DEEPWATER DEFINED.pdf

8/10/2019 DEEPWATER DEFINED.pdf

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DEEPWATER DEFINEDThe term deepwater has been part of the offshore lexicon for many years. But its meaning has always beenrelative to the state of technology in a given year (Table 1).

Table 1: Deepwater Drilling Milestones

1960s 500-ft water depths represent the practical limit of offshore drilling technology

1970s By the early part of the decade, drilling capabilities surpass 1,000 ft water depth. In1979, the drillship Discoverer Seven Seas sets a water depth record of 4,876 ft

1980s The Discoverer Seven Seas breaks its own water depth record several times:

5,624 ft in 19826,448 ft in 19837,520 ft in 1987

1990 - 2003 The first of a new generation of rigs becomes available to push into water depths of

8,000 to 10,000 ft.In 2001, Discoverer Spiritextends the record to 9,727 ft.

In 2003, Discoverer Deep Seassurpasses the 10,000-ft mark, drilling at a water depthof 10,011 ft in the Gulf of Mexico.

At the beginning of 2008, the record of 10,011 ft set by the Discoverer Deep Seasstill stoodbut perhaps notfor long, as geologists consider new prospects in water depths of up to 12,500 ft, and the industry develops theequipment and methods needed to drill in these depths.The Minerals Management Service (MMS), the agency of the U.S. government charged with overseeingoffshore activity in U.S. federal waters, classifies water depths as follows (French et. al, 2006):Deepwater starts at 1,000 feet; depths of 5,000 ft and greater may be referred to as ultra-deepwater.From the standpoint of technical requirements, these thresholds are somewhat arbitrary, and do not signifyabrupt changes in equipment or methods. The 1000-ft deepwater threshold, for example, does not precludethe use of fixed platforms, which in fact are considered viable to a depth of 2,000 ft. Beyond 2,000 ft, only

floating production platforms have been installed.Because our discussion focuses exclusively on drilling from floating rigs, we will define deepwateras 2,000 ft or greater, and ultra-deepwater as greater than 7,000 ft.While water depth is obviously a key consideration in offshore operations, it is not the only or necessarily eventhe most important one. Factors such as seafloor topography, subsea well depth, and the characteristics ofdrilled formations are likely to be more significant in planning and designing a particular well.

WORLDWIDE DEEPWATER ACTIVITYThe market for deepwater rigs and the subsequent levels of drilling activity are influenced by the types of wellsenvisioned for various projects.

Exploration and appraisal wellsare drilled to gather information about the subsurface, and toestablish the presence or extent of a reservoir. In deepwater, these are usually vertical, drilled fromfloating Mobile Offshore Drilling Units (MODUs) positioned directly over their target formations.

Development wellsare drilled in already discovered reservoirs. Like exploration and appraisal

wells, they can be drilled vertically from an MODU. But they can also be drilled directionally orhorizontally, either from permanently moored floating production platforms, or as one of severalwells clustered on a subsea template.

Rig Supply, Demand and CostOffshore Magazine (July 2007), in its 2007 Worldwide MODUConstruction/Upgrade Survey, reported 75 rigsunder construction or being rebuilt/upgraded for water depths of 2,000 ft or deeper. Six of these rigs (twosemisubmersibles and four drillships) are rated for 12,000 ft water depth, and are scheduled for delivery in2009.


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The demand for semisubmersible rigs and drillships with the highest capabilities began exceeding supply in2000; by 2006-2007, oil company operators were paying dayrates on the order of $400,000 to $500,000. At theupper end of the cost scale, one operator signed a contract in late 2007 for a high-specification deepwater rigat a dayrate of $600,000 for work in the Gulf of Mexico to begin in 2009. Lesser units, which are morerestricted in maximum water depth and load-bearing capacity, may still command dayrates of $200,000 to$350,000.The high-capability units typically are under multi-year contracts to individual operators, who probably

commissioned and underwrote the construction of the rigs. In January 2007, oil companies had MODUscapable of drilling in waters greater than 5000 feet under lease for a total of 1,430 months, or 119 future rigyears. At 2006 dayrates, a single deepwater exploration well can have a price tag of $100 million or more,although that is the upper range. Well costs tend to increase with greater water depths and greater well targetdepths below the seafloor (mudline). Operators in the Gulf of Mexico have begun targeting formations lyingmore than 20,000 feet [6096 m] below the seafloor in water depths of ,7000 to 8,000 ft, giving occasional totalwell lengths of 28,000 to32,000 ft.The per-well drilling cost for development wells tends to be somewhat lower than that of exploration orappraisal wells because of existing information and the learning-curve effect. On the other hand, completioncosts are a significant addition to the total well cost. Operators can use batch-drilling techniques to reducedevelopment well costs, and they are constantly looking for ways to reduce the time it takes to drill a well. Withday rates being what they are, saving several hours on a single task and several days on an entire wellrepresents a significant cost reduction.

Safety and QualityAs with any drilling project, safetyand qualityare of paramount importance in deepwater. Every operator andcontractor strives for a zero accident rate and takes extraordinary measures to achieve it through training,development of safe procedures, careful supervision, equipment specification, and a maintenance program.The equipment and control systems aboard a modern, deepwater MODU or production platform typicallyreduce the exposure of the drilling crew to drilling hazards to a fraction of what it was even 10 years ago.A well must be drilled to a quality standard that enables it to fulfill its purpose. An exploration well must enablethe operator to obtain logs and other formation data, and, in some cases, to flow-test a discovery.Development wells must provide high-quality completion zones that allow fluids to pass freely out of theformation into the well or from the well into the formation at the specified rates. Wells that cannot deliver thespecified flow rates may never pay back the costs to drill them.Deepwater drilling and field development projects have been the most interesting and exciting segments of theoffshore industry for several years. They have also absorbed much of the industrys total capital expenditureand have been generating an increasing share of its revenues.

Areas of ActivityMost areas of offshore activity have seen some deepwater drilling, but the bulk of the action is concentrated inthree regions:

Gulf of Mexico Campos Basin and a few other areas offshore Brazil, West Africa, from the Gulf of Guinea south to Angola

The North Sea also participates in deepwater drilling, and because of the harshness of the climate, it makessense there to lower the deepwater threshold to 1,000 ft. In Southeast Asia off the island of Borneo, oil hasbeen found in water depths greater than 2,000 ft. And offshore in Egypts Nile Delta region, deepwater drillinghas discovered commercial reserves of natural gas in depths beyond 2,000 ft.

Gulf of MexicoFigure 1(Peterson et. al, 2007) shows deepwater discoveries in the Gulf of Mexico by year, while Table 1listssome of the more signifcant discoveries in terms of water depth. Note the dramatic increase that occurred in1987 with the Coulomb/Na Kika discovery.
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F i gure 1

Table 1: Some Gulf of Mexico Deepwater Discoveries, 1975-1987 (Active Fields)

Table 1: Some Gulf of Mexico Deepwater Discoveries, 1975-1987 (Active Fields)

Name Water Depth Year Discovered

Cognac 1023 ft [312 m] 1975

MC 113 1986 ft [605 m] 1976

Zinc 1478 ft [450 m] 1977

Typhoon 2679 ft [817 m] 1984

Allegheny 3294 ft [1004 m] 1985

Coulomb/Na Kika 7591 ft [2311 m] 1987

Baha 7620 ft [[2323 m] 1996

Spiderman/Amazo 8082 ft [2463 m] 2003

Jubilee 8788 ft [2679 m] 2004


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Tobago 9,493 ft [2893 m] 2004

Gulf of Mexico drilling results through 2005, as listed by the U.S. Minerals Management Service, include 13discoveries in water depths from 8,000 to 9,000 ft and five discoveries in depths greater than 9,000 ft; thedeepest of these was the Trident discovery in 9,743 ft of water (French et. al, 2006).As of early 2008, the water depth record for drillingworldwide as well as Gulf of Mexicostood at 10,011 ft.

This record was set in 2003 by the Transocean drillship Discoverer Deep Seas.

BrazilDuring the late 1980s and into the 1990s, Brazil became the second major laboratory for deepwater technologydevelopment, and the state oil company (Petrobras) set many drilling records. Urged on by Brazils drive tobecome self-sufficient in oil production, Petrobras became the leading user of subsea-completed wells tiedback to floating production systems as a means of bringing new discoveries onstream quickly. Havingdeveloped this early production technology in shallower water, Petrobras was able to use it with greatconfidence to develop fields in water depths ranging from 1,000 ft to over 5000 ft during the 1990s. Operatorscontinue to discover and develop new deepwater fields in Brazils offshore basins. (Figure 2)

F i gure 2

West AfricaHaving observed similarities between Brazils marine geology and that of West Africa, oil companies began toexplore the deepwater basins in the Gulf of Guinea during the 1990s. They discovered a series of large fieldsin water depths from 1000 to 5000 feet [305 to 1524 m], particularly in Angolan and Nigerian waters, but alsooff of smaller countries such as Equatorial Guinea. (Figure 3).
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F i gure 3

West African deepwater activity is characterized by a substantial number of very large field developmentprojects based primarily on subsea wells tied back to floating production platforms. More recently, interest indeepwater prospects has extended northward from the Gulf of Guinea to the coastal waters of Mauritania and

Morocco.

Levels of ActivityOne gauge of the level of deepwater activity is the number of rigs drilling in various locations and water depths.Offshore Magazine (2006) listed 101 rigs capable of operating in water depths greater than 4000 ft (70semisubmersibles and 31 drillships). At the time of writing, several of these units were under construction anddue for delivery by 2008. Thirty-one of these rigs are rated and equipped for drilling in waters deeper than8,000 ft.French et. al (2006), in their MMS Report Deepwater Gulf of Mexico 2006: Americas Expanding Frontier,noted that in 2005, there were 126 deepwater rigs operating worldwide in depths exceeding 1,000 ft, anddistributed among the deepwater regions as shown inFigure 4.
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F i gure 4

This report also provides a breakdown of all deepwater rigs by maximum water-depth capabilities, as shown inFigure 5,although the authors do not explain the discrepancy between the total number of rigs included in thedepth capability classification and the number included in the geographical distribution.


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F i gure 5

The Gulf of Mexico is clearly the worlds leading deepwater region, accounting for 31 percent of all deepwaterrigs in service, and 45 percent of rigs capable of drilling in water depths greater than 5000 ft.Palathingal andWright (2006) reported in the September 2006 issue of Offshorethat there were 176 units in the floating drillingrig fleet. So it is clear that between 57 and 79 percent of the floating MODU fleet is capable of operating indeepwater, depending on the threshold that is used. The only floaters not rated for at least 1000-ft waterdepths are older units that have not been upgraded, and perhaps a majority of those rigs aresemisubmersibles working in the North Sea and East and Southeast Asia.French et. al(2006) observed the following trends in the Gulf of Mexico::

From 1992 to1997, the average number of active deepwater rigs increased steadily, from three to 26. The number of deepwaterwells drilled each year likewise increased from 32 to 176. During this period, twenty-five wells were drilled in water depths greaterthan 5,000 ft, and one well exceeded 7,500-ft water depth.

From 1998 to 2000, the number of rigs working and deepwater wells drilled leveled off. From 2001-2005, the number of deepwater rigs operating in the Gulf reached an all-time high of 41 in 2001, while the number of

wells drilled hit 211 (59 in water depths of 5000 ft or more and six in water depths greater than 7,500 ft). By 2005, the number ofdeepwater wells drilled had declined to 119.

The decline in total wells in the Gulf of Mexico from 2001 to 2005 corresponds with a shift of activity to WestAfrica, where operators have been drilling production wells for a growing number of large deepwater fielddevelopments.The Gulf of Mexico is still the scene, however, for the most challenging wells in the greatest water depths. Anincreasing number of these wells in depths greater than 5,000 ft are targeting formations that lie below thicksalt sheets and are 15,000 to 20,000 feet below the seafloor, giving a total well depth from the surface of25,000 to 30,000 feet. Plans are being made to drill in water depths to 12,500 feet.


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DEEPWATER ENVIRONMENTSDeepwater operations present challenges related not only to water depth, but also to open water environmentsand subsurface geology. While these parameters differ from one region to another and also within the sameregion, certain characteristics do tend to be associated more commonly with deepwater environments thanwith shallow-water ones.

Open WaterDeeper waters almost always mean greater distances from land. This extra distance may not be significant inmild environments such as offshore West Africa, where the main concerns are sea swell and coastal currents.But in other environments such as the North Sea and Gulf of Mexico, it translates into harsher wind and waveconditions that can significantly impact well planning, design and construction operations.In the Gulf of Mexico, for example, warm-water eddy currents break off from the Loop Current that enters theGulf through the Yucatan straits and exits through the Florida straits (Figure 1Eddy currents in the Gulf ofMexico. NASA, Jet Propulsion Laboratory).These eddy currents, which can be up to several hundred milesacross and several thousand feet deep, rotate clockwise at speeds of up to four or five miles per hour. Theydrift slowly westward across the Gulf, along a path that takes them through the deepwater drilling areas in theCentral and Western Gulf. Obviously, this mass of rapidly moving water exerts a strong force on any structureit encounters - far greater than the shallower currents found nearer to shore.

F i gure 1

Eddy currents also affect hurricanes. The warm water provides energy that can be drawn up by hurricanes thatpass over them, allowing the hurricanes to strengthen. This seems to have happened several times in recentyears. Both Katrina and Rita in the summer of 2005 strengthened as they moved across the deepwater areas(Figure 2Hurricane Katrina, 2005.From National Oceanic and Atmospheric Administration) then weakenedas they moved over cooler water before making landfall. Both storms did more damage to deepwater floatingproduction platforms and drilling rigs than had been expected and alerted authorities to potential deficiencies indeepwater specifications and requirements.

F i gure 2

The wind and wave forces of a hurricane may combine with the strong flow of an eddy current to exertextremely heavy loads on offshore structures and drilling rigs. It may have been such a combination that toreseveral semisubmersible rigs loose from their moorings and set them adrift during Katrina and Rita, andcaused the Typhoonmini-Tension Leg Platform production facility to capsize (Figure 3:Typhoonplatform (a)before andFigure 4(b) after Hurricane Rita. Courtesy of Minerals Management Service).

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F i gure 4

To the extent that the deepwater wind and wave regime may be more severe than in shallower water, drillersmay experience a reduced weather window for moving a rig on location and deploying the mooring system,and also for moving off location.

Subsurface EnvironmentOffshore drilling takes place on the continental margin, which is divided into the continental shelf, slope, andrise(Figure 5.Courtesy of Office of Naval Research,www.onr.navy.mil).

F i gure 5

The shallowest segment, the continentalshelf, is usually smooth and gently sloping and may extend out fromshore for many miles until the water depth reaches about 650 ft. In the Gulf of Mexico off the Texas coast, the100-ft water depth can be more than 30 miles from the beach. By contrast, in active tectonic zones such asoffshore California and much of the rest of the Pacific Rim, the shelf may be only a few miles wide. Shelfsediments typically have been deposited slowly in shallow water environments over numerous cycles of highand low sea levels. Where the shelf ends, the seafloor drops off at a much steeper rate to form the continentalslope. The seafloor topography of the slope is far more rugged than the smooth shelf and is characterized bycanyons, gullies, and outcroppings. The slope eventually flattens somewhat to become the continental risethat extends outward and downward to the deep ocean floor, or abyssal plain. The deepest drilling in the Gulfof Mexico is now occurring on the continental rise.The deepwater formations in the Gulf of Mexico, offshore Brazil and West Africa have certain geologicalcharacteristics in common:

Deepwater basins tend to be younger than shallow-water basins. Their sediments have been deposited rapidly in a high-energy (turbid) marine environment at the

base of the continental slope and tend to be poorly compacted.

Turbidite-dominated sequences are common, and the sediments tend to be clay-rich with lowpermeability. Sandy formations occur only occasionally and are discontinuous. Many of the clay-bearing shale sequences contain significant proportions of water.These characteristics give rise to one of the key challenges of deepwater drilling: the narrow window betweenformation pore pressure and fracture pressure.

Pore Pressure and Fracture PressureThe depositional history and immaturity of deepwater basinstogether with the fact that much of theiroverburden corresponds to the weight of the water above a formation rather than water plus rock matrixmakes them more likely to contain sediments that are undercompacted. This tends to result in pore pressuresthat are higher, and fracture pressures that are lower, than those that would be encountered in land wells orshallow offshore wells at the same depths.
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This combination of higher pore pressures and lower fracture pressures has important implications fordeepwater drilling projects. These are addressed in the subtopic titled Deepwater Well Planning and Design,but are summarized as follows:

Drillers control formation pressure by adjusting the propertiesprimarily the density or weightof the drilling fluid. This function ofthe drilling fluid, or mud, is expressed in the well-known equation relating hydrostatic pressure to Equivalent Mud Weight (MW) andTrue Vertical Depth (TVD):

Phyd= 0.052 x MW x TVD (1)where Phydis in psi, MW is in pounds per gallon (ppg) and TVD is in feet.

To prevent formation fluid from entering the wellbore, the mud weight must be high enough so that the pressure exerted by the mudcolumn is higher than the formation pore pressure. At the same, it must not be so high that the pressure of the mud column beginspushing fluid into the formation (the condition known as lost circulation or lost returns) or worse, that it actually causes theformation to fracture. In normally pressured formations, it is usually possible to weight up the mud to handle any expected formationpressure without risk of lost returns and formation damage. The difference between the pore pressure and the fracture pressure isgreat enough to allow for some latitude in the mud weight schedule.

The situation is less forgiving in deepwater wells, which tend to exhibit narrower differences between pore pressure/fracturepressure, leaving little margin for error in determining mud weight (Figure 6Comparison of pore pressures and fracture pressuresfor a land well and a subsea well drilled in 4000 ft of water. Note that the subsea well exhibits a much smaller difference between

pore pressure and fracture pressure).. The pressure that is needed to prevent intrusion of formation fluids may be very close to thepressure that will fracture the formation. The weight of the mud column also increases as the well gets deeper, and this can push thepressure beyond the fracture pressure of the formation. The narrow pore pressure/fracture pressure window is the source of manychallenges in deepwater drilling and places severe constraints on the well planning and design process.


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F i gure 6

When a deepwater well finally reaches its reservoir target, it is more likely than a well in shallow water toencounter high temperatures and high pressures that create challenges for drilling, well testing, wellcompletion, and production operations. These reservoirs and the wells drilled into them are commonly given

the designation HTHP. Blowout preventers and production trees for deepwater wells may be rated forpressures of 15,000 psi and temperatures of 350 F.

Low Seafloor TemperaturesLow seafloor temperatures are characteristic of all deepwater operations. Even in tropical regions, the watertemperature below 2000 ft [610 m] will be no higher than 34 to 38 F [1 to 3 C]. These low temperaturesaffect both hydrocarbon fluid flows and the metallurgical properties of subsea equipment. The effects are mostsignificant in production operations, where hot well fluids enter cold seafloor equipment and piping, but canalso impact drilling operations.

Geohazards


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Several types of geological hazards (geohazards) are encountered frequently in deepwater drilling areas.Some of the geohazards reflect the depositional history of deepwater basins, particularly mass-transportdeposits (MTDs) resulting from resedimentation occurring after the period of original deposition. Deepwatergeohazards are found from the seafloor to depths of about 3000 ft below the mud line (BML) and posesignificant risk for a successful drilling operation, including loss of the well. Geohazards can be identified on 3Dseismic records and by seafloor and shallow subsurface surveys. Identification and proper planning allowdrillers to avoid or mitigate the effects of deepwater geohazards.

Deepwater geohazards include seafloor features or events such as mud or debris slides and unstable soils, aswell as a variety of incompetent formations below the seafloor. While these can create difficulties for drilling,the greater threat comes from shallow formations (sands) containing water or gas under high pressure that canbegin to flow into the wellbore or even around a cased wellbore to erupt at the surface. These shallowgeopressured sands are usually shut off by chemical treatment delivered in the drilling mud and by casing andcementing. These measures are not always effective, however. Marathon Oil Company reported the loss toshallow water flow (SWF) of an exploration well drilled in 2001 on Garden Banks Block 515 in 3300-ft waterafter the geopressured formation had been cased off (West and West,2005). In 1999, Marathon had drilledsuccessfully through the same SWF sands.Shallow water flow was identified as one of the five most urgent challenges for deepwater drilling (Sparkmanand Smith, 1996), and has been addressed by numerous studies. SWF creates difficulties in setting conductorpipe and surface casing; and when it is occurs in a well with a narrow fracture gradient, it contributes toincreased well costs through the need for additional casing strings. Severe SWF and fracture gradientconditions may, in fact, make it impossible to penetrate a potential reservoir with a wellbore of sufficientdiameter to allow for economically feasible production flow rates.

HSE issuesProtection of health, safety and the environment (HSE) is paramount for onshore and offshore operations alike.Avoiding accidents and eliminating risks to personnel is a top priority, both in operational activities andequipment design, and minimizing pollution and harmful environmental impacts is a constant objective.All of the risks associated with the hostile marine environment and the handling of volatile liquids are commonto both deepwater and shallow water drilling operations. Several aspects of deepwater drilling, however, mayincrease the urgency of HSE concerns.

Weather and environmental forcesDeepwater operations generally involve exposure to marginally more severe and less predictable weather andenvironmental forces. In The Gulf of Mexico, for example, the powerful eddy currents create hazards indeepwater that to do not exist in shallower water areas. Storms may be more severe in deepwater areas, andthese regions may also be more exposed to rare phenomena such as rogue waves.

Distance from shoreTransport to and from offshore facilities is inherently risky, and greater distances would seem to add to the risk.Remoteness and distance from shore also mean that evacuation of deepwater facilities in the face ofhurricanes or other severe storms requires more lead time and takes longer to accomplish. Careful planningand contingency arrangements are a must.

Sensitive seafloor ecologyCertain deepwater areas in the Gulf of Mexico are home to communities of unique benthic flora and fauna,which place them off-limits to drilling. Where little is known about the deepwater seafloor environment, drillersmay be required to conduct detailed underwater surveys and eliminate or minimize release of pollutants.

Geology and GeohazardsThe geology and geohazards of deepwater areas may increase the risk of blowouts and require moreconservative well-control procedures. In previously unexplored deepwater trends, ignorance of the underlyinggeology adds risk to drilling operations.


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DEEPWATER RIG REQUIREMENTSFrom a broad business perspective, the challenges of deepwater drilling are similar to those encountered inother oilfield projects: namely, to deliver the desired result on time and on budget while avoiding accidents andenvironmental incidents. The main difference is one of scale. Deepwater drilling is a high-stakes gameinvolving very large expenditures for the opportunity to find and produce large volumes of hydrocarbons.Everything costs more in deepwater, beginning with the drilling rig itself. Therefore, there is great emphasis onthe efficient use of the rig and all associated equipment.

Load-bearing CapacityThe extreme demands of deepwater drilling require high load-bearing capacities. A rig must be able to supportlong, heavy strings of drill pipe and casing and a marine drilling riser, as well as a subsea blowout preventerand wellhead assembly that may have a working pressure rating of 15,000 psi. This requirement affects thedesign of the vessels hull, drilling systems and marine systems.

Deck load is less an issue for drillships than it is for semisubmersibles. Early semisubmersibles haddeck loads of about 2,000 tons or less. This increased to 4,000 - 5,000 tons for semis built duringthe 1980s. The leading deepwater drilling unit of that time (a drillship) boasted a variable load of9,100 tons. New semis built in the late 1990s and 2000s vary in deck load from 5,000 to 10,000tons, depending on their water-depth and drilling-depth ratings. The lower range of deck load forsemis rated for 10,000-ft water depth and 30,000-ft total well depth is about 7,700 tons, and theupper range exceeds 10,000 tons. The deck-load capacities of large drillships are now in the rangeof 20,000 to 25,000 tons.

The derrick and associated equipment that supports the drillstring, riser, and casing must be madestronger and more powerful for deepwater operations. Deepwater rigs are typically equipped withgreater mud pumping and power generation capacities than are found on shallow-water units.

Station keeping requires either a deepwater mooring system with longer lengths of chain and wireor a thruster-powered dynamic-positioning system (DP). Rigs drilling in deepwater are alwaysequipped with a dedicated remotely operated vehicle (ROV) system. Each of these elements addsdeck-load weight.Supporting this extra weight requires additional buoyancy, which can only be achieved by increasing the sizeof the hull so that it displaces a larger volume of water. The extra weight, carried at or above deck level, alsocreates stability problems that must be addressed by the hull design. The additional structural steel and steelplating increase the weight of the hull, which in turn places greater demands on the station-keeping system.The additional size and capacities raise the cost to build deepwater rigs. The cost, in turn, is reflected in higherday rates for deepwater units and, thus, in the cost of deepwater wells. This all finally means that the oil andgas prospects targeted for deepwater drilling must be of sufficient size to allow these costs to be recovered.

Efficient use of rig timeThe need for greater load-bearing capacity adds significantly to the overall cost of drilling wells in deep andultra-deep water depths. The high costs challenge drillers to optimize all aspects of the drilling process so thatthese expensive rigs can operate with the greatest possible efficiency.The offshore industry in general places a premium on saving rig time by operating as efficiently as possible. Atpresent, this goal is handicapped by a shortage of qualified personnel, an issue that is beyond the scope of thisdiscussion. This section provides a brief overview of several aspects of deepwater operations wherecompanies seek to improve efficiencies.

Mobilization and Moving onto LocationDeepwater MODUs are typically on full day rate when moving from one drilling location the next. These moves,or mobilizations (mobs), can involve cross-ocean voyages between such locations as the North Sea, Gulf ofMexico, Brazil, and West Africa. Drillships make these mobs under their own power. For semis, these long-distance mobs can be hastened by loading the rig aboard a heavy-lift vessel for a dry tow rather than using

tugboats to wet-tow the rig with its hull in the water (Figure 1.Source: Charles Townsend,www.acrigs.com.)

F i gure 1
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More often, the distance involved will be shortfrom one block to another within the same region or betweentwo drilling locations within the same block or the same field. The opportunities for optimization are greaterduring a series of short moves, particularly when a rig is drilling and completing a set of subsea developmentwells within a single field. Dynamic positioning offers the greatest efficiency, since there are no anchors andmooring lines to deploy. But even with conventionally moored MODUs, careful planning can minimize thenumber of moves and reduce the time each one requires.In development drilling projects, subsea wells can be located in several groups around the field so that each

well in a group can be drilled by simply repositioning the rig using its mooring winches to take in and pay outline, rather than retrieving and deploying the entire mooring system. In this manner, it may be possible to drill12 to 15 wells with only three to five rig moves.

Spudding the WellThe first set of tasks involved in spudding, or getting a deepwater well started, require round-tripping thedrillstring several times. In water depths of 5,000 to 10,000 feet, this takes considerable time, during whichnothing else is happening to actually advance the drilling operation. If any of these tasks can be combined,thereby eliminating one or more round trips, it will improve the overall efficiency of the operation.The uppermost sections of a deepwater well are typically drilled without the BOP or drilling riser in place.Before drilling can proceed to more than 1000 to 1500 ft or so below the sea floor (mudline), however, theBOP and marine drilling riser must be deployed (Figure 2-Subsea BOP stack in place at the end of drillingriser. CAD computer model for deep sea scientific drilling vessel D/V Chikyu. Image provided courtesy ofJAMSTEC. All rights reserved).The drilling riser is a tubular column that extends the well with full pressurecontainment from the BOP to the drilling rig, providing an annulus around the drillstring for drilling fluid to returnto the surface. Installing the BOP can involve two roundtrips of the drillstring, with the riser being run betweenthe two. Because of their design, the requirement for pressure integrity, and the need for buoyancy along theirlength, running and retrieving a drilling riser is more time-consuming than tripping the drillstring or running astring of casing.

F i gure 2

It is possible to move from one well to another without retrieving the riser and BOP to the surface if the wellsare close enough to each other. The BOP is released from the finished well, raised above the seafloor, and

hung off beneath the drilling rig while it shifts to the next well. This can be performed with little risk when thetwo wells are very close together, as is the case with much deepwater development drilling.To enable this kind of time-saving operation while also having the ability to spud a well with riserless drilling,some newly built or upgraded deepwater rigs are equipped with dual drilling systems, so they can performcertain operations simultaneously (referred to as dual-activity (Figure 3Deepwater dual activitysemisubmersible West Venture. Seadrill.).While the primary drilling rig suspends the BOP and riser abovethe seafloor, the second derrick is moved over the new well and performs the riserless operations to get thewell started. When these are finished, the primary derrick is moved over the new well to attach the BOP, anddrilling can then proceed without the delay of round tripping. The dual-activity capability removes theinstallation of the BOP and drilling riser from the well schedule critical path.

F i gure 3

This may seem to be an extreme measure, but it does indicate the lengths to which drillers and oil companieswill go to save rig time with deepwater MODUs that carry $500,000 day rates. If two days can be saved wheninitiating a new well, the cost of a second derrick will be well worth it. Oil companies monitor drilling operationsclosely for unproductive time, a category covering just about all the time that the well is not making progresstoward its target, i.e., drilling, running casing, cementing casing, and so forth. Their goal is to reduce theunproductive time to an absolute minimum.
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Marine drilling riser design and operationNo piece of equipment is more important to the success of deepwater drilling than the marine drilling riser. Asthe extension of the well between the BOP and the drilling rig, the riser is a primary device for pressurecontainment and well control. It is also the conduit for drilling fluid to return to the surface and the guide for thedrillstring and casing down to the wellhead. Riser failure has very serious consequences for drilling operations,safety, and environmental protection.The riser is made up of a series of 20-21-inch ID tubular joints coupled together with highly engineeredconnectors - threaded, flanged, or mechanical.Kill and choke lines used to re-establish well control when a gas kick occurs are attached to the outside of theriser and terminate at the BOP stack. A 20-in. steel tube with several much smaller tubes attached to it andextending up to 10,000 feet between the surface and seafloor has little structural integrity and is obviously veryvulnerable. Tensioning at the top allows it to resist environmental forces. To perform reliably it must bedesigned with the utmost care.The design and specification of the riser must take into account the loads and stresses that it will experienceover the entire range of the rigs drilling capabilities. These include hydrostatic pressures; the MODUs motionsin response to maximum environmental conditions for drilling operations; bending stresses imposed by theMODUs lateral motions, particularly if the motions exceed the limit of the pre-defined watch circle; and fatiguefrom repeated motions and vibrations that may be caused by currents. There is also the special case of riserhang-off in the event that the rig must rapidly disconnect from the well in an emergency.The lower end of the riser is firmly attached to the BOP at the seafloor, while the upper end is attached to themoving drilling rig. Although the rigs motions are limited by the mooring or DP system and the riser is

suspended from the rig by a set of tensioners so that it will never go into compression, the riser still respondsto rig motions. Its behavior in service is thus dynamic instead of static and many of the loadings are nonlinear.Analysis of a specific riser design can be as complex and exhaustive as the available budget allows andincludes static, quasi-static and dynamic methods, as well as finite element analysis of local components, suchas joint connections.API Recommended Practice 16Q(1993) covers marine drilling riser analysis in detail.


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PROJECT MANAGEMENT CONSIDERATIONSWhile all deepwater drilling projects have certain things in common, each offshore region, each basin, andeven individual wells within the same block or field offer different sets of challenges. The success or failure of awell depends on correctly anticipating and responding to these challenges. More than anything else, managinga deepwater drilling project involves combining knowledge, experience, and information to direct the use of avast array of technologies and operational capabilities.As with any offshore project, operators and contractors approach deepwater drilling from two distinct

perspectives. The operator approaches it as a customer who brings the money to the table, assumes the roleof overall project manager, sets objectives and priorities, makes the key decisions during the drilling operation,and judges the relative success or failure of the results. The operator maintains a relatively low-profilepresence offshore, however, and it is the contractor who manages all tasks during project execution.

ContractsIn general, depending on the rig market at any given time, drilling contracts tend to favor either the operator orthe contractor. This has traditionally imparted an adversial element to the operator/contractor relationship.A more collaborative relationship has developed for deepwater drilling because of the complexity of theprojects, the levels of risk involved, and the magnitude of expenditure. However, while both parties recognizethe need to align contractor interests with those of the operator, the realities of a tight rig market have favoredthe contractors from about 2000 to 2007 and given them considerable leverage in the contracting process.

Conventional Day Rate ContractThe conventional offshore drilling contract is based on a day ratelease for the MODU and crew. The leaseruns for the number of days required to drill a well or a series of wells. If the market favors the operator, thecontractor usually must agree to mobilization, demobilization, and standby fees that are less than the full dayrate. Operator and contractor distribute the responsibility and costs for other risks and liabilities based oncompetitive market factors. But the contract locks in the day rate and other terms only for the single well orseries of wells. The cost of the well is not capped. The day rate contract worked, and still works, efficiently forwells in conventional water depths.

Term ContractWhen the industry began moving into deepwater, only a small percentage of the drilling fleet had deepwatercapabilities. This shifted the market to favor the contractors, who began requiring operators to pay forupgrading existing rigs or building new ones. Instead of paying up front, however, the operator guaranteed thatthe contractor would receive adequate return on its construction investment by agreeing to pay a day rate for aspecified period of time, or termperhaps anywhere from one to five years, or even longer in a few cases.The MODU might then drill a series of exploration prospects in the operators portfolio or drill and completeproduction and injection wells for a field development project. These contracts require longer-term planningand are generally negotiated at a higher level within the companies than a day rate lease.

This form of term contract has increasingly become the model for deepwater drilling, although as the marketexpanded into a boom of sorts some contractors began to upgrade existing units or build new rigs without aguaranteed contract. Under the term contract, the contractor is guaranteed a known rate of return, subject toperformance criteria, and the operator is guaranteed the availability of a suitable MODU. The operatorgenerally works with the contractor to develop the performance and equipment specifications for the upgradeor new-build and monitors construction closely. A term contract allows an operator to benefit from learningcurve effects and build an effective drilling team with the contractor. In exchange for the certainty of the termcontract, both parties trade off flexibility and take on the risk that day rates for comparable units will moveeither up or down.

Turnkey ContractIn a turnkey contract, the contractor agrees to drill one or more well to the operators specifications for a fixedcost. The cost cap protects the operator against higher costs that could be incurred under a day rate contract.The contractor takes the risk of cost overruns, but also has the opportunity to earn a high profit on the well ifthe drilling can be completed in fewer days than are built into the fixed cost. Turnkey contracts are not used in

deepwater drilling because of the high costs and risks and the prevalence of day rate-based term contracts.

Operator and Contractor InterestsIt is difficult to align operator and contractor interests under a traditional day rate lease contract, apart fromincentives and penalties, because the contractor tends to profit more as the drilling time lengthens, whereasthe operator benefits from a shorter drilling time. The term contract, with its fixed length and fee, can eliminatethis disparity and result in a very close partnership between contractor and operator, particularly if the contractincludes contractor performance incentives based on quality, schedule, cost and safety criteria. Effectiveteamwork is essential for success in deepwater drilling, and operators are focusing more attention onpersonnel management techniques with both their own employees and the drilling contractors.


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Health, Safety and Environment (HSE)HSE management is an integral part of all operations aboard an offshore drilling rig, and new MODUs aregenerally safer by design than previous generations of rigs. But safety performance still depends on theoperators and contractors values regarding HSE, on how well they communicate their values to all personnel,and on how effectively these values are embodied in rules, procedures, and the structure of HSE programs.

Aboard a MODU, safety is always everyones responsibility and first priority.HSE standards and requirements are imposed by host country national governments, and are in force in alloffshore areas. They vary from extremely rigorous to relatively lax, as does enforcement. In general, the majorhost countries in West Africa have modeled their safety regimes on those developed in the North Sea.All contractors and oil companies have their own sets of HSE standards, which, in many cases, are morerigorous than those of the host country. When a drilling contract is put out for bid, the operator requiresprospective contractors to supply information about their safety systems. Before signing a contract, theoperator may audit a contractors safety system, and it may conduct periodic follow-up audits through theduration of the contract. As part of the contract, the contractor must conform its safety system to the standardsand processes of the operators system, and the operator may place its own safety manager aboa rd the drillingrig to ensure compliance and encourage performance.With appropriate standards and procedures in place, HSE performance comes down to how effectively thevalues and commitment are communicated to all rig personnel, including those of service companycontractors. This process begins with the Captain or Master, who is the top marine officer on board and isultimately responsible for safety performance and the overall well-being of the crew and the rig itself. Thecontractor will typically have a safety manager or officer aboard to administer the system, monitor its

functioning and establish education programs. Standards and procedures are communicated and enforced bysupervisors within the drilling and marine crews. Handoff meetings at shift changes ensure that all drillingpersonnel are aware of everything about the well situation when they take over.MODUs are required to hold frequent emergency response drills. The Captain or Master has ultimate authorityin an emergency situation and is responsible for making such decisions as to execute an emergency quickdisconnect from the well, to leave the drillsite, or to abandon the rig.

Management Structure and PersonnelThe operating company provides overall direction for a project, sets goals and objectives and makes keydecisions during the drilling process. The operator develops the well plan and presents it to the contractor forexecution.Operators typically have one or two company representativesaboard a MODU (the second to oversee thesecond shift, or tour). They provide direction to the contractor about execution of the well plan andcommunicate with shore-based operator personnel.Although the company representatives have full authority over everything directly related to the drilling of the

well, they tend to operate with less autonomy than they had in the past, before real-time communicationstechnology enabled engineers and geologists to monitor and assess drilling progress from a headquartersoffice and provide advice or solutions when problems are encountered.The company representatives typically report to shore-based general managers, or to country managers incharge of a support base in foreign locations. They in turn are responsible either to a regional assetmanagement team or to a functional division, such as exploration or drilling.Without question, the Captainor Masterof an MODU bears ultimate authority for the safety and well-being ofthe crew and the rig. The Captain supervises a marine crew that includes First, Second, and Third Officers,First, Second, and Third Engineers, DP operators (on dynamically positioned units), ballast control operators,and a handful of able-bodied seamen, mechanics, electricians, communications specialists, and medicalpersonnel. The Captain also supervises a domestic crew, headed by a steward, that includes cooks, galleyhelp and housekeepers. The marine crew is responsible for all aspects of supply logistics, including mooringand unloading of supply boats and helicopter landings.The contractors toolpusher(who generally has an assistant to supervise the second shift) is in overall chargeof the drilling crews. The toolpusher discusses the status of the drilling operation with the operators

representatives and gives the orders for the day to the driller. The drilleris in charge of all activities on the rigfloor and typically has an assistant for the second shift. On rigs with automated pipe-handling systems, thedriller can control all routine drilling activities from an enclosed console on the rig floor (Figure 1). Even aboardautomated rigs, however, the drilling crew typically includes several floor hands, two derrickmen, and severalroughnecks and roustabouts for each shift. A mud engineer monitors the drilling fluid for drilling cuttings andmakes adjustments to mud weight and composition. The contractor also provides mechanics and electriciansdedicated to keeping the rig and associated equipment functioning, along with one or two crane operators, whomay double as derrick hands.The contractor files daily reports about the status of marine and drilling operations with its local support base orheadquarters. Full engineering support for the marine and drilling operations is available from the companyscentral engineering department.


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SchedulingThe duration of a deepwater drilling project is a matter of considerable uncertainty until some benchmarkshave been established for a particular basin or area. Operators place great emphasis on the use of proceduresand technologies that allow them to shorten the drilling schedule. In many cases, this will depend on accuratecoordination among vessels and equipment, such as the drilling rig and anchor-handling tug. In subsea fielddevelopments, careful planning and coordination between the drilling rig and various installation vessels canachieve significant time savings.A project critical pathis a key element in managing a drilling schedule. The critical path assesses every taskor operation in relation to other tasks that impact it in some way. A task belongs on the critical path if it must becompleted before another task can be performed. The sequence of operations can then be analyzed with thegoal of removing tasks from the critical path. For example:

A rig must be moored (or a dynamic positioning reference established and calibrated) before drillingcan begin. Although it is not commonly done in drilling operations, the mooring system can beinstalled before the MODU arrives at the location, thus taking it off the critical path. The rig then hasonly to pull in the mooring lines and adjust the tension when it does arrive.

Use an MODU with dual-activity capabilities. This allows a number of tasks to be performedsimultaneously rather than sequentially, thus removing them from the critical path. For instance, thesecond rig could be used to spud a new well and set the 30-in. conductor and 26-in and 20-in.casing in riserless mode, while the primary rig hangs off the riser and BOP.Scheduling becomes more important for an operator that has leased a MODU on a long-term contract. The

sequence of drilling projects must be scheduled carefully to ensure that the rig is used efficiently and cost-effectively. Any schedule gaps are pure waste.

International OperationsA contractor working in a country outside of the one in which it is based (e.g., a U.S. contractor working inWest Africa) faces additional hurdles and challenges. Fortunately, the contractors working in these areas arefamiliar with the additional requirements, and are usually working for a national oil company or an internationalcompany that is familiar with how things are done in the host country. Nonetheless, contractor personnelmobilizing a MODU to drill in a different country are well advised to become familiar with the pertinent laws,regulations, and expectations of the host country.The following listing is for illustration purposes only, to alert contractor personnel to some of the hurdles theymay face when given a foreign assignment. Again, it is incumbent on the contractor to determine the specificrequirements set forth by the host country.

Obtaining the correct identification and entry papers for the host country.With most contractors, personnel will be guided by aunit of the human resources department, which may carry out many of the tasks for them.

Establishing an office (and perhaps a subsidiary company) in the host country. This is a task for lawyers and an experiencedexpatriate. Importing the MODU and all other equipment.Developing nations have large, complex customs bureaucracies with many rules,

requirements, and procedures. Unless the operator client lays the groundwork for the contractor, the contractor personnel will have tomaster this labyrinth and learn to navigate it.

Establishing an onshore support and supply base. Understanding the relevant laws and regulations - such as for safety and environmental protection - and knowing how to

comply with them.

Meeting requirements for local content.In a drilling operation, this will probably be limited to hiring and providing training for aspecified number of native workers, but may also include purchasing provisions from local sources.

Ensuring the availability of adequate support equipment,such as anchor-handling tugs, supply boats, and helicopters. Lack ofequipment with adequate capabilities at a critical time will lead to costly delays.

Understanding the host country culture.More international postings are derailed by an inability to understand and adapt to thelocal culture than by any other cause.

Service Companies and SuppliersA deepwater MODU will have service company equipment and often personnel onboard. For certain services,the basic equipment will be installed permanently aboard the rig. A cabin and winches will be in place for welllogging and wireline services. The drilling fluid supplier may have its own facility onboard. A control cabin andlaunching system will be installed for the dedicated remotely operated vehicle (ROV), which is onboard at alltimes. If the MODU is engaged in development drilling, facilities may be placed onboard to support the work ofvarious companies supplying completion services.When an operator enters a long-term contract for an upgraded or new-build MODU, they typically selectlogging and ROV contractors so that their facilities can be installed during the latter stages of construction.Management of these service providers is usually the responsibility of the company representative aboard the


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rig. The ROV contractor, however, works very closely with the drilling contractors marine personnel and maythus be supervised by one of the marine officers or engineers.Other services may be supplied under long-term contract to a preferred supplier. In development drilling, the oilcompany will probably have worked with one or two suppliers on the design of completion equipment, and willcertainly have contracted with a single supplier for provision of subsea wellheads and production trees. Thiswill also be true for other specialized services, such as cementing casing and formation fracturing if thegeology of the pay zone requires it.

Technology ManagementOffshore drilling, and deepwater drilling in particular, are to a large extent technology-driven. The developmentof new technologies has made it physically possible to drill and produce in progressively greater water depthsand has brought sub-marginal oil and gas resources into the realm of economic viability. This makes itmandatory for oil companies to stay familiar with the leading edge of technology development, which isoccurring more and more these days in the R&D divisions of specialized suppliers and service companiesrather than within the oil companies themselves. It is, of course, often very efficient for an oil company toidentify a problem or new requirement and then work with a drilling contractor and the service industry todevelop the solution.Technology management occurs mostly at several removes from the rig floor among oil company engineeringstaffs and internal consultants. It is one thing, however, to be aware of a new technology and quite another tounderstand when to use it and how to make it cost-effective. This requires systematic efforts, often involvingthe technology suppliers, to communicate new technical information and educate personnel in its relevanceand applications.

Measuring PerformanceThe use of new technology leads directly to the need to measure its performance, as well as the overallperformance of the drilling effort. This is an operators task, although the drilling contractor conducts its ownperformance measurements and supports its operator client. The technology supplier also cooperates in themeasuring and evaluation process.An operator will not adopt a new technology without a rigorous process of testing and qualification. During thisprocess, the operator and supplier develop a standard or set of criteria for measuring performance. These arethen used to evaluate the commercial application. For some equipment or processes, the criteria are obvious:Is it easier to install? Does it make some other operation easier? Is it more reliable? Does it have a longeruseful life or increase mean time between failure? Does it allow us to do something we could not dopreviously? Does it provide information we could not get before?Of course, it is generally easier to measure performance in a controlled laboratory or test facility than it is on aworking drilling rig, where it can be difficult to isolate the contribution of the new technology from the effects ofeverything else that may be going on at the same time. Fortunately, this task has become more manageable in

the years since deepwater drilling first became common, with the advent of such capabilities as Pressure-while-drilling (PWD), which provides information that is useful both for controlling the well during the drillingprocess and evaluating post-drilling performance.Drilling contractor performance is measured continuously as a well is being drilled. Operator and contractormeasure the length of hole drilled each day and compare the result with information about offset wells in thefield or area. The total time that it takes to drill, and perhaps complete, a well is one of the universal standardsfor measuring contractor performance. This is plotted on a simple graph of well depth vs time in days. Fromthis graph the operator and contractor can identify sections of the hole or operations that caused difficultiesand took more time than had been allotted in the schedule (e.g., Did a shallow water flow cost us some time?Or lost circulation due to a weak formation and narrow fracture gradient? Was it unusually difficult to get agood cement job on a section of casing? Did the drillstring become stuck in a particular formation? Was timelost to trouble with some part of the completion? ).A carefully conducted measurement program allows the operator and contractor to identify anomalies andunexpected variations. Equipped with these insights, personnel at all levels can begin analyzing themeasurements to discover the causes of the difficulties.

Measurement and analysis provide the operator and contractor with the information they need to improve theirmethods, processes, equipment and technology and do a better job on the next well. They provide thefeedback needed to progress along the learning curve for a series of development wells. The information canbe used to establish benchmarks and to build a suite of best practices that can be employed on future wells inthe field or area. In deepwater projects, this entire process is generally conducted with a high degree ofcollaboration between the operator, drilling contractor, and suppliers of technologies and equipment.Information may also be shared among operators and with regulatory authorities. Valuable information andlessons learned will go into the knowledge management systems maintained by the operator and contractor sothat they may be available throughout the

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