You must log in to edit PetroWiki. Help with editing

Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. More information

PEH:Offshore Drilling Units

Jump to navigation Jump to search

Publication Information


Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume II - Drilling Engineering

Robert F. Mitchell, Editor

Chapter 14 - Offshore Drilling Units

By Mark A. Childers, Atwood Oceanics

Pgs. 589-646

ISBN 978-1-55563-114-7
Get permission for reuse

The growth and evolution of offshore drilling units have gone from an experiment in the 1940s and 1950s with high hopes but unknown outcome to the extremely sophisticated, high-end technology and highly capable units of the 1990s and 2000s. In less than 50 years, the industry progressed from drilling in a few feet of water depth with untested equipment and procedures to the capability of drilling in more than 10,000 ft of water depth with well-conceived and highly complex units. These advances are a testament to the industry and its technical capabilities driven by the vision and courage of its engineers, crews, and management. From an all-American start to its present worldwide, multinational involvement, anyone involved can be proud to be called a "driller."

Since the beginning in the mid-1800s until today, the drilling business commercially has been very cyclic. It has been and still is truly a roller-coaster ride, with rigs being built at premium prices in good economic times and sold for pennies on the dollar in bad times. Mergers, acquisitions, fire sales, and buyouts have occurred throughout its history, yet during all these times, the drilling segment has served the oil and gas industry well. Unfortunately, all this turmoil has been hard on the people involved, but they keep coming back with enthusiasm to this very interesting and stimulating industry.

In the early days, public image, safety, and the environment took a backseat to the technical and operational challenges of offshore drilling. Today, however, these issues often drive the whole thrust of drilling activities and operations. The offshore drilling business is now a worldwide, multibillion-dollar business with high visibility that has a strong influence on the world ’

s economic health and people of all nations.

The offshore drilling business is one of the most challenging, exciting, and rewarding businesses in which an individual can be involved. This chapter focuses on the history and evolution of offshore drilling rigs and describes the various types of offshore drilling units. The capabilities and limitations of mobile offshore drilling units (MODUs) are discussed, followed by specific subjects that have a direct bearing on their operation and use. Health, safety, environment, and security (HSE&S) also are discussed because these subjects have become a major element in the industry. The importance and reason for classification, registration, and regulation of the units are presented, along with a discussion on the relationship of the contract drillers and their customers, the operators. And for the user, an explanation is given concerning selection of the appropriate type of drilling unit for a particular job.

History and Evolution

When did offshore drilling start? If "offshore" is defined as a large body of open water generally considered an ocean or sea, in 1897, just 38 years after Col. Edwin Drake drilled the first well in 1859, H.L. Williams is credited with drilling a well off a wooden pier in the Santa Barbara Channel in California. He basically used the pier to support a land rig next to an existing field. Five years later, there were 150 "offshore" wells in the area. By 1921, steel piers were being used in Rincon and Elwood (California) to support land-type drilling rigs. In 1932, a steel-pier island (60 × 90 ft with a 25-ft air gap) was built ½ mile offshore by a small oil company, Indian Petroleum Corp., to support another onshore-type rig. Although the wells were disappointing and the island was destroyed in 1940 by a storm, it was the forerunner of the steel-jacketed platforms of today.[1]

In 1938, a field was discovered offshore Texas. Subsequently, a 9,000-ft well was drilled in 1941 in fashion similar to the California wells by use of a wooden pier; however, with the start of World War II, all offshore drilling activities halted. After the end of World War II, the state of Louisiana held an offshore state waters lease sale in 1945. This was followed in 1955 by the state of California (Cunningham-Shell Act) lease sale, which allowed exploration of oil and gas sands.[1] Before the latter act, core drilling could be done only until a show of oil and gas. At that time, all drilling had to stop and the core hole plugged with cement.

The first "on-water drilling" was born in the swamps of Louisiana in the early 1930s with the use of shallow-draft barges. These barges were rectangular with a narrow slot in the aft end of the barge for the well conductor. Canals were and still are dredged so that tugs can mobilize the barges to locations. Later, barges were "posted" on a lattice steel structure above the barge, allowing them to work in deeper water depths by submerging the barge on the bay bottoms. These barges usually required pilings around them to keep them from being moved off location by winds and waves. The first "offshore" well, defined as "out of sight of land," was started on 9 September 1947 by a tender assist drilling (TAD) unit owned by Kerr-McGee in 15 ft of water in the Gulf of Mexico (GOM). An ex-World War II 260 × 48-ft barge serviced the drilling equipment set (DES), which consisted of the drawworks, derrick, and hoisting equipment located on a wooden pile platform.[2] TADs are discussed in more detail later.

The Breton Rig 20 (Fig. 14.1), designed by John T. Hayward who was with Barnsdall Refining Co. at the time, was a large "posted" submersible barge credited in 1949 with drilling some of the first wells in the open waters of Louisiana. What made it different from the Kerr-McGee barge was that all the drilling equipment was on one barge that could be towed as a complete unit. The unit, which was a conversion from an inland drilling barge, had two stability pontoons, one on each side of the barge, that hydraulically jacked up and down as the barge was submerged and pumped out. These pontoons provided the necessary stability for this operation. TheBreton Rig 20, later known as the Transworld Rig 40, was a major step forward because it eliminated the cost and time required to build a wooden platform to support all or some of the offshore-type rig. Although it drilled only in predominantly protected bays in shallow water (less than 20 ft), the Breton Rig 20 may be able to lay a qualified claim as being the first MODU.[3], [4]

The first truly offshore MODU was the Mr. Charlie, designed and constructed from scratch by Ocean Drilling and Exploration Co. (ODECO) headed by its inventor and president, "Doc" Alden J. Laborde. The Mr. Charlie (Fig. 14.2) was truly a purpose-built submersible barge built specifically to float on its lower hull to location and, in a sequence of flooding the stern down, ended up resting on the bottom to begin drilling operations. When the Mr. Charlie went to its first location in June 1954, Life magazine wrote about the novel new idea to explore for oil and gas offshore.[5] The Mr. Charlie , rated for 40-ft water depth, set the tone for how most MODUs were built in the GOM. Usually an inventor secured investors, in this case Murphy Oil, and then found a customer with a contract to drill for, in this case Shell Oil, allowing bank loans to be obtained to build the unit.

Because the shelf dropped off quickly and water depths increased rapidly offshore California, the approach there was entirely different from that in the GOM. Rigs were installed on surplus World War II ship hulls modified to drill in a floating position compared with sitting a submersible barge on the ocean bottom, as done in the GOM. Oil companies formed partnerships or proceeded independently, but MODUs were not designed and constructed by contract drilling companies in California. All design and construction was done in a highly secretive manner with little sharing of knowledge because technology was thought to give an edge in bidding for state oil and gas leases. Before the leasing of oil and gas rights in 1955, oil companies cored with small rigs cantilevered over the side midship of old World War II barges. These barges did not have well-control equipment or the ability to run a casing program. They could only drill to a designated core depth with the understanding that if they drilled into any oil and/or gas sands, they would stop, set a cement plug, and pull out of the core hole. These core vessels were highly susceptible to wave action, resulting in significant roll, heave, and pitch, which made them difficult to operate.

With leasing from the state of California to explore and produce oil and gas, well control and the ability to run multiple strings of casing became mandatory and required a totally new, unproven technology. The first floating drilling rig to use subsea well control was the Western Explorer (Fig. 14.3) owned by Chevron, which spudded its first well in 1955 in the Santa Barbara Channel. Others followed quickly, with all of them concerned about the marine environment and technology to allow drilling in rough weather. In 1956, the CUSS 1 was built from another World War II barge. The unit, built by the CUSS group (Continental, Union, Shell, and Superior Oil), was 260 ft long and had a 48-ft beam. The CUSS group eventually evolved into what is now Global Santa Fe.

The original designers had no examples or experiences to go by, so novelty and innovation were the course of the day. Torque converters on the drawworks were used as heave-motion compensators; rotaries were gimbaled to compensate for roll and pitch; the derrick was placed at midship over a hole in the vessel called a "moonpool"; blowout preventers (BOPs) were run on casing to the seafloor; re-entry into the well was through a funnel above a rotating head (riserless drilling is not new); mud pits were placed in the hull with mud pumps; and living quarters were added. It was an exciting and amazing time, considering that everyone was starting with a blank sheet of paper.

Fig. 14.4 shows the Humble SM-1 drilling barge (204 × 34 × 13 ft) built and owned by Humble Oil and Refining Co. (now ExxonMobil) in 1957. Fig. 14.5 shows the subsea equipment used to drill the wells. Note that it has no marine riser. The Humble SM-1 drilled 65 wells for a total cost of $11.74/ft, about double the cost of land drilling at the time, in an average water depth of 159 ft and with a maximum well depth of 5,000 ft. The unit averaged 8.93 days per well and drilled an average of 324 ft/D. Unfortunately, the unit sank in a storm in 1961 while on loan to another operator.[6] At the insistence of insurance underwriters, the American Bureau of Shipping (ABS) wrote and implemented in 1968 the first independent codes, guidelines, and regulations concerning the design, construction, and inspections of MODU hulls.

With the Mr. Charlie (bottom founded) and Western Explorer (floating) as the first MODUs, another concept for a MODU showed up in the form of a "jackup". This type of unit floated to location on a hull with multiple legs sticking out under the hull. Once on location, the legs were electrically or hydraulically jacked down to the ocean bottom, and then the hull was jacked up out of the water. With this approach, a stable platform was available from which to drill. In World War II, the De Long spud can jacks were installed on barges for construction and/or docks. The De Long-type rigs (Fig. 14.6 shows an example, the Gus I) were the first jackups built in 1954.[7] Although jackups initially were designed with 6 to 8 legs and then a few with 4 legs, the vast majority of units today have 3 legs. The Gus I was constructed with independent legs. The Le Tourneau Co. built for Zapata Corp. the first lattice-leg jackup, the Scorpion (Fig. 14.7), which had independent legs with spud cans. To this day, Le Tourneau continues to specialize in lattice-leg-type jackup MODUs.

A major evolution for the jackup design was the introduction of the cantilevered drill-floor substructure (Fig. 14.8) in the late 1970s and early 1980s. As fixed platforms got bigger, the slot jackups could not "swallow" or surround the platform with its slot containing the drilling equipment; however, the cantilever units could skid the cantilever out over the platform after jacking up next to it. Before the cantilevered substructure, all jackups had slots, usually 50 ft square, located in the aft end of the hull. During tows, the substructure was skidded to the metacenter of the hull, but during drilling operations, the substructure was skidded aft over the slot. The derrick and/or crown could be skidded port/starboard to reach wells off center just like today

’ s units do. The water depth range for most of the early slot and cantilever designs was from 150 to just over 300 ft; cantilever drill-floor centers had a reach of 40 to 45 ft aft of the aft hull transom; and variable deck load (VDL) ratings were 3,500 to 5,000 kips. In the late 1990s, "premium" or "enhanced" jackups were designed and built that could carry much larger deck loads (≥ 7,000 kips), could drill in deepwater depths (≥ 400 ft), had more capable drilling machinery (7,500-psi high-pressure mud systems and 750-ton hoisting equipment), had extended cantilever reach of ≥ 70 ft, and had larger cantilever load ratings of double or more the earlier units (some>

2,500,000 lbm).

The TAD concept was used to drill the first offshore "out of sight of land" well in the world. Initially used as an exploration method, it has evolved into a development tool. The first tenders were shaped like barges, but some are now shaped like ships for better mobilization speeds. Basically, the DES consists of the derrick, hoisting equipment, BOPs, and some mud-cleaning equipment, thus reducing the required space and weight to be placed on the fixed platform. All the rest of the rig, such as mud pits, mud pumps, power generators, tubulars and casing storage, bulk storage, accommodations, fuel, and drill water, is located on the tender hull moored next to the fixed platform. This approach turned out to be a very cost-effective way to drill from small fixed platforms. Unfortunately, in mild and especially severe weather, the mooring lines could fail, with the hull floating away, as it often did in a GOM "norther." Today, most TADs operate in benign or calm environments in the Far East and West Africa.

In 1992, the first semisubmersible (semi) Seahawk TAD (Fig. 14.9) was converted from an old semi MODU. The semi hull offers superior station keeping and vessel motions compared with ship or barge-shaped hulls. In a semi hull, the wave train can move through the "transparent" hull without exciting it to heave, roll, and pitch, unlike a mono hull. The lower hull of the semi is below the water at a deeper draft; the columns offer a reduced area to excite the hull; and the work platform or main deck is above all wave action. TADs are seeing new use on deepwater production platforms, such as spars, tension leg platforms (TLPs), and deepwater fixed platforms, which operate beyond jackup water depths.

Things were off and running in the 1950s, with numerous operators getting into the rig ownership and operation business and new drilling contractors being formed every year. In the early 1960s, Shell Oil saw the need to have a more motion-free floating drilling platform in the deeper, stormier waters of the GOM. Shell noticed that submersibles like the Mr. Charlie, now numbering almost 30 units, were very motion free afloat compared with monohulls. The idea was to put anchors on a submersible, use some of the California technology for subsea equipment, and convert a submersible to what is now known as a semisubmersible or semi. Thus, in 1961, the submersible Bluewater I (Fig. 14.10) was converted to a semi amid much technological secrecy. In fact, in the mid-1960s, Shell Oil offered the industry the technology in a school priced at U.S. $100,000 per participant and had lots of takers.

Then came the Ocean Driller, the first semi built from the keel up (Fig. 14.11. The Ocean Driller, designed and owned by ODECO, went to work for Texaco in 1963, with the mooring and subsea equipment owned by the operator, as was common in the 1960s. The unit was designed for approximately 300 ft of water depth, with the model tests of the hull done in Doc Laborde’ s swimming pool. The Ocean Driller could also sit on bottom and act as a submersible, which it did well into the 1980s. Most of the first-generation units could sit on bottom or drill from the floating position as a hedge against unemployment. The shape and size of the first semis varied widely as designers strived to optimize vessel motion characteristics, rig layout, structural characteristics, VDL, and other considerations. The "generation" designation of semis is a very loose combination of when the unit was built or significantly upgraded, the water depth rating, and the general overall drilling capability. Generation is discussed in more detail later.

In the early 1970s, a new, second-generation semi was designed and built with newer, more sophisticated mooring and subsea equipment. This design generally was designed for 600-ft water depth, with some extending to>

1,000 ft. The Ocean Victory class (Fig. 14.12) was typical of the units of this era, which concentrated heavily on reducing motions of the platform compared with increased upper-deck VDL rating. Many were built, and in the middle to late 1980s, a number of third-generation semis were designed and built that could moor and operate in> 3,000 ft of water depth and more severe environments. Many of the third-generation units were upgraded in the 1990s to even deeper water depth ratings with more capabilities and became fourth-generation units. With a few exceptions, the operating displacement of these units went from ≈18,000 long tons in the 1970s to>

40,000 long tons in the 1980s.

In the late 1990s, the fifth-generation units, such as the Deepwater Nautilus shown in Fig.14.13, became even larger (>

50,000-long-ton displacement) and more capable. These units can operate in extremely harsh environments and in>

5,000-ft water depth. Some second- and third-generation semis have been converted, given life extensions to their hulls and upgrades to their drilling equipment so as to be classed as fourth-generation units.Fig. 14.14 shows a second-generation Ocean Victory class unit (see Fig. 14.12 ) that was completely upgraded to a fifth-generation unit capable of mooring and operating in 7,000-ft water depth. Note the addition of column "blisters" for increased VDL, ≈ 50% increase in deck space, and the addition of riser storage and handling. A limited number of third-, fourth-, and fifth-generation semis have dynamic positioning (DP) assist or full-DP station keeping compared with a spread-mooring system.

Fifty years ago, fixed platforms had land rigs placed on them to drill and complete wells. Today’

s platform rigs have been repackaged so that they optimize the rig-up/load-out time, require less space, are lighter, and have more drilling capabilities; thus, they have become very sophisticated. Drilling platform rigs are still common, but today’

s units look far different from those of 30 or 40 years ago. Conventional platform rigs are usually loaded out with a derrick barge. Some large platforms may have two drilling units on them. To eliminate the costly derrick barge, "self-erecting" modular rigs have been built for light workovers and for drilling to moderate depths. Larger units that have the capability of a 1-million-lbm hook load have been built that are lightweight, easier to rig up/load out, and self-erecting. The advent of spars and TLPs in deep water, where space and deck load are critical, has generated even a more sophisticated modular deepwater platform rig, which is highly specialized to the structure on which it sits (Fig. 14.15). These platform rigs are not self-erecting, are unique to the structure they are placed on, generally are very light, and usually have limited drilling equipment capabilities.

By the mid-1960s, the jackup-designed rigs were displacing submersibles in increasing numbers. Jackups had more water depth capability than even the largest submersibles (some could operate in 175-ft water depth),[7] and they did not slide off location in severe weather. From this point on, jackup and semi designs were refined and made larger and more capable from a drilling and environmental standpoint.

Ship and barge-shaped floating MODUs, initially attractive because of their transit speed and ease in mobilizations, decreased in number as semis and jackups became more popular. One exception was the DP drillship, which held location over the wellbore by use of thrusters and main screw propulsion rather than a spread-mooring system. The first unit developed in the mid-1960s, although not an oil and gas exploration unit, was the Glomar Challenger, which was designed and owned by Global Marine (now Global Santa Fe) and contracted by the National Science Foundation for deep-sea coring around the world. This vessel confirmed the theory of shifting continental plates. Following the Glomar Challenger in the late 1960s to early 1970s were a number of first-generation DP oil and gas drillships, such as the Sedco 445. Subsequently, in the middle to late 1970s, the second-generation DP units were developed, such as the Ben Ocean Lancer. The Ben Ocean Lancer was an IHC Holland Dutch design, which also included the French rigs Pelerin and Pelican, which were owned by the French company Foramer (now Pride). These units could drill in up to ≈ 2,000- to 3,000-ft water depth, had better station-keeping ability in moderate metocean conditions, and had better overall drilling capabilities. DP ships of the late 1990s and early 2000s can operate in>

10,000-ft water depth and are two to three times larger than the earlier DP ships, with extremely complex station-keeping and dual-activity drilling systems. Dual drilling consists basically of some degree of two complete derricks and drilling systems on one hull so that simultaneous operations, such as running casing while drilling with the other derrick, can be done. These units are very expensive to build and operate but can overcome their cost with supposedly higher efficiency. For the right conditions, such as batch drilling a subsea template, large development projects over a template, deepwater short wells, and well situations in which more than one operation can benefit the overall plan, these units need to be reviewed for possible use as an alternative to standard single-operation units.

The offshore drilling industry has had spurts of construction and design improvements over its 50-year history. The first was the conception of the MODUs in the mid-1950s, followed by a mild building period in the mid-1960s. In the early 1970s, there were significant numbers of jackups and semisubmersibles built. However, the major boom of the late 1970s and early 1980s has been unmatched in numbers of rigs built. Starting in the late 1980s, a number of drilling contractors upgraded rigs built in the 1970s and early 1980s to deepwater depths, more severe environmental ratings, and better drilling abilities rather than building new units. The concept was that delivery and cost could be cut in half compared with a new build. Some drilling contractors have successfully built their entire business plan around conversion instead of new build.

Since the oil and gas bust of the mid-1980s, there has only been one spurt of new building, and that was in the late 1990s. Mergers and buyouts of drilling contractors and rigs dominated the industry from the mid-1980s to the mid-1990s. One drilling contractor, Global Santa Fe, monthly publishes a percentage number related to day rate and cost of building a new unit. A 100% rating means new units can be built profitably; however, the percentage number has lingered in the 40 to 60% range over the last 15 years or so, with spurts into 80%. By its nature, the drilling business is built on optimism for the future that may not always show proper returns on investment in terms of new builds or conversions. High on hope and the future, the contract drilling business has historically not been conservative and has not followed generally accepted rules of investment.

In the early 2000s, the average age of the fleet was> 20 years, with some units> 30 years old. Few are< 5 years old. Some have been upgraded and have had life extensions, which means that, with good care and maintenance, the basic hull, if it and/or the rig are not rendered technologically obsolete, may last> 40 years, as do units in the dredging business. "Technologically obsolete" means that the unit needs to have up-to-date top drive, mud-solids control, and pipe handling equipment, among other features, as well as enough power to run all the new equipment. The fleet in 2003 stood at approximately 390 jackups, 170 semis, 30 ships, and 7 submersibles. Fixed-platform rigs number about 50, and TADs number about 25.

The consensus is that the offshore drilling business will continue to grow, with emphasis on technical breakthroughs to reduce drilling costs. The industry has demonstrated that it can drill in water depths up to and>

10,000 ft and can operate in the most severe environments, but all at a very high cost that can run into hundreds of thousands of dollars per day. Ultra deepwater wells costing more than $50 million are common, and some wells have cost more than $100 million. It is very difficult to justify wells that cost this much given the risks involved in drilling the unknown. The challenge to the offshore industry is to drill safely and economically, which means "technology of economics," with safety, environment, security, and personnel health all playing a large role.

Rig Types, Designs and Capabilities

The previous section discusses the history and evolution of offshore MODUs and related offshore drilling units. This section gives more detailed technical description of today ’ s units, their advantages and disadvantages, capabilities, and operating characteristics. One may ask why there are so many types, sizes, and capabilities of offshore units. The answer involves different technical, economic, government, and safety requirements to accomplish a specific drilling program. No one type can satisfy all the requirements for every drilling location; thus, we have to understand all types to make a correct decision on their use.

Fixed-Platform Rigs

As the name indicates, this type of rig is located on a fixed structure previously installed at the well location. The structure may be a fixed jacketed platform, spar, TLP, or gravity structure; whatever it is, the rig sits atop it. Fixed platforms may have as few as 3 or 4 or > 50 well conductors. Generally, the drilling rig is not a permanent part of the fixed structure; however, on some occasions, the unit is left on the platform for future workovers or additional drilling; sometimes, removing it is uneconomical. Most units are complete, totally self-contained units that include their own power plant, accommodations, drilling equipment, life-saving equipment, and auxiliary services. However, some do not have their own power plant and obtain power from the platform’ s generators, which are usually powered by produced natural gas. On large, central field platforms that have their own living quarters, the rig may not have its own accommodation facilities. In this case, the life-saving equipment (e.g., lifeboats and gas-detection, fire-fighting, and communication systems) is part of the fixed platform. Most fixed platforms have their own craneage, but usually it is not big enough to load or unload the components of a conventional platform rig. Most modern platforms are built to American Petroleum Inst. (API) standards, thus allowing movement of a standard API-configured platform rig from platform to platform with little or no modification.

There are three types of fixed-platform rigs. The first type is the conventional standard platform rig that is not self-erecting, is not particularly modular in construction, is heavy, and is built to API well spacing standards, so it can work on a wide range of platforms. This type of rig usually requires a derrick barge or a large platform crane to load and erect. Erection time may be 2 to 4 weeks, and its dry weight will probably exceed> 5,000 kips. These rigs are usually self-contained and can include up to and in a few cases over a 1 million lbm of derrick and traveling equipment.

The second type of rig is a self-erecting, self-loading, and highly modularized rig set up to go from platform to platform quickly. Generally, they take up much less space, and their dry weight (750 to 1,250 kips) is considerably less than that of a conventional standard platform rig. Unfortunately, most of these rigs have limited hook and traveling-block capacity and sometimes do not have all the auxiliary equipment, such as bulk tanks, large liquid-mud-storage capacity, and emergency power. They are particularly attractive for in-casing workovers and out-of-casing redrills. A few of the larger modular rigs have hook load ratings of 1 million lbm but also have compromised weight and ease of mobilization. Modular rigs first appeared in the late 1980s and early 1990s. They generally have no module weighing> 30 tons, have a self-erecting "leap frog" crane, contain modules that can be transported on any standard-sized workboat, and can be completely rigged up or down in 2 to 3 days.

A third type of the modular fixed-platform rig that has gained popularity recently is site-specifically designed and constructed to be placed on deepwater spars and TLPs. These modular rigs are very compact, lightweight, and site-specifically built (Fig. 14.15). Their mobilization and rig-up time is much more than that of a standard modular rig. Because they are generally not self-erecting, total rig-up and rig-down time and cost are an issue.

The first consideration in using a fixed-platform rig, usually controlled by the operator, is whether the platform is large enough and has a high enough load bearing to place and work the rig. This includes the space and dry weight of the rig itself, wet weigh (mud, operator fixed items, liquids, portable tools, etc.), live loads (hook, setback, and rotary), storage, and such expendable items as bulk casing and operator supplies. Generally, a four-pile structure is the smallest fixed structure that a conventional standard platform can be placed on and work efficiently. Usually, the second consideration is the mobilization method and cost. Numerous platform rigs when broken down for shipment cannot fit on a standard workboat, and thus a derrick barge is required. All modular rigs can usually fit on a workboat.

Why would someone want to use a fixed-platform rig? Generally, their day rate is considerably less than that of a jackup, assuming that the platform is in accessible jackup water depth and that there are enough wells to warrant the mobilization cost. The decision to use a jackup or standard platform rig is usually controlled by the number of wells to be drilled; the more wells there are to drill, the more attractive the platform rig becomes. Of course, the platform water depth, availability of a suitable jackup, metocean, and the mobilization cost and time of either unit are also factors. In shallow water, less expensive jackups are available; however, a platform rig will be more economical in deeper water. Market conditions at the time of use, like all rig types, are usually the driving economic force. Another alternative to a platform rig is a TAD; however, availability will be a problem because there are so few units, especially semi TADs. Environment may be an issue for monohull tenders. With semi TAD hulls, environment should not be an issue.

With a semi TAD, operating efficiency is higher. Studies have shown that a tender with very large load-carrying capability and space availability is operationally very attractive. A number of operators have stated that they think a semi TAD is 10 to 25% more efficient as controlled by workboat transit time, weather, specific type of wells being drilled, and space/weight limitations of the platform and platform rig.

There is no standard, easy answer for all situations to specifically recommend a specific rig type. With the appearance of extended-reach wells (ERWs), the required loads and space are becoming so great that a cantilevered jackup or TAD sometimes becomes a more attractive alternative than even a large standard platform rig.

Tender Assist Drilling

TADs were the rig of choice in the 1950s and early 1960s in the GOM for development drilling off fixed platforms. However, the monohull tenders tended to lose location with mooring failures during storms. This occurrence, along with severe motions of the tender, resulted in their losing favor, except for use in very mild or benign environments, such as in the Far East and West Africa. There are about 25 TADs in existence today, with most being monohull tenders. Four are semi tenders and offer the motion characteristics to drill in mild to somewhat severe environments. The TAD advantage is that its DES is relatively lightweight, one-quarter to one-fifth the weight and one-third the space of a standard platform rig. Most TADs carry the DES on the tender hull and are self-erecting, so no workboat or derrick barge is required. They are particularly attractive for situations in which there is an old platform with reduced load-carry ability and/or space, such as when a platform was drilled with a standard platform rig and then production equipment was loaded onto the platform, thus eliminating space and load-carry capacity. It is not unusual for a platform to deteriorate with age and then be unable to hold up a standard platform rig when additional wells need to be drilled. The TAD is an option for this situation. Of course, if the platform is in jackup water depth range, the jackup may also do the drilling if its cantilever can reach the well centers with adequate load capacity and if there are no incompatible spud can holes and/or a severe punch-through condition.

For spars and TLPs in deep water where weight and space are at an absolute premium, TADs, particularly semi TADs with their lightweight DES, have significant advantages in some cases over a modular platform rig. This is usually true for spars and TLPs with > 9 or 10 wells up to a maximum of ≈ 24 wells. For spars and TLPs with< 9 or 10 wells, their load and space availability are too small for any type of platform rig or DES, and those with> 24 wells are large enough to support a modular platform rig without a large weight and space penalty assuming all other factors are equal.

Semi TADs also have the advantage of acting as construction barges for platforms that are commissioning production equipment. Their large rig-up crane, open decks where the DES is stored and transported, accommodations, and general facilities offer a relatively inexpensive construction platform compared with a construction derrick barge.

Why would anyone want to use a TAD? They may be particularly attractive for standard platforms in water depths over jackup-rig rating and where space and/or load limits are a major factor, for deepwater spars and TLPs with the right number of wells, and for any platform where weight and space for long ERW are limited. Generally, a TAD costs more than a platform rig, especially the modular type, but they are a very attractive option for certain situations.

Conventional Ship- and Barge-shaped Rigs

In the early days, ships were very attractive and the most common floating MODUs. They mobilized quickly and could carry a large amount of operator consumables, such as casing and bulk mud. However, their motions in weather proved to be a significant disadvantage in even mild environments. If a ship-shaped unit was hit on its beam with even moderate swells, the roll could raise havoc with efficient productivity. Fig. 14.16 shows a typical spread-moored drillship from 1970. The Offshore Co. (now Transocean) developed and patented the turret mooring system (Fig. 14.17). This system solved some of the motion problems, but other problems remained: decks were sometimes awash with green water, the turret could store only a limited amount of mooring wirerope because the winches were all located on the turret "plug," and the subsea BOP usually had to be stored on the drill floor. When the total number of MODUs increased, thus reducing the number of long mobilizations, and the number of semis in particular increased, the semi, with its vastly superior motion characteristics, became the MODU of choice for floating work. Another factor is that even though ships could carry large amounts of consumables, their space utility and connivance were limited by their cigar shape. The heyday of these units was the late 1950s to late 1960s, with a few being built in the early 1970s. Not until the late 1990s were more drillships built in the form of DP ultradeepwater units.

This section refers only to the spread-moored units, which were usually rated at

< 1,000-ft water depth unless their mooring system was supplemented with mooring line inserts (i.e., mooring lines were inserted into the MODU’ s own lines by use of anchor-handling boats). For instance, ≥ 1,500 ft of mooring wirerope may be inserted into the mooring line of the drillship’ s own lines, thus increasing its line length and scope. With the inserts, some units have rated themselves at> 2,000 ft, but mooring MODUs in this manner is time-consuming and expensive. The alternative to moored MODUs is DP units, with their self-positioning thrusters and propulsion, are discussed later. Barges or non-self-propelled units are also not discussed here because these units, which are few in number, are used in lakes, bays, and buoys, not in offshore areas. Today, there are very few moored drillships left, and they operate only in the mild, benign environments of the Far East and West Africa. Most are> 25 years old and generally have not been upgraded technologically, which is another of their disadvantages.

Why would anyone want to use a drillship? If a location with a very benign environment is under consideration, if a conventional well is to be drilled, if the well is in a remote location where logistics is a primary consideration, and if mobilization of another type of unit is costly, then price is the driving factor.


Today, there are only seven submersibles left in existence, all located in the GOM. Their water depth range is between 9 and 85 ft, with a lesser depth rating during hurricane season. They have a narrow water depth range; however, unlike moored drillships, today they serve an important, although limited, segment of the market. Most jackup rigs cannot operate in < 18 to 25 ft of water, although a very few can move into as little as 14 ft of water. However, when they operate in very shallow water, their hull often must be placed on the ocean bottom so that their legs can be pulled. Jackup hulls are not designed for this type of service, although if no obstructions (e.g., rock outcrops, boulders, wellhead stubs, and pipelines) are present, jackups can be used. When the spud cans come out of the mud, the mud spills over onto the deck, making a huge mess. Cleaning the deck usually requires high-pressure wash-down pumps.

Submersibles are attractive in shallow water of< 14 to 20 ft and/or where the ocean bottom is very soft (< 60-psf shear strength). These soil conditions are common in river delta areas such as around the Mississippi River delta. In these areas, independent-leg jackups may drive their legs well beyond 100 ft, and then the legs may not be retrievable. Even if a mat-type jackup is used, the mat may be submerged, resulting in a loss of mat stability. In these conditions, the submersible becomes attractive.

Submersibles also have other advantages in that their VDL or well-consumable load-carrying ability is usually much higher than for comparable shallow-water jackups. They also do not leave a "footprint" like an independent-leg jackup does with its spud can holes. These footprints can cause significant structural leg problems when another jackup with different leg spacing is jacked up in the same area. Even if the second rig jacks up, it may slide into the previous spud can holes and lose its position over the platform, possibly causing significant leg damage.

The biggest disadvantage of submersible units in the past has been their susceptibility to sliding off location in even mild storms. However, one of the seven units, the Atwood Richmond, installed a patented station-keeping system in 2000 consisting of four 10-ft-diameter suction piles that are easily self-installable and retrievable. In 2002, the system held the unit on location in a hurricane with> 142-mile/hr winds and 30-ft seas.


The jackup-type MODU has become the premier bottom-founded drilling unit, displacing submersibles and most platform units. The primary advantage of the jackup design is that it offers a steady and relatively motion-free platform in the drilling position and mobilizes relatively quickly and easily. Although they originally were designed to operate in very shallow water, some newer units, such as the "ultra-harsh environment" Maersk MSC C170-150 MC, are huge (Fig. 14.18) and can be operated in 550 ft in the GOM. With 673.4-ft. leg length, a hull dimension of 291×336×39 ft, and a VDL of 10,000 long tons, it is mammoth and rivals some of the larger semis. This type of unit can be commercially competitive only in the North Sea and in very special situations.

There are two basic types of jackups, the independent-leg type, usually three legs with lattice construction, and the mat type, in which the legs are attached to a very large mat that rests on the ocean bottom. Both types of jackups have a hull, float onto location, jack the legs to the ocean bottom, and then jack the hull out of the water.

For the independent-leg units, "preloading" is required to drive the legs into the ocean bottom before the hull is completely jacked out of the water. During this procedure, the jackup MODU is at risk from weather and leg "punch through"; i.e., one leg breaks through a hard crust thus putting the other legs in a large bending movement. Generally, 5-ft swells and/or a combined sea of 8 ft are the maximum seas in which these units can jack out of the water. If the hull should roll, pitch, and heave to an extent that the legs come into contact with the ocean bottom, particularly if it is hard, the legs can be severely damaged. In addition, the preload sequence is usually done in stages, with the hull never rising

> 5 ft out of the water to safeguard against having a leg punch through. If the ocean bottom is soft and consists of clay, it is not uncommon to take 7 or more sequences, with each sequence taking 7 to 12 hours. The unit’

s pumps seawater into its preload tanks, adding weight to the hull and driving the legs. After the legs are driven and the hull goes into the water, the seawater is dumped overboard and the sequence is begun again. This process occurs until the legs no longer penetrate the ocean bottom. The concept is to load the legs to a level above that which the unit will encounter in the harshest predicted environment. The newer, enhanced premium units do a single preload in which the jacking system is strong enough to jack the unit with all the preload water onboard, the basic weight of the hull, and the full transit VDL. This is a significant advantage in that a much smaller "weather window" can be acceptable to move the unit. Jackups are most susceptible to major damage or loss when they are floating.

The mat-type jackup also usually consists of three legs that are cylindrical and are from 8 to 12 ft in diameter (Fig. 14.19). The mat is carried just under the hull during mobilization, usually with ≈ 5-ft gap. When the unit comes onto location, it jacks the mat down to the ocean bottom, and because of its low bearing pressure, usually under 500 to 600 psf, the unit jacks the hull out of the water without going through the preload sequence required for independent-leg units. Bethlehem Steel Corp. built most of these units from the 1950s through the 1980s. Their key advantages are that they were relatively inexpensive to build and leave no footprint at the drilling location.

Unfortunately, the mat is also very susceptible to damage from any object on the ocean bottom. Mat-type jackups tow very slowly because the mat and hull are large and create a lot of drag. Their mats are susceptible to being gouged by workboat propellers, their upper hull has limited open deck storage space, and their legs sometimes form a wind-induced leg vibration known as vortex shedding (a form of severe vibration seen with smoke stacks without spoilers) at high winds, which can cause them to fail. Most mat rigs have cylinders for legs and are structurally limited to shallower water depths, usually< 250 to 275 ft. Only a very few units have reached 300 ft, and these units have lattice-type legs. For all these reasons, mat jackups have fallen into disfavor, although they are relatively inexpensive and for some well types are more than adequate.

Air gap, or the distance from mean water level to the bottom of the hull while the unit is jacked up in the operating condition, is a critical issue. The bottom of the hull must have a large enough air gap that the largest wave crest will not hit the hull and turn over the rig. Air gaps usually are 35 to 50 ft, with the larger air gaps in shallower water because wave heights build as water depth decreases. If a unit should work over a platform with a very high deck, air gaps of up to 100 ft are not uncommon; however, this obviously reduces the water depth rating. Jackup water depth ratings generally use a minimal leg penetration of 15 to 25 ft, which may not be the case in actual operation.

Independent- and mat-leg jackups also come in two types of drill floors, slot and cantilevered. As previously discussed, slot units were initially built in the 1950s through the late 1970s; however, with bigger platforms, the ability to cantilever the drill floor over the platform had an advantage over the slot units, which could only "swallow" minimal-size platforms. As the cantilever moves out to position itself over a well, it generally loses combined drillfloor load rating. The combined loading consists of the hook, setback, rotary, and drive-pipe tension if that tension is hung off the drill floor substructure. Generally, a minimum cantilever length (≈ 14 to 20 ft) is required for moving BOPs and other items next to the hull. Full rating is usually accomplished at center positions but decreases as the cantilever moves further out and the drillfloor moves either side of center (usually ±15 ft). The rating on the extreme cantilever and extreme off-center can decrease by as much as 80%, leaving the unit capable of only light workovers.

Unlike typical earlier 1-million-lbm cantilever load units, the new premium jackups have ratings of ≥ 2 million lbm. With the advent of ERWs, deeper gas wells, and high-pressure/high-temperature requirements, the higher load ratings are required, so many older jackups have been upgraded and enhanced, although not to the extent of some of the newer premium units built in the late 1990s and early 2000s. The Atwood Beacon (Fig. 14.20) is shown in the process of setting a small platform. This unit has a 2-million-lbm cantilever load rating, 7,500-psi-working-pressure mud system, 70-ft cantilever, 400-ft water depth rating, accommodations for a crew of 120, and 7,500-kip VDL, which is typical of the dozen or so units like the Atwood Beacon.

There are more jackup-type MODUs than any other type of MODU. Table 14.1 shows general information about the various types of major units. Marathon Le Tourneau (now Le Tourneau) has designed and built more of these units than any other designer and builder. As shown, the size and capabilities of these units vary widely, with the general trend being for them to get bigger and more expensive with higher drilling and marine capability.

Unlike platform rigs, submersibles, and ships, jackups and semis are upgradeable from a technical and commercial standpoint. Rowan Co. and Noble Drilling, both large offshore drilling contractors with large jackup fleets, have done extensive upgrades and enhancements to units built in the 1970s and 1980s. Upgrading usually consists of converting slot to cantilever units, leg strengthening and lengthening with more preload tanks, increasing environmental capability, and updating the drilling package with higher hook loads and installation of top drives.

Originally, MODUs were considered to have a life of 12 to 15 years, but through rigorous hull and equipment maintenance and technological updating, some 30-year-old units are considered "modern" and well fit for select purposes.

Why use a jackup? For water depths of 25 to 300 ft, there are many units to choose from. Some can be used in>

400-ft water depth. The jackup, with its stable work platform, relatively inexpensive mobilization costs, availability, versatility to work over a platform or to drill in open water, and generally competitive day rate, lends itself as the rig type of choice in certain water depths.


For drilling from the floating position, the semi MODU has become the unit of choice. Sometimes referred to as a "column-stabilized" vessel, the combination of hull mass and its displacement, wave transparency of the hull because of the columns, and its deep draft enable waves to pass through the unit with minimal energy exciting it to excessive roll, pitch, sway, surge, heave, and yaw. With the work deck above the wave crests and the factors listed above, this design is a very capable work platform in severe environments. Floating units can work in very shallow water depths, < 100 ft in some cases, to the deepest water depths. The present world-record water depth for a semi is 9,472 ft set by a DP semi in Brazil in 2003 with a surface BOP, a new technique discussed later. The water depth record for a spread-moored semi is 6,152 ft, set in 2002 offshore Malaysia. A semi in 2003 set the world record for a "taut line" mooring system at 8,950 ft, also discussed later. The same rig also set the record for subsea completions in 7,571 ft in the GOM as the deepest producer.

In shallow water, the concern is the possible clashing of the lower hulls with the BOP stack if the semi moves off location. In other words, the distance between the subsea BOP stack when the lower marine-riser package is disconnected and the lower hull in the event of a move off location usually controls the minimal water depth. Heave, tidal range, slipjoint space-out, and ability to hold location are also important factors.

As with jackups, air gap is critical and is a major design consideration when the unit is rated for environmental conditions. During the design of a semi, hull motion analysis in relation to waves crashing into the upper deck is critical. Under no circumstance should a MODU be designed or rated for environmental conditions in which waves will come in contact with the upper hull. In addition, heave, roll, pitch, sway, yaw, and surge need to be analyzed in terms of the upper limits of motion in which crews and equipment can operate. For example, significant amounts of heave, if slow (long periods), may be tolerable for most operations; however, short heaves that are very fast (very short periods) are more difficult. From a crew performance standpoint, smooth predictable motions generally do not hinder performance; however, jerky unpredictable motion will have a significant negative impact. Metocean conditions throughout the world result in most semis being operated in< 8- to 10-second wave or swell periods, so motions below these periods are usually not of concern. A swell period of interest is the "resonance" or natural period in which the hull motion actually exceeds the environmental value (> 1.0 ratio) for motion (i.e., the hull heave is more than the wave height). It is generally agreed for semi designs that the resonance period for heave should be> 17 to 18 seconds in the GOM to prevent resonance. The resonance period varies in other areas.

Table 14.2 shows the relationship of common semi designs available in today’ s market. As seen, the size, mass or displacement, VDL, and water depth ratings vary widely. Generally, the deeper the water depth rating is, the more severe the environmental capability is, and the bigger the VDL rating is, the larger the semi displacement and dimensional size are. In the 1970s, the average semi displaced 18,000 to 21,000 long tons, whereas some of today’ s deepwater units displace>

50,000 long tons. Larger displacement usually means more VDL and better motion characteristics.

It is common to refer to semis as belonging to a "generation." This designation is somewhat inexact, but Table 14.3 gives some guidance for semis. Recently, the newer ultradeep drillships have also adopted this type of designation. Many semis may start out as one generation, but an upgrade may graduate them into another one. This is particularly true of many second-generation units that are upgraded to fourth-generation units. One of the most unusual conversions and upgrades is Noble Drilling’ s EVA-4000 design, which originally was a shallow-water submersible. This triangular submersible was a complete redesign and turned into fourth- and fifth-generation semis. VDL and age are poor definition parameters for generation designation because some second-generation units have larger VDLs than some fourth-generation units and because age variations within a generation, especially fourth generation after upgrade, can vary widely. The most defining qualities between generations probably are water depth rating, the date of new build or upgrade, and the technical capability of the drilling and subsea equipment on board the unit. Fifth-generation units usually have very large VDLs, high marine-riser tension, hook load ratings of 1.5 million lbm, large deck space, high-pressure [7,500-psi working pressure (WP] mud pumps, and extensive mud-solids control systems. Floating units require subsea well-control equipment, a marine-riser system, marine-riser tension systems, drillstring motion compensation, large mooring systems, craneage to handle all the tubulars and marine riser, a guidance system to enter the well and to run the well-control systems, and a sophisticated management system to work all the components together. This equipment and these procedures are discussed later.

Why would someone want to use a semi? In general, they are the most dependable, motion-free, and capable of all the MODUs. Their cost is generally higher than that of a jackup, but in water depths exceeding that for which jackups are rated, they are the unit of choice.

Ultradeepwater Units

These units, which are extremely expensive, few in number, highly capable, huge in size, and technologically advanced, are the technological forerunners and pioneers in the offshore drilling business. Table 14.4 gives some characteristics of these units, most of them drillships of extraordinary size, but some are semis as listed in Table 14.3. All were built in the late 1990s and early 2000s. Most have some degree of dual-rig activity (i.e., they have two drilling units on one hull). The Transocean Enterprise Class drillships (Fig. 14.21), for example, have the capability to run two riser and two BOP systems with one system drilling and the other completing a well on a subsea template. With this drill-and-complete mode on a multiwell template, companies have claimed efficiency savings of 40% compared with a single-derrick unit. For exploration wells, it is possible to run casing with one derrick set and drill with the other, thus reducing total rig time to complete the operation. Of course, the latter operation is accomplished before running the BOP stack. It is possible to run marine riser and the BOP stack with one derrick set while running and cementing conductor casing with the other. Some have the capability to produce and store crude oil, thus eliminating the need to flare or burn the produced fluid during well testing.

The ultradeepwater drillships are the outgrowth of the second-generation DP units built in the middle to late 1970s. These units provided technological breakthroughs in stationkeeping, re-entry without guidelines, power management, thruster management, reliability, priority assignments, and maintenance that led to the newer units shown in Table 14.4 . The newer units are "D3" rated in that they have total triple redundancy from the engines, to SCR, to electrical switch, wiring, fuel, thruster, stationkeeping monitoring, etc. In other words, if any component of the system should fail, another one comes online immediately; if another system fails, the third system comes online. This approach is an effort to increase the reliability of the total stationkeeping system.

The attractiveness of these ultradeepwater units, all of which are fifth-generation units, is their unique ability to drill in up to 7,500 ft—and in some cases,

> 10,000 ft—of water depth. These units generally cost more than U.S. $400,000,000 to build, with some running more than U.S. $650,000,000. The commercial viability from the contract driller’ s viewpoint is still questionable; however, they have proved that the industry has the ability to drill in over 10,000 ft of water depth, a feat not imagined 15 years ago. The current world-record water depth set by the DP drillship Discoverer Deep Seas in 2003 and 2004 is 10,011 ft in the GOM. The current drill and complete for production record is 7,209 ft, also in the GOM and set in 2002 by the sister rig of the Discoverer Deep Seas, the Discoverer Spirit.

Why use one of these units? Water depth is the primary reason. Some contract drillers believe that the dual-activity capability makes them competitive with moored units of lesser capability and cost. However, these units are, in general, exploration units with a "niche" development capability for large-numbered multiwell subsea templates in very deep water. They are expensive but very attractive for the right situation. Generally, for exploration wells, the deeper the water depth is and the shorter the well is, the more commercially attractive they become over a standard spread-moored semi. Without them, we could not explore consistently in>

7,500 ft of water depth.

Other Considerations

Until now, we have focused on the basic hull designs and their capabilities. For any MODU to operate as designed, many associated and auxiliary factors and systems must be taken into account. Following are some major items that a driller needs to consider when selecting and operating a MODU.

Mobilization and the Drilling Site

Mobilizing a MODU usually falls into three categories: field, area, or long/international move. For field moves, which are short, no special preparation is done other than standard marine items. Field moves are usually defined as < 500 miles in the same environment, the same geographical area, and the availability of safe haven if required by weather conditions. In large bodies of water such as the U.S. Gulf Coast, the entire area is classified as a field move. However, if a MODU is moved from the U.S. Gulf Coast to Mexico, for example, it would be an area move. Any moves across the Atlantic or Pacific Oceans, of significant distance in Southeast Asia, from Europe to West Africa, etc., would be considered long/international moves.

Through their more favorable marine design, ships and semis have less metocean restrictions on moves than jackups and submersibles. Depending on the drilling contractor’ s arrangement with the insurance underwriters and third-party surveyor, a surveyor may or may not be required to be present during the move. The surveyor and underwriter are keenly interested in the seaworthiness of the MODU. The degree of preparation is controlled by the category of move. The long/international move, which is the most restrictive, requires the most preparation. Usually, there is a long list of conditions, including mooring gear requirements, water tightness of openings, crew training and licensing, radio and communication gear, tug hookup and emergency lines, weather forecasting, class and regulator compliance, routing of the tow, post-tow inspection, and general overall condition of the MODU.

A unit may be moved in two basic ways, by wet tow with a tug or a dry tow with a heavy lift ship or barge. Tugs for wet tows come in all sizes and capabilities. Small 600- to 900-hp tugs are often used to move submersibles in shallow water near shore. For field moves in the open waters of the GOM, 4,600- to 9,000-hp units are often used, usually two to three units at a time, depending on the size of the MODU, length of tow, and type of MODU. For ocean-going wet tows, tugs with> 20,000 hp are not uncommon. In the past 15 to 20 years, a new type of tug has become popular for semis that can pull/run anchors, act as a supply boat, and tow. Some of these vessels are very large with horsepower ratings> 20,000 hp.

The second mode of transport is the use of a heavy lift ship or barge (Fig. 14.22). This is the most expensive transport but usually travels at>

10 knots, which, depending on the MODU, is two to three times faster than a wet tow. If collecting the MODU contract day rate is an issue for the drilling contractor, the heavy lift ship is cheaper overall because it gets to location much faster. The insurance rate is also a third to a quarter of that for a wet tow. The use of heavy lift ships has become more popular for many reasons, mainly safety and speed. There are also unpropelled submersible barges that load the same way as the heavy lift ships.

A key issue with any MODU is the site condition. This usually centers on soil characteristics, especially for jackups and submersibles, which sit on bottom, and less so for semis and drillships, which are concerned only with the anchor-holding power of the soil. The issue of punch through of a leg by an independent leg jackup is of major concern; thus, soil borings are usually required for these locations. With information on soil conditions from soil borings, punch-through conditions can usually be determined. A punch-through condition usually is associated with a hard, thin sand layer with weak soil underneath it. When the jackup preloads by filling its preload tanks with seawater and thus increases its weight, the load may become so great that the soil fails and a punch through occurs with usually just one leg-spud can. Should this occur, the other two legs will probably be quickly overstressed. If the punch-through is deep enough, the legs usually bend, and the jackup must go to the shipyard for extensive leg and hull repairs.

For submersibles, the issue is usually uneven settling or scouring under the hull. If the hull should settle unevenly because of scouring resulting from ocean currents, the hull will most likely be overstressed, resulting in possible structural damage. Although this event is very uncommon, "hogging" or bending the keel of the submersible is a very serious situation. To prevent this, some submersibles have scouring skirts around the edge of the hull. Mat jackups also may experience scouring, especially if in shallow water with high currents; therefore, a 2-ft-deep knife edge is placed all around the mat’

s parameter to help prevent scouring. Cement-filled sandbags have been used to prevent scouring under submersible and jackup mats. Uneven settling is a more severe condition for a mat jackup in that with misalignment over 1 to 1½ degrees vertical tilt, the cylinder legs will become wedged in the jack house, and the rig cannot jack because of friction between the leg and jack house.

Pipelines and underwater structures (e.g., natural reefs and old shipwrecks), protected underwater creatures (e.g., tube worms), and even old wells must be mapped and acknowledged. For semis, running anchor lines across and resting the anchor chains on some of the latter objects is not allowed or considered good practice. In this case, anchor patterns are altered or special mooring-line configurations are considered. Options include the use of spring buoys that lift the mooring line off the object, special vertical load anchors that do not require the anchor-line scope of a dynamically installed drag anchor, and/or special composite mooring-line makeup. Sandbags full of ready-mix cement have often been laid on pipelines in shallow water to keep mooring lines from cutting or lying on them.

Drilling next to shipping lanes and/or fairways requires planning and extra precaution. Ships sometimes stray out of their designated lanes and have on occasion collided with MODUs. Floaters may have anchors and/or anchor lines in the fairway, so coordination with the proper authorities is mandatory so that vessel traffic will not hit the MODU’ s mooring lines. Usually, the mooring line must be at a depth under full tension that will not threaten vessel traffic. For the GOM and other areas, notice must be given to the proper authority that a "navigation hazard" has moved into an area so that vessel traffic will be aware of the MODU and not collide with it.

The above discussion indicates that using a MODU requires the operator to plan ahead, determine conditions, and make arrangements for unusual conditions.

Equipment Outfitting and Capabilities

We must never lose sight of the fact that a MODU ’ s primary goal is to drill and sometimes complete wells. Often, when concentrating on the marine aspects of the offshore drilling business, we forget this fact. Every well and site have their own requirements and demands, but following are some general comments, not always applicable to every situation, on MODU equipment and capabilities that should be considered when selecting a unit or planning a well. This list is far from complete but raises some of the most common considerations:

1. Variable Deck Load. VDL includes any item of weight that is not included in the lightship of the basic vessel. Lightship is the basic weight of the MODU, including all equipment considered permanent. This includes drawworks, mud pumps, rotary, derrick, top drives, power plant, and basically all items that cannot be readily lifted off the vessel. VDL includes the drilling contractor’ s drillstring, BOPs, spare parts, vertical tension to hold up a drilling marine riser, fuel, portable water, and anything loose on board. The remaining VDL is for the operator’ s consumables, including logging units, casing, bulk and liquid mud, cement, handling tools, subs, and anything that he may want to store on the MODU. Hook, rotary, and setback are also considered VDL and may consist of a large portion of what the MODU is required to safely carry. The depth of the well and casing program has a big impact on the amount of VDL required, as will water depth. Complicated mud programs requiring changing of mud systems will necessitate more volume and space. It is not uncommon for a development MODU to have three types of mud on board. For floating rigs, storing the entire volume of the marine riser adds significant weight and space requirements to the MODU as water depths increase. Some MODUs report large VDL capacity, but often they do not have the space to store the VDL. In general, jackups, except for the new premium units, have the least VDL capabilities. They also do not have a lower hull or large tankage like a semi’ s lower hull or a drillship’ s auxiliary tanks or a submersible’ s lower hull tankage. The range of VDL for jackups ( Table 14.1 ) runs from 1,600 to 2,600 short tons. For semis ( Table 14.2 ), the VDL ranges from 2,500 to 4,000 short tons for older units and 4,000 to> 7,000 short tons for the newer-generation units. 2. Stationkeeping Equipment and Marine Riser Tension. For spread-moored MODUs, analysis must be done in relationship to the environment required for it to withstand and hold station in drilling, standby, and survival modes. Metocean data must be obtained and used in an industry standard analysis program like that published by API or other recognized authority. For DP operations, the operating limits of the system must be compared against the metocean and the return periods of major events. DP stationkeeping, unlike spread-mooring systems, functions so that the unit either maintains location or is steadily forced off location. There is no in-between when reaching the maximum capabilities of the unit. For spread-moored units, as the MODU moves off location because of increasing environmental forces, the mooring system increases in restoring force; however, the offset from the well may be too great to manage the marine-riser system safely. The mooring and marine riser work hand-in-hand; therefore, a riser analysis in accordance with an industry standard such as API should be done. If the MODU appears to be more than adequate for the proposed location, drilling contractors can usually supply the analysis and guidance. For more challenging locations, a number of competent engineering firms can conduct studies and give guidance as to the acceptability of a specific MODU under consideration. 3. MODU Classification and Environmental Rating. Every MODU has design ratings approved by classification societies, country of registration, and regulations by various bodies. A unit may be able to work in the GOM but not be rated for the environment or regulatory requirements in the North Sea. Most MODUs can operate in temperate and mild environments, but such areas as the North Sea and west of the Shetlands are restrictive to many units. Some third-world countries do not have any regulatory requirements, and the regulations that do exist are loosely enforced. Pollution and environmental requirements can be major considerations. Some countries, such as Australia and Italy, have very strict rules concerning electrical, mechanical, training, staffing, and other matters. This subject is discussed in more detail later. 4. Well-Control and Related Equipment. The anticipated maximum surface pressure in the event of a well-control problem will determine the WP rating of the well-control equipment. Most MODUs have a 10,000-psi-WP system. A few have only 5,000-psi-WP systems, but if a 15,000-psi-WP system is required, MODU selection may be restricted. The cost of the MODU and well will increase because of a more restrictive market for high pressure and sometimes high temperature (high bottomhole temperatures). Wellheads, usually more and heavier casing and thus higher VDL requirements, more and heavier muds, and the like all drive up the required capability of the MODU. Well-control equipment is a subject in itself, and there are a number of good references in the industry. The following text discusses subsea equipment and its relationship with stationkeeping.

5. Accommodations Capacity. If a simple well is to be drilled and not completed, crew and servicemen capacity requirements are far less than if a complicated well is to be drilled and completed. Most modern MODUs have capacity for at least 70 crew, many have capacity for 80 to 90, and some of the newer units have capacity for up to 120. Included are the operator ’ s personnel, service personnel used at various stages, the contractor’ s crews, catering personnel, and any visitors. Room for regulatory personnel is sometimes a requirement, but as most operators will confirm, there never seems to be enough capacity. This results in a constant shuffling of personnel and crew on and off the MODU to stay within class and lifesaving allowable limits. 6. Drilling Equipment and Power Plant Requirements. Most drilling engineers and operations personnel will look at a MODU’ s drilling equipment and power plant first to see whether the unit is capable of drilling the well under consideration. Many upgraded units, even some new builds, may be short in one or more areas. If the unit has added, for example, a top drive, a third mud pump, enlarged accommodations, centrifuges, and solids-control equipment, more power and electrical equipment are required. During upgrades, this additional power is not always added. It generally is advantageous to be able to run all mud pumps, lift up a heavy load with the drawworks, back ream the hole at high torques, and have a maximum utility or "hotel" load simultaneously. Various operators have rules about what they require. Some require at least one mud pump in reserve at all times. Some want one main engine as a reserve for backup in the event of an unexpected loss of one engine or available for routine maintenance. Is a high-volume, high-pressure mud system (5,000- vs. 7,500-psi WP) worth the extra money required to hire an upscale MODU? All the aforementioned items should be part of the equipment evaluation. In addition, operating performance, management style of the contractor, safety performance, financial stability, honoring of contracts, and many more factors should be kept in mind. 7. Well Testing. If extensive well testing is anticipated, burning and/or storage of the crude must be considered as part of the MODU selection. If high production rates for a gas test are considered, cooling of the MODU is a major consideration. Piping and safety systems are of paramount importance to ensure that the operation is conducted in a safe and environmentally secure manner. 8. Crew Capability, Training, Safety, and Overall MODU Performance. Assuming that the "hard" or basic equipment qualifications are met, it is important to determine the capabilities, training, and safety work habits of the crews. Longevity of critical and key members of the crew, such as the offshore installation manager (OIM), tool pushers, drillers, crane operators, barge engineers, rig mechanics and electricians, is an indication of good morale, teamwork among the crew, continuity, and performance. The International Association of Drilling Contractors (IADC) has rules and guidelines to measure safety through lost-time incidents (LTIs), non-LTIs, first aid, and near misses. These statistics indicate the MODU and drilling contractor’ s commitment to and success in conducting a sound safety program. Overall MODU performance can be measured in downtime, for which every drilling contractor keeps records, and time-vs.-depth curves. Many receive appraisals from their customers on a well-by-well basis. If these forms are not proprietary per the drilling contract, they should be reviewed. 9. Special Situations and Considerations. If the well is to be drilled in an unusual area or there are atypical circumstances, MODU selection may be restricted. Very high-current areas that induce vortex shedding and thus violent vibrations of marine risers, jackup legs, mooring lines, guidelines, and BOP control lines may require special equipment. Severe cold, especially below-freezing temperatures for extended periods of time, require special winterization, which is not standard equipment. Icebergs and pack ice flows are another unusual situation that must be taken into account when selecting a unit. Extremely large tides,> 20 ft, may eliminate some jackup MODUs because of leg length. Unusual situations and circumstances do not occur often but may have a significant impact on MODU selection when they do occur.

The above list is not all inclusive but suggests important points in reviewing a MODU for a specific drilling program. Many other factors and items, such as the MODU’ s maintenance records, age and condition of equipment, type of MODU (some jobs can be done by more than one type of MODU), day rate and contract conditions, mobilization/demobilization costs and distances, and timing and availability of potential MODUs, need to be considered. How to select the right unit is discussed later.

Subsea Equipment, Stationkeeping, and Management

For successful floating MODU operation, proper marine riser and mooring equipment and their management are critical. We have briefly discussed the two types of stationkeeping systems, spread mooring and DP. The vast majority of floating MODUs are equipped with spread-mooring systems. Some have a limited amount of dynamic thruster assist to their spread-mooring system. Almost all of today ’ s semi and drillship MODUs have an eight-point mooring system consisting of anchor chain, wire rope, or a combination. Most of the deeper-water units have a combination of anchor chain on the anchor end and wire rope on the rig end. For a very few ultradeepwater operations, synthetic mooring line is used to increase the strength-to-weight ratio of the mooring line. However, the synthetic mooring line is not carried or deployed by the MODU, which is a distinct disadvantage from an operations standpoint.

The anchor chain used on most MODUs ranges between 2¾ in. and 3½ in., with the predominant sizes being 3 in. and 3¼ in. Anchor chain comes in various grades, the most common being oilrig quality (ORQ), followed by R3S (20% stronger than ORQ) and RQ4 (30% stronger than ORQ). Wire ropes range from 2¾-in. to 3¾-in. OD and may be as long as 15,000 ft, although the average is closer to 6,000 to 9,000 ft per line. The rated break strength of wire rope varies widely, depending on the construction and manufacturer. For example, API EIPS grade 3 in. is rated at 389-tonnes breaking strength, but Bridon Dyformed DB2K 3 in. is rated at 530 tonnes, or 36% more strength. For combination mooring systems, it is important to match the strength ratings of the wire rope and chain. Anchor chain generally performs better in shallow water depths (< 600 ft) because most of the strength is used for restoring force rather than holding up the chain’ s weight. Wire rope and combination wire-rope/chain systems are best for deep water (> 1,000 ft and> 2,000 ft for combination systems) because the strength-to-weight ratio is higher and more important in deeper water. Quality assurance is a critical issue for mooring lines and related equipment.

Spread-moored MODUs, depending on the metocean, can generally moor in up to ≈ 5,000 ft; however, in benign to mild metocean conditions, some MODUs can meet industry standards to moor in up to 8,000 ft. Increasingly used in ultradeepwater depths is the "taut mooring line" system, which uses synthetic mooring line and spring buoys and is prelaid, as shown in Fig. 14.23. The current world record for this type of mooring system was set by the Deepwater Nautilus (Fig. 14.13) in the GOM at 8,950 ft in 2004. This type of system is prelaid by anchor handling boats ahead of the arrival of the MODU. The taut-line systems are expensive and time-consuming to handle; however, they extend the mooring capability of some MODUs to deeper water depths and may be very economical compared with a DP unit, especially for very long wells and development projects. Anchors with very high holding power have been developed that range in dead weight from 7,500 to>

15,000 tons. The larger anchors perform best when the mooring line reaches the ocean bottom on or near tangent at full design tension; however, new vertical-load anchors have proved to be successful for special cases. These anchors are difficult to set, take special equipment, and cannot be carried by the MODU; however, they work well with some types of taut-line systems.

Deck machinery to store, deploy, and retrieve the anchors and mooring lines for a deepwater mooring system can be massive, expensive, and heavy. Fig. 14.24 shows a typical layout on one corner of a semi MODU for a deepwater combination chain/wire-rope mooring system. Chain is stored in chain lockers in the columns below the deck machinery. The chain and wire rope are connected and disconnected for storage at a platform below the deck machinery level. This operation usually takes from 20 to 40 minutes for the latter operation.

Fig. 14.25 shows all the components and their location for subsea equipment, usually defined as anything under the rotary of a floating MODU down to the ocean floor. The subsea BOP stack consists of the lower package (mostly BOPs) and the upper package (lower marine-riser package). The BOP stack is in two parts such that, in an emergency, the marine riser can be disconnected from the lower BOP at the lower marine-riser package. The BOP stack, used primarily for well control, usually consists of a minimum of four ram-type and two annular-type BOPs with three to four sets of double-outlet failsafe close valves. Valves are in sets of two with an inner and outer valve, all failsafe, with the choke side having a minimum of two sets and the kill side having one or two sets. The choke-and-kill pipeline runs are routed up past the flex joint and to the surface by use of lines attached to the marine riser. During well-control operations, the well is circulated down the drillpipe, up the choke line, and through a choke manifold in a controlled manner to pressure balance or "kill" the well.

The marine riser’

s primary purpose is to guide objects (bits, logging tools, casing, wellhead hangers, and seal assemblies) in and out of the wellbore while also serving as a return conduit for drilling fluids and cuttings. The marine riser also carries auxiliary lines on the outside of the main conduit for the kill (pump down to the well), choke (flow a kick back to the rig), mud-circulating line (help lift drill cuttings up the large-internal-diameter riser tube), and hydraulic conduit (hydraulic power fluid for activating the BOP stack). The flex joint at the top of the BOP stack is a pivot point to reduce stresses in the riser and acts as a hinge point. The slip or telescopic joint allows vertical motion between the floating MODU and BOP stack and marine riser, which are attached to the ocean bottom.

The outer barrel of the slip joint, attached to the BOP stack, is tensioned with strung wire rope by 6 to 16 pneumatic tensioners ranging in capacity from 80,000 to 250,000 lbf each. Riser tensioners are usually pneumatic rod/cylinder assemblies with wire rope attached to the outer barrel (the part attached to the seabed) of the slip joint. Total installed riser tension pull varies with water depth rating for the MODU, but a very-shallow-water unit will have ≈ 640,000-lbf tension and the newer MODUs will have ≈ 1.6 to 2.0 million lbf. A new type of riser-tension system consisting of large, very long hydraulic cylinders (referred to as inline tensioners) attached to the slip joint and substructure has recently been installed on some of the newer floating MODUs with tension capabilities of up to 4.8 million lbf. Total stroke for all riser tensioners usually is 50 ft, but some of the deeper-water units must have more stroke length in case the MODU moves off the well without disconnecting the lower marine-riser package from the BOP stack.

Atop the inner barrel of the slip joint, which is attached to the rig’ s substructure, is the diverter assembly. The diverter assembly is used to divert fluids, usually gas, that the marine riser may have in it. The diverter assembly has a low-pressure (500-psi WP) packer that may close around the drillstring and divert fluid horizontally by use of diverter lines. Diverter lines (12- to 16-in. outer diameter) are used to route well fluid away from the rig and overboard in the unlikely event that unwanted fluids should come to the surface. More detailed information is given about subsea equipment in Marine Riser Systems and Subsea Blowout Preventers.[8]

To maintain constant weight on bit for a floating MODU, drillstring motion compensation (DSC) is required. Thus, the industry has developed inline (travels with the traveling block) and crown-block (located on top of the derrick and part of the crown assembly) motion-compensation equipment. Most drillstring motion compensators are inline and passive (the drillstring motion compensators react to MODU motion rather than sensing it, as does an active system). Drillstring motion compensator’ s stroke is usually 15 to 25 ft, with an average of 18 ft; however, most floating units will not operate the drillstring motion compensators with> 10 to 12 ft of heave. Active systems usually involve the drawworks motors that dissipate the energy though the rig’ s power-plant generators. This is one reason why DP drillships with a large power-plant system use active heave-compensation systems.

The BOP control system is critical and probably the most difficult in which to maintain the high degree of reliability required for safe offshore operations. Most floating MODUs use all hydraulic systems by use of pilot valves in a "pod" on the subsea BOP stack (Fig. 14.25) shifted by pilot lines from the surface. The power fluid is usually sent down a hydraulic conduit on the marine riser. Some deeper-water units (>

5,000 ft) use a multiplex electrically coded system as the signal medium for shifting the pilot valves in the pods. Industry standards require subsea rams to close in 45 seconds and the annulars in 60 seconds; thus, signal time is critical and very time dependent. Subsea BOP stacks differ from land BOP stacks in that they stay assembled, have remote stabbing capabilities, have hydraulic wellhead and riser connectors, have mechanical riser connectors, have BOPs and valves that are hydraulically actuated, have guidance systems, and are controlled remotely per the above description.

The key to successful floating MODU operations is managing the marine-riser and mooring system together and in harmony. As stated, the mooring system objective is to restore the floating MODU within specified limits over the wellbore through varying degrees of environmental conditions and rig operations. Hole position or vessel offset from the wellbore is usually monitored with acoustic hole position indicators that work in percentage of water depth from the wellbore. Riser angle at the flex joint located on the LMRP is also measured acoustically. Table 14.5 is an example set of criteria for allowable differential riser angle (difference between the BOP and riser angle at the flex joint, not with vertical) and hole position, depending on the rig operation being conducted. The primary purposes of these guidelines are to achieve riser angles so that tools can be run/pulled through the BOP stack and flex joint without hanging up or creating damage, to prevent damage to the subsea equipment because of drillstring key seating, and to ensure adequate structural integrity of the marine-riser system.

Recently, a new form of floating drilling has been developed in which the BOPs are located in the cellar deck rather than on the ocean bottom. With standard floating drilling, it is anticipated that if the MODU has a mooring failure, loses its station over the wellbore because of environmental conditions, or experiences a riser failure or any other mishap, the subsea BOPs can secure the well. With the surface BOP approach (Fig. 14.26), the loss of hole position by the MODU or a failed riser means that the well will probably be lost. The concept is that the riser is high pressure (usually 13⅜- or 16-in. casing), the metocean is very benign, and the well pressure is normal gradient, so seawater head will kill the well in the event of a riser failure. It has been very economically successful in the Far East and has cut well costs by as much as 70%; however, the risk of losing the well and/or having a blowout has deterred many operators from using the approach. One mitigating approach is to put a complete shutoff device at the ocean floor (usually at least one shear ram with hydraulic connectors top and bottom); however, this approach increases the expense and time to the point of losing all savings. However, in ultra deepwater where the well is circulated up small-ID kill and choke lines, causing significant backpressure on the formation, the surface BOP with the large high-pressure casing and BOPs at the surface eliminates the problem. In other words, there are pros and cons for every approach.[9]

Another approach similar to surface BOP is the "slim riser" approach (Fig. 14.27). The standard subsea system is built around an 18¾-in.-ID BOP stack and wellhead system that ordinarily uses a 21-in.-OD riser. The standard system has the capability to run up to nine casing strings by means of hangers and liners under certain conditions. In deep water where the margins between formation fracture gradient and hydrostatic head of the drilling mud to maintain well control is very close, many casing strings are often required. The GOM has this requirement, often resulting in very expensive wells costing U.S. $50 million and sometimes more than $100 million. If a more standard deepwater well is to be drilled with only two to three casing strings through the BOP stack, a 16-in.-OD riser may be used. This results in far lower mud volume requirements because of a smaller drilled hole and smaller riser ID, which in turn requires less marine-riser tension, less deck space, and thus less VDL. Most importantly, these reduced quantities allow a third- or fourth-generation MODU to be used at reduced day rate rather than a fifth-generation unit.[10] A capable third or fourth generation semi rated for 5,000 ft water depth can be increased to 7,500 ft or over.

Although not discussed in detail in this chapter, well control in deep water is much more difficult than off a jackup MODU or a land rig. With the margin of safety between the fracture gradient and mud hydrostatic pressure smaller, the shut-in point (subsea BOP) being much closer to the influx formation, the detection point still at the rotary, and long runs of kill and choke lines on the marine risers with small IDs (usually minimum of 3 in., with most being 3½ to 5 in.), detection and proper circulation is delicate and takes training, concentration, and patience. To date, the industry has an excellent deepwater well-control record.

Well Intervention and Remotely Operated Vehicles

In the 1980s, divers jumped in and out of saturated and pressurized systems to do almost all well and subsea equipment intervention, inspection, and repair. If the divers could not complete the repair task and/or inspection, the BOP stack or other items had to be pulled out of the water for repair. Even with the most sophisticated equipment, divers had limited capabilities because of water depth, visibility, currents, temperatures, bottom downtime, and sometimes questionable safety standards. Subsea television systems were and still are used to inspect and monitor hulls and subsea equipment by use of running down guidelines, but they can only view, not do repairs or other physical tasks.

Starting in the 1990s, coinciding with the increase in subsea completions, well intervention with highly capable remotely operated vehicles (ROVs) has developed into a common third-party addition to a floating MODU. Modern ROVs have the ability to "fly" by means of an umbilical that is attached to the transport cage (garage). Once the ROV leaves its cage, it may traverse for approximately 100 ft. The operator, or pilot, controls the flight pattern and position of the ROV so that it will not become entangled in its own umbilical or other items. Most ROVs have visual and recording capabilities in addition to manipulator arms with various degrees of strength, feedback, and lifting capability. ROV technology has far exceeded water depth ratings of MODUs; thus, capabilities and reliability of these units have improved considerably. Changing of wellhead sealing ring gaskets, control of some functions on the BOP stack in an emergency, retrieval/installation of items on the wellhead or production hardware, and inspection are common tasks, in addition to inspections with the subsea television system. With the increase in the use of subsea completions to develop whole fields, ROVs have become an integral part of deepwater development. With subsea development, MODUs do the drilling and most of the completion, including setting trees, flying leads, jumper hoses and pipelines, umbilicals, production risers, production skids, and templates, all requiring ROV intervention. When wells need to be worked over, ROVs are required and are usually launched off MODUs or intervention vessels working in conjunction with a MODU.

As ROVs have become more important in floating MODU operations, the size and space requirements have increased dramatically. For intervention and completions, it is not uncommon to have two ROV systems, requiring the storage and operating porch to be used as a work platform, structural reinforcement for the deployment winch, fendering to prevent the ROV from hitting the MODU columns/lower hull, electrical power to support the unit (can be > 200 to 300 KVA), VDL, and deck space. This can amount to a considerable support system that the MODU must accommodate, so planning ahead is important. Not every MODU can accommodate the larger ROV systems from a weight (some times over 40 tons), space (2,500 square ft or more), or power standpoint.

Rig Crews and Management

The importance of well-trained, motivated, skilled, safety-oriented personnel with a teamwork attitude to crew and operate offshore drilling units cannot be overstressed. No matter how well-engineered, well-equipped, and well-maintained a MODU is, it will not perform any better than the crew who manage, operate, and maintain it. The fact that the crew and management system are often the real determining factor concerning MODU performance and safety is often overlooked during the flurry of cost analysis, equipment evaluation, operating expenses assessment, and number crunching during bid analysis and MODU selection. It is often said that the low bid does not always give the best performance. A complete "hard" (equipment) and "soft" (crew, management, and safety) analysis must be done to make the best decision.

Over the last 10 to 20 years, almost every offshore drilling contactor and operator has developed very comprehensive management systems to guide and operate their companies. Management systems will normally include a mission and goal statement, a top-tier-quality control manual, and various second-tier standards and procedures manuals addressing such business functions as document control, department descriptions and responsibilities, job descriptions, bridging documents, safety and security, internal audit, contract review, purchasing, inventory control, and human resources. These policies and procedures should be reinforced from the chief executive officer to the roustabout on the rig to have a successful and well-performing organization and rig operation.

The staffing and organization of a MODU vary with each drilling contractor, operator, and country and are controlled eventually by classification and registration requirements. The most senior person on the MODU is usually the OIM who is by law the "master" or "captain" of the vessel. The OIM is responsible for all departments, including drilling, maintenance, marine, auxiliary services, and safety. The OIM works for the drilling contractor and interfaces and coordinates with the operator ’ s (leaseholder’

s) representative. Table 14.6 shows a typical MODU personnel complement for a jackup. The drilling contractor may employ the catering complement wholly or partially.

Employment contractors used by the drilling contractor are not uncommon in overseas operations. These contractors usually supply positions only from floor man down, but there are exceptions. The shore-based operation usually includes an operations manager, drilling superintendent, administrative manager, materialsman, and a secretary. Often car drivers, local agents, warehouse men, and administrative staff are included for overseas operations. If the financial and accounting functions are done on site, additional personnel may be required. With the advent of satellite communication on the MODU and local office, communication problems and time delays have been significantly reduced, resulting in a much smoother and more trouble-free operation. Procurement, inventory, and maintenance can all be monitored, directed, and recorded with ease and in a timely manner. In the early offshore days, MODUs operated like little independent companies, including their own personnel hiring/firing, procurement, accounting, materials and inventory, housing, and so on; however, with modern transportation and communications, local operations have been reduced in favor of centralized procurement, employment, accounting, and financial functions. Tax issues can be very tricky when moving from country to country; thus, outside major accounting firms are needed to interpret local laws so as to comply but not waste potentially huge sums of money.

The operator will have additional personnel on the MODU, such as radio operators, two or more drilling superintendents or foremen, drilling engineers, a geologist, and possibly an administrator. The operator from time to time will also have third-party service companies on board to perform and/or run mud logging, cementing, casing running, electric logging, measurement-while-drilling (MWD) and logging while drilling (LWD) drilling tools, completion and drilling tools, fishing, special downhole tools, wellheads, etc. Where rigs had accommodations of 60 to 80 personnel, including all support activities, it is now not uncommon to have a requirement for well over 100 personnel.


With operations often classified as high risk from a financial and physical standpoint and costs often in excess of a quarter of a million dollars per day, capable personnel and a defined management structure are essential. Running a drilling operation in the oil and gas business requires unique knowledge and the ability to adjust to new problems and challenges every day. It is definitely not like manufacturing widgets day in and day out.

Personal safety and health has increasingly become more of a factor and focus in offshore operations over the years. Safety statistics show that LTIs, recordable incidents, near-miss incidents, and medical treatments statistics have improved significantly over the last 10 to 15 years. Whereas the LTI rate (incidents per 200,000 hours) was commonly > 10, it is now common to be< 1 and often< 0.5. Safety offshore is no longer given mere lip service. IADC publishes statistics monthly by participating members, and the MSS gives out coveted awards in the Gulf Coast each year. From both a humanitarian and a financial standpoint, all feel that making safety a priority is the right thing to do.

All operators and drilling contractors have extensive safety programs, with the DuPont STOP program or some modification of it being the most common element. The STOP program emphasizes "observance" by everyone on the unit of the actions of each crewperson and the conditions of the surroundings. STOP cards can be written by anyone on board about anyone else, from the roustabout to the OIM, and then discussed during safety meetings. A Job Safety Analysis (JSA) is another significant program in which detailed procedures are written up for every major job and task, discussed before the job is performed, and then implemented during the job performance. The requirement to have the proper Personal Protective Equipment (PPE), such as hard hats, gloves, safety glasses with side shields, proper shirts and pants, and protective gloves, helps to provide a safe atmosphere. Drills for man overboard, firefighting, helicopter landing and takeoff, lifeboat use, first aid, entry into non-ventilated tanks, etc., contribute to improving safety in the workplace. Off and on the rig, training schools for crane operation, well control, firefighting, helicopter crash survival, team building, leadership, and other skills result in an enlightened operation and better safety and performance.

Before a crewman can be hired to go offshore, an extensive physical, including drug screening, is usually given. For newcomers, there are roustabout and roughneck schools, such as those given on the Mr. Charlie, now a museum and training platform in Morgan City, Louisiana. Intoxicating beverages, firearms, weapons, and illegal drugs are strictly prohibited offshore and, if discovered, usually mean instant dismissal and transport to shore for the offender. Almost every rig has a paramedic as part of the crew, with access to doctors and medical help instantly through satellite and/or other communication medium. Tens of millions of dollars and an extensive amount of time and effort continue to be spent by all trying to run a safe operation offshore, and statistics show that the industry has shown considerable improvement.

Environmental and antipollution policies and efforts have increased steadily over the last 30 to 35 years. The U.S. federal and state governments have extremely strict laws and procedures for before, during, and after leases are put up for sale, drilled, produced, and abandoned. The fear of pollution, or the potential for a spill, is so great that some areas, such as the east and west coasts of the U.S.A., have seen no drilling for years. Most of Florida is off limits, even though limited drilling has shown potential for gas. Through the International Maritime Organization (IMO), every rig has an international oil pollution plan that details the procedure to follow in the event of a spill, even a very small one. In the United States, even a very small fuel oil spill must be reported to the U.S. Coast Guard immediately. Fines of U.S. $10,000 or more can be imposed for each incident. Discharge of any toxic or potentially polluting fluid or solids overboard is strictly prohibited. Solid food waste must be ground into mulch< 1 in. 3 before discharge. Sewage waste must be treated before discharge overboard. Drill cuttings in some areas cannot be discharged overboard and must be transported to shore for disposal and/or injected into an approved reservoir offshore, usually down a casing annulus. Some areas offshore in the GOM do not allow mooring of vessels or discharge of cuttings because of sensitive coral reefs (possibly thousands of feet underwater), tubeworms, and other protected entities. The most feared environmental event from a MODU is a blowout of crude oil. Well-control equipment capabilities, procedures, and training have improved steadily over the years to a level where a blowout of any significance is extremely rare. The industry spends billions of dollars on antipollution and environmental safeguards every year in an effort to comply with laws and the public’

s desire for pollution-free operations and to be just a good citizen.

A new subject in the area of personnel and equipment security has appeared in the late 1990s. The Middle East, West Africa, and radical religious sects and areas around the world have required operators and drilling contractors to take security steps not envisioned just 10 years ago. Because overseas operations usually involve air flights for personnel sometimes into hostile countries, use of security consultants and constant contact with local governments and intelligence agencies are now common. In highly sensitive areas, crews do not ride in buses to lessen the risk and to disperse the target; crew boats are searched even underwater for explosives; security personnel are stationed on board with minute-by-minute communications with army and air force support; and hotels are carefully picked for ease of escape. Contingency plans are drawn up for every conceivable event; local personnel have 24-hour evacuation plans and stay packed for quick exit; a low profile is emphasized, with advice given to stay out of native crowds; hired drivers are used to drive evasively and to lessen the risk of an expatriate getting in an accident; and in one case a 3-mile "no entrance zone" by sea or air was placed around a MODU. Security not even conceived of 10 years ago is now front and center and is a large part of offshore operations in many parts of the world.

HSE&S has become as important in offshore operations as drilling the well. Drilling contractors are taken off operator bid lists if they do not have and do not demonstrate a sound, statistically proven system for human, equipment, well, pollution, security, and operational well-being.

Classification, Registration, and Regulations

Almost every vessel, barge, or floating object, including MODUs, must have classification and registration certificates of compliance to the rules and regulations as dictated and published by the classification society and country of registration. Most insurance underwriters require classification for the vessel to qualify for marine insurance. If the vessel is not fully classified, underwriting insurance companies will not insure the property, thus leaving the owner and his financial institution "self-insured." The vessel owner may consider the risk of a financial loss resulting from self-insurance, but his bank will not. Most operators will also require a drilling contractor to have classification on the MODU to show the unit ’ s condition and seaworthiness. In other words, MODUs must be fully "in" classification to obtain full insurance coverage, to obtain bank loans, and to comply with the operator’ s contract requirements.

Classification societies are usually privately owned for-profit companies that work closely with, though fully independently of, government bodies. There are twelve societies, all belonging to the International Association of Classification Societies (IACS). The primary societies are ABS (American), Det Norske Veritas (DNV, Norwegian), and Lloyd’ s Register of Shipping (Lloyd’ s Registry, English). Other members are located in France, China, Italy, Germany, Korea, Japan, Russia, Croatia, and India. It is very rare to see a MODU that is not classified by one of the three primary societies, with ABS having most of the units. Classification as an indication of seaworthiness and vessel condition was started in the late 1600s in England. ABS origin has been traced back to 1862. The first rules and regulations for MODUs appeared in 1968 and were written by ABS.

When a MODU applies for classification, usually during initial construction, it is a costly and rigorous exercise requiring months of effort by the owner, the design team or engineering company, and the classification society. The process consists of a "design review" and an on-site inspection to verify that the design is built as engineered and according to the society’ s published rules. Once classified, the unit will have periodic inspections that the owner and operator must plan for and schedule so that the MODU does not fall out of classification or interfere with the operator’ s drilling and/or well-completion program. There are "annuals" (once-per-year "walk around" unless a problem is found), yearly surveys, 2½-year surveys often called underwater inspection in lieu of drydocking (UWILD), and a "special survey" (every 5 years and usually requiring a drydock). These surveys include inspections of the steel structure and hull condition, piping, firefighting, safety at sea, corrosion protection, power and electric equipment and wiring, communication on and from the MODU, detection systems for fire and gas, crew level, mooring equipment, stability, and operating manual and emergency procedures.

In the 1940s and 1950s, it became apparent that by working together and developing common rules and regulations, the shipping industry could become safer, operate with higher principles, become more efficient, and exercise better pollution control. Thus, the Intl. Maritime Organization (IMO), an industry group that is not part of classification or registry, was assembled. Under the IMO, several regulations, guidelines, and rules have been developed and adopted by a number of countries that have become part of the requirements for vessel and MODU registration. Included under the IMO umbrella is the Safety of Life at Sea (SOLAS), which deals primarily with safety issues and communications; MODU code, which deals primarily with construction and equipment; Maritime Pollution (MARPOL), which deals with pollution control and prevention; and International Safety Management, which focuses on safety for self-propelled vessels and MODUs. Member nations of the IMO adopt the codes and enforce them through classification societies’ efforts and fees charged the drilling contractor. Registration requirements often include the IMO codes.

Registration concerns the country of home port for the unit. Each country of registry has rules and regulations centered mainly on safety, communication, lifting and cargo gear, pollution, and pollution containment. Each registry has different rules and regulations, and the registry often has a working agreement with the classification society for the unit to inspect and certify on its behalf. The most popular registries are Panama, Liberia, and the Marshall Islands. The United States, England, Norway, and other industrial countries are not common registries because of their more complicated rules, regulations, and staffing requirements. Most MODU registries also fly the flag of the registry country, which controls the crewing and staffing levels and designation of crew skills. Although not common, there are some "dual registries" in which hardware and safety issues are handled by one registry and crew and staffing by another.

When a MODU has a classification and registration, it must comply with the rules and regulations of the country in which it operates. For example, a MODU may have an ABS Classification, Marshall Islands Registration for all the equipment, and registry for crewing in Germany, and it enters the United States to drill a well in the GOM. It now must comply with the U.S.A. regulations as enforced and surveyed by the U.S. Coast Guard. In addition, the operator must obtain permits to drill from the Mineral Management Service (MMS), which also inspects the MODU for MMS rules and regulations compliance. The well to be drilled and MODU must meet the MMS requirements concerning equipment, procedures, and crew training. Then, the Environmental Protection Agency (EPA), Occupational Safety and Health Agency (OSHA), and a few other agencies may enter the picture. The operator and contractor usually work together to comply with and follow the necessary rules and regulations.

Some countries, such as the United Kingdom (England), Norway, and Australia, require a "safety case" for the MODU to operate within their waters. Safety cases usually are expanded documentation, equipment and systems, and training centered on classification and registration rules but dovetailed into those particular countries’ laws. Developing a safety case requires considerable time and money and should be anticipated and planned for in detail far ahead of its implementation on the MODU. It is not unusual to take 6 to 12 months or more and over half a million dollars to fully develop a documented safety case for a single MODU. The safety case is required to obtain the necessary country’

s approval for the MODU to drill in its waters. Fortunately, consulting companies that specialize in the development of safety cases are available.

Industry organizations, such as the American Petroleum Inst. and International Standards Organization (ISO), also have a major influence on the upstream oil and gas industry. These organizations write specifications and recommended practices (RPs) for the industry to follow. These documents usually deal with equipment, procedures, and operating systems. The documents are usually written by the industry for industry use and are widely quoted by the societies, registries, operators, and drilling contractors.

In summary, 30 years ago in the infancy of the offshore oil and gas business, none of the above was required; however, after a number of incidents and tragedies, insurance underwriters, operators, drilling contractors, and governmental bodies have developed a fairly tight system to ensure better safety and environmentally friendly systems for the benefit and health of all.

Relationship Between the Drilling Contractor and Operator

There are three separate and distinctive entities on an offshore MODU: the drilling contractor who owns and operates the MODU, the operator who contracts the drilling contractor ’ s MODU to perform a service, and third-party contractors who work for the drilling contractor and/or the operator. In the 1950s, the relationship between these three parties was more clouded; some operators owned and operated the MODU. However, over the last 50 years, the relationship between the three entities has become standard and well defined.

There are exceptions, but the operator generally contracts the drilling contractor’ s MODU for a specific well or wells or a "term" contract of months or even years. The length of the contract usually is determined by the number of wells the operator wants to drill. He must decide whether a term contract or a contract for a specific number of wells is best for his program. The use of a long-term contract is usually driven by market conditions, with a tight rig market usually resulting in term contracts. This is especially true if a new rig build is involved; the drilling contractor’ s financial institutions may require a reasonable payback on the loan before the contractor can sign a contract and build the unit.

MODU capability, availability, mobilization, market conditions, safety, and operating performance enter the minds of the drilling contractor and operator when a potential MODU contract is at hand, but economics is generally the primary driving force. The operator will seek bids from a number of drilling contractors capable of performing the work. The operator will usually specify the type of equipment and drilling capability desired, such as the size of mud pumps, mud pit volume, hoisting load, drillpipe size and length, water depth capability, VDL, pressure rating of equipment, and size of well-control equipment. The operator will also ask for specifics about the drilling contractor’ s HSE&S program and request statistics showing past performance and copies of specific policies and procedures that the drilling contractor has in place. The operator will also have a preferred drilling contract. When it is a buyers’ market for rigs, the operator will have a strong position to use his formulated contract with few negotiated changes; however, in a sellers’ market, the drilling contractor will try to use his formulated contract, which of course favors the contractor’ s position. The contract, including the IADC-suggested offshore contract model, usually contains equipment and capabilities exhibit, liability clauses, payment terms, crew complement, description of work to be performed, a "menu" of who will pay for what services and materials, termination provisions, day rates and other charge items, terms for settlement of contract disputes, and numerous exhibits on customs, confidentiality, items required by law (e.g., equal opportunity), policies of both companies, etc. Sometimes a "bridging document" is required between the operator’ s and drilling contractor’ s policy and procedures manuals to eliminate confusion if the two do not agree on every item. Bridging documents are very important from a practical and legal standpoint.

A characteristic of the upstream oil and gas industry is the strong and unique cultures developed by operators and especially contract drilling companies. Although less so these days than in years gone by, egos and individualism often enter into the relationship between operators and drilling contractors, especially at the higher management levels. Some operators are very conservative and are willing to pay more for less trouble and rig downtime, greater safety, and higher-end rig capabilities. Of course, conservative drilling contractors usually work best with conservative operators. On the other hand, some operators are more freewheeling, "cut closer to the bone" so to speak, and work, for example, on a front-end cost basis, and they work best with drilling contractors who work the same way.

Generally, the most productive operations are done with good, workable, and cooperative arrangements laced with goodwill between the operator and drilling contractor. Driving the hardest bargain possible to the point of picking at every contract clause, every possible charge-back item, strongest possible indemnities, mobilization items, etc., usually results in hard feelings and a less productive operation. In other words, the relationship is very adversarial and convoluted, resulting in a difficult working relationship. Another common problem occurs when an operator decides to coordinate the drilling contractor’ s equipment and personnel down through the driller’ s position rather than communicate through the OIM. Initiative, cooperation, and a sense of responsibility and ownership by the drilling contractor personnel suffer, to the detriment of the whole operation.

If the operator has a defined drilling program for a long period (e.g., a 2- or 3-year period), the operator will generally obtain a "fit-for-purpose" MODU at a competitive price that molds itself into the operator’

s culture and routine during the term of the contract. This usually results in higher efficiency, a safer operation, less trouble time, less downtime for the operator and the drilling contractor, a more team-oriented effort between the parties, and overall a more cost-effective, trouble-free operation—a truly "win/win" situation. Unfortunately, not all operators can put together a drilling program of this duration, eliminating the potential for this type of relationship to develop.

Picking the Right Unit for the Job

With all the above said, one may ask, "How do I pick the right drilling rig for the job?" The answer is that often there is more than one rig type that technically can do the job. A review of previous sections of this chapter will show many items that must be considered. Following is a summary centered on the technical side of the evaluation. As stated, commercial, HSE&S, and other items need to be factored into the overall decision:

  • First and foremost, and as simple as it may sound, the operator must take the time and effort to be knowledgeable about MODUs, drilling contractors, the equipment involved, and the relationship between all the parties (operator, drilling contractor, and third parties). Surprisingly, this does not always occur.
  • The operator also should be aware of and obtain all the permits, and be aware of and set up logistics for boats, helicopters, ground transportation, housing, automobiles, agents, warehouses, office space, communications, contracts with third parties (e.g., bulk mud, casing, cementing services, and logging), security, drill and potable water, fuel, local supplies, and all related items.
  • The operator must also be aware of any unusual requirements to drill the well. Possibilities include shipping lanes and fairways, pipelines, unusual soil conditions, strong currents and/or large ranges of tides, strict drill-cutting discharge requirements, local government requirements for use of native labor and/or professionals, and restrictions on the use of harbors and air space (military explosive dumping area or non-flyover zone). Special requirements may have a major impact on the well plan.
  • With the last three points addressed, the operator must take time to engineer the exact type of performance he requires of the drilling equipment before deciding on the type of drilling rig. Sometimes the drilling rig type is obvious, such as an ultradeepwater rig; however, most of the time it is not. A checklist should include hoisting load and speed, mud volume, bulk volume (barite, bentonite, and cement), sack storage, VDL, drill-water capacity, feedstock capacities for synthetic or oil-based mud and completion fluid, metocean conditions in relationship to MODU capabilities, deck space, well-testing requirements if applicable (space, deluge for seawater and piping), and many of the items listed in the sections on equipment, outfitting, and capabilities.[11] Unfortunately, operators sometime specify a MODU and drilling equipment with not enough capabilities to drill the well with the hope that they will obtain an inexpensive unit. More often, operators specify a unit with complete overkill, eliminating very capable units that could do the job quite nicely at an attractive price. In other words, specify a unit that can do the job comfortably but do not overkill or try to squeak by.
  • Is the well over a structure, such as a caisson or platform, or at an open location? If it is over a structure, then only a jackup, TAD, platform rig, and/or submersible, depending on water depth, should be considered.
  • If the well is in open water then a jackup, TAD, and/or submersible, depending on water depth, should be considered. A standard moored drillship may also be evaluated if commercial issues are a key consideration.
  • If the well(s) to be drilled are over a platform, some of the following questions need to be considered:
  • On the subject platform, can a cantilever jackup reach the well conductor after jacking up, and does it have enough combined cantilever load rating to drill the well(s)?
  • If a platform rig is being considered, is there enough fixed platform space and load-bearing capability? Older platforms sometimes weaken with age and additional production equipment is placed on them, thus reducing the space needed for a platform rig. What is the spacing for the "cap beams," or the beams the platform rig would skid and rest on? The beams may range from 30 to 62 ft; TLP, spars and large platforms may even be wider. Standard cap beam spacing usually runs from 35 to 45 ft. A jackup or a TAD should be considered if cap beam spacing, load, or space is a major issue.
  • If a platform rig seems to be the best fit, required capabilities are very important when deciding between a standard and a modular unit. As a rule, modular, self-erecting units are less capable overall but offer many advantages over their larger, more expensive cousins, as discussed earlier.
  • If there are weak soil conditions that increase the likelihood of a punch through or old spud-can holes that do not fit the available jackups, use of a jackup may be questionable, especially if a capable TAD, preferably a semi, is available.
  • If platform space and/or load bearing are critical and the wells to be drilled are ERWs or very deep, a high-specification semi TAD will be very attractive because a TAD takes up less space, the DES is much lighter than high-specification platform rigs, the weather effect for loading and unloading consumables is generally not a factor with TADs, and the TAD can store (space and load) a considerable amount of casing, mud, cement, and operator expendables.
  • If a TAD appears to be the best solution, weather, space, and VDL should be factored in when considering a monohull vs. a semi TAD.
  • For spars and TLPs, modular platform rigs vs. TADs must be explored. Weight is very critical and extremely expensive to accommodate. The TAD, weighing one-fourth to one-fifth as much as a modular rig and requiring about one-third the space, is very attractive. If more than 9 to 12 long ERWs are to be drilled, a TAD spar/TLP instead of a modular platform rig "drilling" spar/TLP may be very attractive. Consumables such as mud (volume and weight), casing (weight and space), supply by boats, and the production and drilling risers will have a key impact on rig efficiency.
  • Water depth of the location has a major impact on MODU selection. Following are some observations that should be kept in mind for bottom-founded units:
  • In very shallow water depths (generally<

25 ft, definitely < 14 to 20 ft), submersibles offer many advantages over jackups. The smaller shallow-water jackups usually have limited drilling, deck space, and VDL capability compared with submersibles. Submersibles can operate in 10-ft water depth and generally have relatively attractive drilling capability.

  • For independent-leg jackups, which most upscale jackups are, leg penetration may be critical. A 300-ft nominally rated jackup with 100-ft leg penetration becomes a unit that can drill only in ≈ 200 ft of water depth, depending on the required air gap. In addition, it will probably require many preload cycles and thus a long mob and demob period. Pulling legs may also be time consuming.
  • For jackups rated for>

300 to 350 ft, a new high-specification, enhanced, premium jackup may be required, along with the additional cost. In other words, the operator should not over specify his requirements. If water depth and/or a 7,500-psi-WP mud system is thought to be required and because there are few of this class of jackup, the operator should expect to pay a premium price to obtain such a MODU.

  • Selecting between a mat or an independent jackup should center on soil factors, spud-can holes (although holes can also be a problem for mat rigs if they are around a high-load-bearing area of the mat), economics, and drilling capability. Almost without exception, mat rigs are less capable than equivalent independent-leg units, but they can drill in areas where leg penetration is a major problem and/or leg punch through is of major concern. A relatively new concept for helping to prevent leg punch through, "Swiss Cheese," is being used on a limited basis. Multiple 26- to 36-in. holes are drilled through the weak load-bearing lens, allowing the spud can to penetrate the weak soil easily through to the stronger soil below the zone in question. However, it is very expensive and not always a sure solution.
  • If the well under consideration is in jackup water depth but the soil conditions are very unsuitable, shallow gas flows are likely, and a jackup is not available, a shallow-water semi may be able to drill the well very economically.[12]
  • If the water depth exceeds jackup capability, a moored MODU should be considered. Once again, the operator should not generally specify a unit with a lot more capability than required. Following are some observations:
  • Semis generally can be grouped into three broad categories of water depth, which usually follows their generation designation: second-generation units work in<

1,500 to 2,000 ft, third- and fourth-generation units in 2,000 to 5,000 ft, and fifth-generation units in 4,000 to 6,500 ft and beyond. Costs generally increase with water depth, but so do the capabilities of the unit. Again, a sledgehammer is not needed to drive a tack.

  • A prelaid taut or semi-taut mooring system can extend the depths of some units, but the prelaid systems are very expensive to purchase, deploy, and maintain. In addition, other requirements, such as VDL, deck space, marine riser tension, and liquid volume capacity may not be adequate.
  • A second- or third-generation unit can be "stretched" beyond its normal water depth rating by mooring line inserts, but as pointed out earlier, other requirements may be limited.
  • In some limited cases in which day rates for second-generation semis are reasonably competitive with those of deepwater jackups, a semi can drill a well faster and more economically than a jackup. This is usually in water depths of 275 to 300 ft or more and wells of short duration. The reasons are the longer time to preload/pull legs, eliminating all the casing strings that must be run and pulled between the rotary and seafloor, and potential moving delays, all of which the semi does not contend with.
  • Generally, a DP MODU will not be commercially competitive with a moored vessel; however, in deep water and short-duration wells, they can be commercially competitive even with much higher day rates.
  • Ultradeepwater water depths are generally the domain of DP fifth-generation drillships and a limited number of semis. There usually is no valid substitute for their use other than in some limited cases when slim riser and surface BOP technology and/or a prelaid taut or semi-taut mooring system can be used.
  • Environment and metocean have a critical impact on MODU selection. There are three general metocean categories that MODUs fall into. Most can operate any place in the world except the North Sea, in arctic conditions (<

32°F), and in select areas (e.g., the southwest coast of West Australia and New Zealand). The second category of rig can operate in the most severe, hostile, and usually artic conditions. These very-high-end units are very costly. The third category can operate only in the benign to very calm environments of West Africa and the Far East. There are exceptions to these categories, such as some mat jackups, so it is very important to specify the environment and then compare it with the classification ratings of the unit. Mooring and riser analyses for floating units also need to be performed.

The above points are provided for guidance, but other factors may be the determining ones. Most important is the understanding that many unit types may be able to perform the work. The operators should do their homework and the evaluation in a knowledgeable, methodical manner. Once the technical side has been evaluated, HSE&S, the drilling contractor ’ s reputation, crews, management style, drilling contract issues, price, etc., need to be factored into the final selection. Finally, such intangible issues as mutual confidence and respect, perception of ability to work out problems with anticipation of an equitable solution, political influence with local governments, and agent’

s impact and help need to be weighed.

The Future

In the offshore drilling business, predicting the future has been difficult at best. Through the transitions of the last 50 years, a few things have been constant:

  • The industry is amazingly resilient. One way or another, the industry has moved forward in good and bad times. It seems to find ways to do things better, more efficiently, more safely, and in some cases more profitably. Mistakes and wrong courses are common, but a service with improving quality has resulted.
  • The need for oil and gas over the long term continues to increase, although with some ups and downs. The services required to produce petroleum products will be needed for the foreseeable future.
  • Technologically, the rigs of today are vastly superior to the rigs of just 10 to 15 years ago. Today’

s technologically superior machines can now drill more efficiently and safely in up to and over 10,000-ft water depth. It has been said that the technology required to function in the offshore drilling business is more complex and demanding than the National Aeronautics and Space Administration requirements to go to the moon.

  • The industry has matured from the rough-and-ready, full-steam-ahead, damn-the-torpedoes approach of the early years to a more methodical business approach that emphasizes performance and HSE&S.
  • Consolidation of drilling contactors, service companies, and operators has not stymied innovation and improvement, as has been the rule rather than the exception in other industries.

So what can be expected in the next 5, possibly the next 10, years? Following are some thoughts:

  • The demand for petroleum products continues to increase, as does the need to drill to deeper depths offshore, in deeper water, and in more remote areas. The need for MODUs will still be there; however, it is unlikely that a new rig-building boom like that in the late 1970s to early 1980s or late 1990s will occur anytime in the near future. Improvement in existing units to do more for less cost is the order of the day. Possible exceptions to more units being built are enhanced, premium jackups and semi TADs.
  • As stated previously, we are entering a stage of "technology of economics" concerning MODUs and their use. We have drilled in over 10,000 ft of water depth and are producing in>

7,000 ft; however, we must do it more economically. Following are some developments under way for MODUs to accomplish that goal:

  • Continue to develop "dual-activity" technology in which a single MODU does some degree of two well operations simultaneously.
  • Focus on better, more efficient use of MODUs, machinery, and crews. This would benefit the industry from many standpoints.
  • The ability to drill ERWs and subsalt wells with relative ease and efficiency will require a shakeout among MODUs of high-pressure mud requirements, fluid storage, cuttings disposal, setback loads, storage VDL and associated space, and automatic pipe-handling systems. ERWs, especially in deep and ultradeepwater, are an attractive approach to more cost-effective development. MODUs need to fine tune themselves to drill these wells cost-effectively.
  • Use of less expensive or lower-generation MODU for ultradeepwater exploration and certain types of development is a must. SBOPs and slim risers show promise under certain conditions. These approaches allow a third- or fourth-generation rig to drill in ultradeep water, thus reducing the cost of drilling the well.
  • The concept of "dual gradient" shows great promise; however, it needs considerably more development to become practical and commercially viable. To eliminate three or four casing strings, skating on the edge of fracture gradients with confidence that the well will reach the planned depth is the goal of dual-gradient technology.
  • Taut and semi-taut mooring systems for exploration and development MODUs will be refined and become more economical.
  • Ultradeepwater units will be upgraded and modified for more efficient deepwater development. This process has already started.
  • Drilling in>

10,000 ft, especially > 12,000 ft, where some think we will hit a technological roadblock, will be worked on, but economics and cost at this point are of major concern.

The issue for the next 5 to 10 years will not be whether we can drill in ultradeepwater depths or drill difficult ERWs or wells>

30,000 ft, but can it be done in a cost-effective manner.


My thanks to SPE for asking me to write this chapter, which has turned into a bigger project than anticipated but also a labor of love. I have been involved with offshore drilling units for >

35 years, and I cannot find a more interesting subject in our industry. My thanks also to Atwood Oceanics for allowing me the time to write this chapter in hopes that it will enhance the knowledge and enthusiasm for this subject that so many of us have developed during our careers. Also thanks to all those people, from chief executive officers to roustabouts, who helped me gain the knowledge needed to produce this chapter. And finally, thanks go to my family for riding this roller coaster with me that has given us such enjoyment and a solid livelihood.

Acronyms and Definitions

Throughout this chapter, words have been used that are common vernacular in the offshore drilling business. Following is a listing of terms with definitions used in the text that may not be familiar to all readers:

  • API: American Petroleum Institute. An industry organization that, among other functions, publishes recommended practices, specifications, and procedures.
  • BOP: Blowout preventers. Large wellbore-sized valves placed on top of the well to close it in to control high pressures and wellbore fluid flows.
  • DES: Drilling equipment set. The portion of the drilling unit consisting of the derrick, drawworks, traveling equipment, and substructure that sits on a platform, with the remaining equipment moored on a tender next to the platform.
  • HT/HP: High temperature/high pressure. Wells that have unusually high wellbore temperatures and pressures.
  • IADC: International Association of Drilling Contractors. An industry association that represents onshore and offshore drilling contractors on many issues.
  • IMO: International Maritime Organization. A private industry group that functions outside classification societies, country registration, flag state, and governmental regulatory bodies.
  • DP: Dynamic Positioning. A means of stationkeeping over a location of a MODU by means of computer-controlled thrusters.
  • Drilling Contractor or "Contractor": The company that owns the MODU, staffs it, and operates under contract to the operator.
  • ERW: Extended-reach well. A well that has a very long horizontal length and is more challenging than a standard directional or straight vertical well.
  • Floater or Floating Unit: Commonly referred to as a MODU that drills from the floating position, such as semisubmersibles and ships.
  • Generation: An industry practice to categorize semisubmersibles into five categories. This categorization centers on a combination of when the unit was built or upgraded, its water depth rating, and its drilling equipment outfitting
  • GOM: Gulf of Mexico. Large body of water on the southeastern coast of the United States.
  • Kips: Unit of weight or force equivalent to 1,000 lbf or lbm.
  • LT: Long tons or 2,240 lbm.
  • LTI: Lost-time incident. This is an accident after which the individual cannot return to duties within the specified time period as defined by the IADC.
  • Metocean: The wind, ocean current, and sea condition data and statistics for various return periods, i.e., 1, 10, or 50 years.
  • M Tons: Metric Tonnes or 2,204 lbm.
  • MODU: Mobile Offshore Drilling Unit. A MODU is any offshore drilling unit that can be moved from location to location.
  • OIM: Offshore installation manager. This individual is the highest authority on the MODU, similar to a captain or master of a ship.
  • Operator: The oil and gas exploration and producing company that hires the drilling contractor and MODU. The operator directs the contractor in drilling the well.
  • Registration: The formal legality of a MODU for flagging and staffing of the unit.
  • Regulations: Usually associated with the laws of a nation that controls the operation of a MODU.
  • HSE&S: Health, safety, environment, and security. These four functions are usually grouped together into one department on and off the rig.
  • Spars: These are production-type platforms that float. They are used in deepwater, are moored to the seafloor with a spread-moored system, and are shaped like a long cylinder from 72 ft in diameter to over 120 ft and up to 705 ft long. One is currently moored in 5,610 ft in the GOM.
  • Stons: Short tons or 2,000 lbm.
  • TAD: Tender-assist drilling. A concept in which the derrick and associated equipment sit on a platform (fixed, spar, or TLP) and the rest of the equipment is on a tender barge moored next to the platform.
  • TLP: Tension-leg platform. A floating platform held on location by use of long steel vertical tendons fixed to the seafloor. TLPs are used in deep to ultra-deepwater depths.
  • Tonnes: Metric weight equivalent to 2,204 lbm.
  • VDL: Variable deck load. This is the drilling consumables and items that can be readily offloaded from the main deck of a jackup, semi, submersible, etc.


  1. 1.0 1.1 Silcox, W.H., et al. 1987. Offshore Operations. In Petroleum Engineering Handbook, second edition. Richardson, Texas: SPE, Chapter 18.
  2. Barnes, K.B., and McCaslin, L.S. Jr. 1948. Gulf of Mexico Discovery. Oil & Gas J 47 (March 18): 96.
  3. Mobile Rig Register, eighth edition. 2002. Houston, Texas: ODS-Petrodata.
  4. Howe, R.J. 1966. The Evolution of Offshore Mobile Drilling Units. Drilling and Production Practice. API-66-120.
  5. Laborde, A.J. 1997. My Life and Times. New Orleans, Louisiana: Laborde Print Company.
  6. Harris, L.M. 1957. Humble SM-1 Offshore Exploration Vessel, Petroleum Engineering Project Report. Los Angeles, California: Humble Oil and Refining Co., Production Department California Area.
  7. 7.0 7.1 Howe, R.J. 1986. Evolution of Offshore Drilling and Production Technology. Presented at the Offshore Technology Conference, Houston, Texas, 5-8 May. OTC-5354-MS.
  8. McCrae, H. 2003. Marine Riser Systems and Subsea Blowout Preventers, first edition, Unit 5, Lesson 10. Austin, Texas: University of Texas at Austin.
  9. Childers, M. 2005. Surface BOP, Slim Rise or Conventional 21-Inch Riser - What is the Best Concept to Use. Presented at the SPE/IADC Drilling Conference, Amsterdam, Netherlands, 23-25 February. SPE-92762-MS.
  10. Childers, M. and Quintero, A. 2004. Slim Riser - A Cost-Effective Tool for Ultra Deepwater Drilling. Presented at the IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Kuala Lumpur, Malaysia, 13-15 September. SPE-87982-MS.
  11. Sheffield, R. 1980. Floating Drilling: Equipment and Its Use, 2. Houston, Texas: Practical Drilling Technology, Gulf Pub. Co., Book Division.
  12. Childers, M.A. 1989. Operational Efficiency Comparison Between a Deepwater Jackup and a Semisubmersible in the Gulf of Mexico. Presented at the SPE/IADC Drilling Conference, New Orleans, Louisiana, 28 February-3 March. SPE-18623-MS.

SI Metric Conversion Factors

bbl × 1.589 873 E – 01 = m3
ft × 3.048* E – 01 = m
°F   (°F-32)/1.8   = °C
hp × 7.460 43 E – 01 = kW
in. × 2.54* E+


= cm
in.3 × 1.638 706 E+


= cm3
kip × 4.448 222 E+


= N
knot × 5.144 444 E – 01 = m/s
lbf × 4.448 222 E+


= N
lbm × 4.535 924 E – 01 = kg
long ton × 1.016 047 E+


= Mg
mile × 1.609 344* E+


= km
psi × 6.894 757 E+


= Pa
tonne × 1.0* E+


= Mg
  • Conversion factor is exact.