump **strokes per minute (SPM)** and the known displacement per stroke. For a triplex pump with liner diameter $d$ (in), stroke length $L$ (in), and volumetric efficiency $e$: $$q\ (\text{bbl/stk}) = 0.000243 \times d^2 \times L \times e$$ Multiply by SPM to get bbl/min (× 42 for gal/min). When drilling data reports flow in GPM, remember it is a calculated value inherited from the pump specification: it is not a measurement. ### 3.5.3 The Mud and Solids Control ```{figure} ../figures/ch03/slide_23.png :name: fig-mud-system :width: 85% :align: center The mud system. Right: composition of an 11 ppg water-based mud — mostly water, weighted with barite, plus drilling solids, viscosifiers, and other additives. ``` The drilling fluid itself is the subject of Chapters 4 through 6; here it is enough to list its primary functions: provide primary well control, transport cuttings to surface, cool and lubricate the bit, stabilize uncased hole, and form a filter cake on permeable formations. The mud weight must be kept above the formation pore pressure but below the fracture gradient; this **drilling window** will be introduced in Chapter 4. Because mud is expensive, the rig recycles it. **Solids control equipment** removes the drilled cuttings before the fluid is pumped back downhole: - **Shale shakers** — vibrate screens that the returns flow across; fluid passes through the screen while cuttings vibrate off the end into the cuttings pit. The first and most important stage. - **Desanders and desilters** — hydrocyclones that remove progressively finer solids - **Centrifuges** — remove the finest solids that screens and cyclones cannot catch ```{figure} ../figures/ch03/slide_24.png :name: fig-solids-control :width: 85% :align: center Solids control. Shale shakers remove most of the larger cuttings; centrifuges remove fine solids that would otherwise accumulate in the recirculated mud. ``` --- ## 3.6 The Power System Everything on the rig runs on power — typically several megawatts of it. Most rigs generate their own electricity with **diesel generator sets**, driving the electric motors on the drawworks, mud pumps, and top drive. Some rigs connect to the **electrical grid** instead, eliminating diesel consumption and emissions at the wellsite. Grid connection brings its own challenge: rig motors are large *inductive loads* that draw enormous instantaneous current when starting, the same effect that dims your house lights when a dryer starts, scaled up to megawatts. Without mitigation, a grid-connected rig can visibly dim the lights of the nearest town every time a pump kicks in. **Hybrid rigs** address this with on-site battery packs that supply the starting transients and smooth peak loads, and reduce generator fuel burn on conventional rigs as well. These rigs can reduce the peak rated power load by 20 to 40%. --- ## 3.7 The Well Control System The final rig system exists for the moments when the weight of mud column alone fails to keep formation fluids out of the well. Somewhere in the world, a well takes an influx of formation fluid, a **kick**, every day. Almost all are detected, circulated out, and never make the news. The well control system is what makes that routine outcome possible. **Blowout preventers (BOPs)** are the stack of high-pressure valves and hydraulically activated rams installed on the wellhead below the rig floor. A BOP stack can close on the annulus around the pipe (annular preventer and pipe rams), close on an open hole (blind rams), or, as a last resort, shear the drillstring entirely and seal the well (blind shear rams). ```{figure} ../figures/ch03/slide_25.png :name: fig-bops :width: 85% :align: center Blowout preventers. Left: a land BOP stack. Right: a subsea BOP stack — the BOP itself is a small part of the assembly; the rest is the machinery required to operate it remotely on the seabed. ``` Supporting the BOP stack: - **Accumulators** — banks of pressurized hydraulic fluid that can close the BOPs quickly even if rig power is lost - The **choke and kill manifold** — a symmetric, twinned, arrangement of high-pressure lines and valves connected below the BOPs, through which a shut-in well can be circulated under precise pressure control. Two redundant sides are provided so that a plugged or eroded choke can be swapped without losing control of the well. ```{figure} ../figures/ch03/slide_26.png :name: fig-choke-kill :width: 85% :align: center The choke and kill manifold. Redundant, symmetric valve paths allow controlled circulation of a shut-in well; the valves may be operated manually or, on newer rigs, remotely. ``` Well control, the detection of kicks, shut-in procedures, and the methods for killing a well, is the topic of Chapters 8–10. --- ## 3.8 What the Rig Powers in the Hole: The Drillstring and Bit The rig's systems exist to run equipment into the ground. A brief tour of that equipment completes the picture; drillstring design is treated quantitatively in Chapter 17. ```{figure} ../figures/ch03/slide_27.png :name: fig-drillstring-overview :width: 85% :align: center The drillstring: drill pipe over heavy weight drill pipe, jars, and drill collars, ending at the bit. Joints come in API Range 1 (18–22 ft), Range 2 (27–30 ft), and Range 3 (38–45 ft) lengths. ``` The term **drillstring** refers to all the equipment between the top drive on the drilling rig and the bottom of the hole where drilling is occuring. A drillstring is typically made up of: - **Drill pipe (DP)** — makes up thousands of feet of the string; strong in tension and torsion, but buckles in compression. Each joint ends in a threaded **tool joint** — a **pin** (male) or **box** (female). - **Heavy weight drill pipe (HWDP)** — thick-walled pipe, frequently used to provide a gradual stiffness transition between drill pipe and collars, or to provide stiffness in while drilling horizontal wells. - **Drill collars (DC)** — heavy, stiff, thick-walled pipe run at the bottom of the string to provide weight on bit; resistant to buckling. Available in slick, spiral, and square profiles (spiral and square reduce wall contact area), and in non-magnetic (monel) versions to house directional survey instruments. - **Stabilizers** — near-bit and string subs with blades at nearly hole diameter that centralize the bottom-hole assembly (BHA), influence directional tendency, and suppress buckling and vibration — at the cost of added torque and drag. ```{admonition} The Aspect Ratio of a Drillstring :class: note If a 3-mile drillstring of 3½-in pipe is scaled down to a line 1,000 pixels long, and the pipe is 0.03 pixels wide — proportionally far more slender than a violin string. Two consequences follow. First, the string is *elastic*: a change in surface RPM takes over a second to reach the bit (torsional waves travel at ~3 km/s), and the string can wind up and release like a spring — the origin of the stick-slip vibration discussed in Chapter 21. Second, the pipe is *flexible*: drill pipe snakes easily through doglegs up to ~15°/100 ft that stiffer casing may not pass. ``` At the bottom of the string is the **bit**. There are two dominant types of bits: - **Tri-cone (roller cone) bits** fail rock in *compression*: teeth on three rotating cones indent and crush the rock. Reliable in nearly any formation and inexpensive (milled-tooth versions), but slower (tens of ft/hr) and limited by bearing life — a tri-cone has a finite number of rotations before its bearings fail. - **PDC bits** fail rock in *shear*: fixed polycrystalline diamond cutters shave the rock like a lathe tool. No moving parts, much faster (potentially 150–200+ ft/hr), suitable for nearly all formations — but the cutters are vulnerable to impact damage, particularly when drilling from soft rock into hard rock, where the bit can dig in, stall, and stick-slip. Most footage today is drilled with PDC bits. ```{figure} ../figures/ch03/slide_31.png :name: fig-bits :width: 85% :align: center PDC bits (left) shear the rock with fixed diamond cutters; tri-cone bits (right) crush it with rolling toothed cones. ``` --- ## 3.9 Choosing a Rig Selecting a rig for a drilling program is an engineering and commercial decision. The operator's drilling engineer typically prepares a rig specification and evaluates available rigs against it. ### 3.9.1 Decision Factors The technical requirements flow directly from the well design: - **Anticipated formation pressures and temperatures** — sets BOP pressure ratings and mud system requirements - **Hole and casing programs** — sets hoisting capacity (heaviest casing string), rotary table opening, and substructure height - **Drillstring sizes and weights** — sets hoisting and racking capacity - **Hoisting requirements** — maximum anticipated hookload with margin - **Hydraulic requirements** — pump pressure, flow rate, pressure drop from downhole tools and motors, and horsepower for the planned hole sizes and depths - **Rotary/torque requirements** — top drive torque rating for the planned directional work - **Auxiliary equipment** — solids control, pipe handling, walking systems, and instrumentation - **Offshore operability** — water depth, station-keeping, and required deck load and space, where applicable ### 3.9.2 Contractor Evaluation Beyond the machine itself, the operator evaluates the drilling contractor: - **Mechanical rating and condition** — maximum hookload and torque capacity, maintenance state - **Suitability and familiarity** — is the rig matched to this well type, and has the contractor worked in this area? - **Mobility** — move time between wells, including pad-to-pad walking or skidding capability - **HSE record** — a contractor's safety statistics are among the strongest predictors of project outcomes - **Quality management, financial strength, staff development, and technical support** ### 3.9.3 Contract Types - **Day-rate contract** — the operator pays a fixed rate per day and directs the work; the operator holds most of the drilling risk. The dominant contract form. - **Footage contract** — the contractor is paid per foot drilled, taking on more performance risk. - **Turnkey contract** — the contractor delivers a completed well for a fixed price, assuming nearly all of the risk (and pricing it accordingly). - **Combination** — hybrid arrangements, e.g., footage to intermediate casing and day-rate below. ```{figure} ../figures/ch03/slide_05.png :name: fig-rig-selection :width: 90% :align: center Rig selection criteria: technical decision factors are derived from the well design; contractor considerations include mechanical rating, mobility, contract structure, and HSE record. ``` --- ## Worked Examples ### Example 3.1 — Fast Line Tension and Derrick Load **Problem:** A drillstring produces a hookload of 400,000 lb. The travelling block is strung with 8 lines. Neglecting friction, calculate (a) the fast line tension, (b) the deadline tension, and (c) the total load on the derrick. **Solution:** (a) Each of the $N = 8$ lines carries $1/N$ of the hookload: $$F_\text{fast line} = \frac{W}{N} = \frac{400{,}000}{8} = 50{,}000 \text{ lb}$$ (b) The deadline is simply another line in the same reeving: $$F_\text{deadline} = \frac{W}{N} = 50{,}000 \text{ lb}$$ (c) The derrick carries the hookload plus both line tensions: $$F_\text{derrick} = W\left(\frac{N+2}{N}\right) = 400{,}000 \times \frac{10}{8} = \boxed{500{,}000 \text{ lb}}$$ **Interpretation:** The derrick load exceeds the hookload by 25% in this configuration. Stringing more lines reduces both the fast line tension (easing the drawworks requirement) and the derrick overload factor — at the cost of slower block travel. --- ### Example 3.2 — Triplex Pump Output **Problem:** A triplex mud pump has 6-in liners and a 12-in stroke, operating at 95% volumetric efficiency. The driller runs the pump at 60 strokes per minute. What is the flow rate in bbl/min and gal/min? **Solution:** Displacement per stroke: $$q = 0.000243 \times d^2 \times L \times e = 0.000243 \times 6^2 \times 12 \times 0.95 = 0.0997 \text{ bbl/stk}$$ At 60 SPM: $$Q = 0.0997 \times 60 = 5.98 \text{ bbl/min}$$ $$Q = 5.98 \times 42 = \boxed{251 \text{ gal/min}}$$ **Interpretation:** This is the *calculated* flow rate the rig data system reports — there is no independent flow measurement. If the pump's actual volumetric efficiency has degraded (worn liners or valves), the true flow rate is lower than reported. --- ### Example 3.3 — Trip Time **Problem:** A bit must be replaced at 15,000 ft on a triple rig (90-ft stands). The crew averages 2.5 minutes per stand tripping out and 2.0 minutes per stand tripping in. Estimate the round-trip time, excluding bit handling time at surface. **Solution:** Number of stands: $$n = \frac{15{,}000}{90} = 167 \text{ stands}$$ Trip out: $167 \times 2.5 = 417 \text{ min} = 7.0 \text{ hr}$ Trip in: $167 \times 2.0 = 333 \text{ min} = 5.6 \text{ hr}$ $$\boxed{t_\text{round trip} \approx 12.6 \text{ hr}}$$ **Interpretation:** At a \$60,000/day rig rate, this trip costs about \$31,000 before the new bit drills a single foot — the economic logic behind longer-lasting bits, taller derricks, and every technology that reduces tripping. --- ## Practice Problems **3.1** A casing string produces a hookload of 620,000 lb. The block is strung with 10 lines. (a) Calculate the fast line tension. (b) Calculate the total derrick load. (c) The same rig is later rigged with 12 lines for a heavy casing run. Recalculate (a) and (b) and comment on the trade-off. ```{admonition} Solution :class: dropdown (a) $F_\text{fast} = 620{,}000 / 10 = \mathbf{62{,}000}$ **lb** (b) $F_\text{derrick} = 620{,}000 \times (10+2)/10 = \mathbf{744{,}000}$ **lb** (c) With 12 lines: $F_\text{fast} = 51{,}700$ lb; $F_\text{derrick} = 620{,}000 \times 14/12 = 723{,}300$ lb. Both the drawworks pull and the derrick load decrease — but the drawworks must reel in 12 ft of line per foot of block travel instead of 10, so hoisting is slower. ``` **3.2** A triplex pump with 5½-in liners and an 11-in stroke operates at 100% volumetric efficiency. (a) Calculate the displacement per stroke in bbl/stk. (b) The hydraulics program requires 420 gal/min. What pump speed (SPM) is required? (c) The same pump is fitted with 6½-in liners. What SPM now delivers 420 gal/min, and why might the rig have made this liner change? ```{admonition} Solution :class: dropdown (a) $q = 0.000243 \times 5.5^2 \times 11 = \mathbf{0.0809}$ **bbl/stk** (b) $420 \text{ gal/min} = 10.0 \text{ bbl/min}$; SPM $= 10.0 / 0.0809 = \mathbf{124}$ **SPM** (c) $q = 0.000243 \times 6.5^2 \times 11 = 0.113 \text{ bbl/stk}$; SPM $= 10.0/0.113 = \mathbf{89}$ **SPM**. Larger liners deliver the same flow at lower stroke rate (less wear), but at a lower maximum working pressure — appropriate for a shallow, large-diameter hole section. ``` **3.3** Explain each of the following, in your own words: (a) Why drilling with a top drive requires fewer connections than drilling with a kelly. (b) Why the drillstring cannot be rotated while tripping on the elevators. (c) Why the slips are described as "self-energizing." (d) Why most of the energy of lowering the drillstring passes through the drawworks brakes rather than its motor. ```{admonition} Solution :class: dropdown (a) A top drive screws into the top of the string and can drill down the full length of a stand (90+ ft) before a connection; a kelly can only drill down one kelly length (~30–45 ft) before pipe must be added. (b) The elevators are a latching collar that grips the pipe below the tool joint — they can hoist and lower, but only the top drive can apply torque to the string. (c) The slips are a tapered wedge: the weight of the string pulls the wedge deeper into the tapered bowl, increasing the transverse gripping force in proportion to the load. Heavier string = tighter grip. (d) Raising the string requires work input from the motor; lowering releases the string's potential energy, which must be dissipated. Mechanical (or auxiliary) brakes convert that energy to heat; only the newest electric drawworks can absorb it regeneratively through the motor. ``` **3.4** An operator is selecting a rig for a program of 10,000-ft TVD horizontal wells with 10,000-ft laterals on multi-well pads, in a field with normal pressures and 5,000-ft spacing between pads. (a) List five technical specifications the engineer should derive from the well design before evaluating rigs. (b) Would pad-to-pad walking capability matter for this program? Why? (c) Which contract type would you expect for this factory-style development program, and why? ```{admonition} Solution :class: dropdown (a) Representative answers: maximum anticipated hookload (heaviest casing string with margin); top drive torque rating (long laterals produce high rotating torque); pump pressure, flow, and hydraulic horsepower for the lateral hole size; BOP stack pressure rating from anticipated formation pressures; derrick racking capacity and substructure height for the planned drillstring; solids control capacity for high-ROP lateral drilling. (b) Yes — on multi-well pads, a walking/skidding rig moves between wellheads in hours without rigging down, eliminating days of moving time per well across the program. (c) Day-rate is the dominant form and most likely, with performance incentives increasingly common. Factory-style drilling makes performance benchmarks measurable, so hybrid day-rate contracts with bonus/penalty structures tied to days-per-well are attractive to both parties. ``` **3.5** The driller reports weight on bit (WOB) as hookload off bottom minus hookload on bottom, using the deadline anchor sensor. (a) List four sources of error in this surface WOB measurement. (b) For which well geometry is surface WOB most accurate, and why? (c) A downhole measurement shows the actual WOB is 15,000 lb while the surface calculates 35,000 lb. Where did the missing 20,000 lb go? ```{admonition} Solution :class: dropdown (a) Inertia of the moving blocks and string during acceleration; sheave friction in the block-and-tackle; the changing suspended weight of drilling line with block position; stretch of the drilling line absorbing dynamic loads (plus calibration only being exact at one block position, and drillstring-wellbore friction). (b) A vertical well — with minimal wellbore contact, almost all of the surface weight change reaches the bit. In deviated and horizontal wells, friction between the string and the wellbore wall carries part of the load. (c) Into friction between the drillstring and the wellbore wall — in a deviated or horizontal well, a large fraction of the surface slack-off weight is supported by wall contact drag and never reaches the bit. ``` --- ## Summary This chapter has covered the drilling rig, the machine at the center of every operation in this textbook: - A rig performs four functions: hoisting, rotating, circulating, and maintaining well control. Its operations, drilling, tripping, running casing, cementing, evaluation, completion, workover, abandonment, divide rig time roughly into thirds of drilling, tripping, and casing/cementing. - Land rigs are mobile and classified by stand capacity (single through quad); offshore rig type follows water depth (jackup, semi-submersible, drillship). Day rates span \$25,000/day on land to \$1,000,000/day in deepwater. - The hoisting system multiplies drawworks force through a block-and-tackle: each of $N$ lines carries $W/N$, and the derrick carries $W(N+2)/N$. The hookload measurement at the deadline anchor is exact only for a static, calibrated system. - The rotary system has converged on the top drive, which drills full stands, backreams, and maintains toolface — with the kelly and rotary table remaining only as backup. Slips hold the string during connections; iron roughnecks and automated pipe handling have removed people from the most dangerous rig-floor jobs. - The circulating system is a closed loop: pumps → standpipe → swivel → drillstring → bit → annulus → shakers → pits. Flow rate is calculated from pump strokes, not measured directly. - The well control system, the BOP stack, accumulators, and choke and kill manifold, is the mechanical line of defense when the mud column alone cannot contain formation pressure. - Rig selection derives technical specifications from the well design (hoisting, hydraulics, torque, pressure ratings) and weighs contractor qualities (HSE record, mobility, familiarity) under day-rate, footage, or turnkey contract structures. --- ## References Mitchell, R.F. and Miska, S.Z. (eds.), *Fundamentals of Drilling Engineering*, Society of Petroleum Engineers, 2011. Bourgoyne, A.T., Millheim, K.K., Chenevert, M.E., and Young, F.S., *Applied Drilling Engineering*, Society of Petroleum Engineers, 1986. Moore, W.W. (ed.), *Fundamentals of Rotary Drilling*, Energy Publications, Dallas, 1981.