Masterado EMI.PDF

8/18/2019 Masterado EMI.PDF

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Chapter 18

Offshore Operations

William H. Silcox, Chevron Corp.

James A. Bodine, Chevron Corp.

Gerald E. Burns, Chevron Corp.

Carter B. Reeds,*

Chevron Corp.

Donald L. Wilson, Chevron Corp.

Edward R. Sauve,

Chevron Corp.

Introduction

Offshore petroleum operations emerged in the 20th cen-

tury and brought new dimensions of challenge and ex-

citement to oil exploration and production. When a

structure taller than a lOO-story building is launched from

a barge, or when a small city is built and placed offshore

in 2 years, those involved deserve their feelings of pride

and accomplishment.

In nearly every corner of the globe, thousands of off-

shore installations with payloads from 5 to 50,000 tons

are producing gas and oil today in water depths from 10

to 1,000 ft. Although subjected to winds and waves up

to hurricane intensity, earthquakes, sheet ice, severe tides

and currents, or shifting foundations, surprisingly few

structures have succumbed to the environment despite the

difficulty in predicting environmental forces, equipment

failure, or reservoir behavior.

This chapter can only scratch the surface of offshore

operations; detailed procedures for design and construc-

tion of structures, equipment, and facilities would require

volumes. Furthermore, such volumes would be obsolete

before they were published. Because there is no concise

reference or set of references, this chapter describes the

fundamentals of standard practice in several disciplines

and offers guidance for the selection of appropriate off-

shore codes of practice and technical references.

Historical Review

In 1859, Col. Edwin Drake drilled and completed the first

known oil well near a small town in Pennsylvania. This

well, which was drilled with cable tools, started the

modern petroleum industry. Drilling methods and tools

remained in their infancy for more than 40 years, until

hydraulic rotary drilling techniques were first used to drill

*Droeascd

the Spindletop well in 1901. By then, the petroleum in-

dustry was already moving offshore.

In 1897, near Summerland, CA, H.L. Williams extend-

ed an onshore oil field into the Santa Barbara Channel

by drilling a submarine well from a pier. This first off-

shore well was drilled just 38 years after Col. Drake’s

well. Five years later, more than 150 offshore wells were

producing oil. Production from the California piers con-

tinues even today.

From this start, offshore drilling actually turned inland

with activity in the Great Lakes, Caddo Lake in Louisiana,

and Lake Maracaibo in Venezuela. Initially, wells were

drilled from shore-connected piers and later from wood-

en single-well platforms. During this period of inland off-

shore drilling, platform technology remained basic. The

one step forward was the change from wooden platforms

to concrete structures in Lake Maracaibo.

In the late 1920’s, steel production piers that extended

a quarter of a mile into the ocean at Rincon and Elwood,

CA, were built and new high-producing wells stimulated

exploration activity. In 1932, a small company called In-

dian Petroleum Corp. determined that there was a likely

prospect about 1/2 mile from shore. Instead of building

a monumentally long pier, they decided to build a por-

tion of a pier with steel piles and crossmembers. Adding

a deck and barging in a derrick completed the installa-

tion. By Sept. 1932, the 60x90-ft “steel island” was

completed in 38 ft of water with a 25-ft air gap. This first

open-seas offshore platform supported a standard 122-ft

steel derrick and associated rotary drilling equipment.

Successful drilling with largely unsuccessful results was

carried on intermittently on the “steel island” until 1939,

when the third well was completed on the pump at 40 B/D.

In Jan. 1940, a Pacific storm destroyed the steel island.

During the subsequent cleanup, divers were used for the

first time to remove well casing and to set abandonment

plugs. ’


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PETROLEUM ENGINEERING HANDBOOK

Meanwhile, the first offshore field was discovered in

the Gulf of Mexico in 1938. A well was drilled to 9,000

ft off the coast of Texas in 194 1. With the start of World

War II, however, offshore activities came to a halt. Ac-

tivity did not resume until 1945 when the State of Loui-

siana held its first offshore lease sale.

At the end of the war, surplus Navy ships and barges

became available to the oil industry. At first, Navy land-

ing craft (LST’s) were converted into tenders to support

drilling operations on offshore platforms. By installing

mud systems and electrical generation equipment, and by

storing consumables on the tender, engineers reduced

drilling platform payloads by a factor of 10.

The development of tender-supported platform rigs

pointed the way toward mobile exploratory rigs that could

move on and off location, thereby eliminating the cost of

fixed drilling platforms. During the late 1940’s and early

1950’s, a number of mobile rigs were developed in rapid

succession.

First was the posted barge, which consisted of a sub-

mersible barge with the drilling rig mounted on steel

columns. The barge was sunk on location with the drill-

ing rig clear of the water. Next came the submersible,

with large vertical columns that provided enough buoyan-

cy to transport the drilling rig while floating. These rigs

were sunk on location with the drilling rig and deck re-

maining above water. Finally came the jackup rig. This

rig consisted of a barge hull fitted with vertical legs that

could be jacked down until they contacted the ocean floor,

thus raising the barge, which supported the drilling rig,

clear of the water. While the bottom-supported drilling

rigs were being developed for the shallow waters of the

Gulf of Mexico, floating drilling vessels and techniques

were being developed for offshore California. There,

water depths in excess of 500 ft were found inside the

3-mile limit.

Civil and structural engineers were largely responsi-

ble for the development of submersible and jackup rigs,

but naval architects and marine engineers were called on

to convert military ships for the drilling industry. Me-

chanical engineers from the oil fields designed the spe-

cialized subsea and shipboard drilling equipment.

The first floating drilling vessels were converted mine

sweepers with A-frames over the side for handling pipe

and jet bits. The pipe was jetted into the ocean floor, and

core barrels were dropped through the pipe to get cores

from the bottom of the hole. Next, Navy patrol boats were

converted into drillships with “over-the-side” masts and

rotary tables. The first rotary floating drilling vessel went

into service in 1953 and was capable of drilling in 400

ft of water to depths of 3,000 ft.

The adverse motion characteristics of these ship-shaped

vessels, combined with the “over the side” rotary table,

encouraged offshore drillers and engineers to find ways

to reduce vessel motions. In 1955, innovative drilling en-

gineers moved the drilling rig from over the side to the

center of the ship to reduce the effects of vessel motion.

A center well, or moon pool, was installed vertically

through the hull, and the drilling rig was mounted over

it. This breakthrough led the way to modern-day drilling

vessels. Technological advances in subsea systems, ves-

sel station-keeping systems, moored and dynamic posi-

tioning, motion compensators, control systems, and

navigation systems have all contributed to the success of

drillships during the past 30 years. They will be discussed

in more detail later in this chapter.

While ship-shaped vessels were being developed for

California waters, a different approach to improving ves-

sel stability was taken in Gulf of Mexico waters. The semi-

submersible, or column-stabilized drilling vessel, was

developed by addition of buoyant hulls to a submersible

so that it could drill while floating instead of sitting on

the seafloor. These rigs exhibited superior motion char-

acteristics and now are used extensively in such rough-

water areas as the North Sea and off the east coast of

Canada.

While mobile drilling rigs were being developed into

today’s sophisticated drilling systems, platform technol-

ogy was keeping pace. In 1947, the first platform “out

of sight of land” was built off the coast of Louisiana in

20 ft of water. From then until the 1970’s, the gulf coast

dominated offshore petroleum activity with the installa-

tion of more than 5,000 offshore drilling or drill-

ing/producing structures. During the 1970’s, the North

Sea captured most of the offshore attention with the ad-

vent of huge payload requirements, and concrete gravity

structures competed with the steel “template. ” Eighteen

concrete structures have been installed in water depths

from 240 to 540 ft with payloads up to 40,000 tons.

Meanwhile, steel-structure technology competed suc-

cessfully for smaller payloads in the North Sea and

regained favor as deeper U.S. waters were explored. In

1976, “Hondo,” a pile-supported two-piece jacket, was

installed in 850 ft of water off the coast of California.

In 1978, “Cognac” was installed in three pieces in 1,025

ft of water in the Gulf of Mexico. Single-piece structures

became viable for deeper water as launch barges and trans-

portation technology developed. “Garden Banks” was in-

stalled in one piece in 680 ft of water in the Gulf of Mexico

in 1976. “Cerveza,” in 935 ft, and “Liguera,” in 915

ft, were installed in the gulf in 1981 and 1982. Designs

for steel jackets for up to 1,200 ft of water are in the fi-

nal design stages for placement in the Santa Barbara Chan-

nel and the Gulf of Mexico.

Many other specialty structures have been installed. In

1966, a steel gravity-oil-storage structure was placed in

service in the Gulf of Mexico. Three 500,000-bbl steel

storage domes that resemble inverted champagne glasses

were installed in the Arabian Gulf in 1969, 1971, and

1972. Buoyant articulated columns were installed in the

North Sea in the 1970’s to serve as tanker mooring devices

for loading out crude oil. Tankers and drilling vessels have

been moored by various means to support gas/water/oil

separation facilities and to provide temporary oil storage.

Breast mooring and single-point mooring systems have

been installed in water depths exceeding 100 ft to accom-

modate a supertanker’s draft. A steel gravity structure

with storage capacity of 1 million bbl of oil and a deck

payload of 30,000 tons has been installed in the North

Sea as an alternative to the concrete structures. A guyed

tower was installed in 1,000 ft of water in the Gulf of

Mexico in 1983. A tension-leg platform, the commonly

favored concept for water depths of more than 1,200 ft,

was installed in 485 ft of water in the North Sea in 1984.

Each of these special-purpose structures represents an ad-

vance in ocean engineering technology and forward-

thinking business management to support untried ideas.


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OFFSHORE OPERATIONS 18-3

Progress is not always the result of new ideas or con-cepts but often a step-by-step improvement in existingtechnology. For example, the skirt pile that is currently

part of most steel deepwater structures was first im- plemented in 1955, but the idea had been patented in the19th century. The North Sea gravity structure had a prece-dent in a gravity platform constructed offshore in Califor-nia more than 30 years ago. The guyed tower was patented

before the turn of the century. The tension-leg platformwas invented during World War II as a seadrome or float-ing airport. Current improvements in computerized de-sign, transportation, and installation equipment, coupledwith an ever-increasing need for new oil supplies, is thedriving force for technological advance.

During the evolution of offshore platforms, the newocean engineering discipline also evolved. Ocean engi-neers are versed in structural engineering, soil mechan-ics, the hydrodynamic effects of waves and currents,

structural dynamics, statistical analysis methods, and reliability analysis techniques.

The equipment, methods, and techniques for complet-

ing, producing, and maintaining wells on the ocean floor

have also undergone tremendous advancements since thefirst subsea wells were completed in the late 1950’s. Earlysubsea Christmas trees were made up of the same con-

ventional valves and flanges as trees for land wells. Theone concession to underwater operations was fail-safe

hydraulic actuators on remote-control valves. These ear-ly trees were usually diver-installed and connected by

Bowlines to shore. One company developed a swimming

hydraulic wrench that was fitted with television cameras

and maneuvering thrusters. This system, integrated intothe wellhead system, was successful to a degree. It was

the first attempt to eliminate divers from subsea opera-tions. Over the past 25 years, there has been a continu-

ous effort to reduce dependency on divers, but divers arestill a very important part of the offshore oil industry.

Complex multiwell systems have been installed on theocean floor. Single-well completions have been made in1,300 ft of water. Control systems that involve hydraul-ic. electronic multiplex, and acoustic signal transmissionsystems are now common. Unmanned, remotely operat-ed vehicles now are being developed that will become anintegral part of the subsea completion system. Much has been accomplished in the past 25 years, but with explora-tory drilling being done in 6,500 ft of water, even moreremains to be done in this area of subsea completions.

The search for offshore oil and gas reserves has directedthe petroleum industry to the ice-covered waters of the

Arctic. In 1963, the first commercial oil field was discov-ered in the upper Cook Inlet of Alaska. For the first time,ice driven by extreme tidal currents produced loads onthe production facilities far in excess of other environ-mental forces. By the end of 1968, 14 platforms were

producing oil and gas from the inlet.The onshore oilfield discoveries of Prudhoe Bay in 1968

and Kuparuk in 1969 established the Alaska North Slopeas an oil province. In 1977, construction of the Trans-Alaska Pipeline System was completed, and oil beganflowing directly to the ice-free port of Valdez. This de-velopment has inspired extensive exploration activity inthe Arctic offshore continental shelves of the U.S. andCanada.

Fig. 18.1– Typical floating drilling arrangement.

The industry has constructed 26 sand and gravel islandsfor exploratory drilling in water depths to 100 ft since1972. Several caisson-retaining systems have been im-

plemented to speed construction and to reduce the fill re-quirements for the islands. Beyond 100 ft, drillships have been used, but they operate only during the ice-free sum-mer season. In 1983, a floating conical drilling unit wasdeployed in the Canadian Beaufort Sea. The unit is capable of resisting early winter ice loads, hence extendingthe drilling season to 6 months a year.

At the current time, at least four major Arctic marine projects are in the planning phases: the Arctic Pilot Proj-ect in the Canadian Arctic Islands, the Arctic MarineHydrocarbon Production Project in the Canadian BeaufortSea, the Endicott Development nearshore U.S. BeaufortSea, and the Hibernia Development off the east coast of Canada. Permanent production platforms, subsea pipe-

lines, icebreaking tankers, supply vessels, and evacua-tion systems are a few of the facilities being developed.

In summary, though the offshore industry has come along way since the wooden pier days of Summerland, thetechnological requirements have barely been addressed.

Offshore DrillingThe Introduction brought us quickly from the very earlydays of the oil industry to today’s jackup drilling units,semisubmersibles, and drillships. This section will dis-cuss the planning, preparation, and equipment necessaryto conduct a typical floating drilling operation (see Fig.18.1). Focus will be primarily on floating drilling because

operations from jackups, submersibles, and platformsgenerally follow land drilling practices. The last portionof the section will be devoted to special considerations,such as deepwater and high-current drilling and consid-erations for cold and hostile environmental conditions. For a general discussion of the technology of offshore drill-ing, completion, and production, see Ref. 2.

Planning and Preparations

Site Conditions and Considerations. The culminationof the sometimes arduous and complex task of geologicevaluation of a potential offshore play is for the explora-tion geologist to put a finger on the map and say “drill


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here.” This decision sets in motion a series of actions that

will eventually lead to the drilling of an offshore well.

The first major step is to select a rig to drill the well.

Because all rigs have specific operating criteria and limits,

however, certain data must be known about the drillsite

and surrounding area. Basic rig selection criteria consist

of water depth, expected environmental conditions dur-

ing the forecasted drilling period (wind, waves, current

profile, and climatological conditions), distance from

nearest dock facility, and availability of consumable sup-

plies (such as drilling mud, cement, pipe, rental tools,

and spare parts).

Water Depth.

A rough idea of the water depth is an

important criterion for rig selection. If the water depth

does not exceed approximately 350 ft, any of the three

ma.jor rig types can be considered. Jackups can handle

a water depth range from their shallow draft limit of 20

to 30 ft to a maximum depth of 350 ft. The maximum

depth limitation is a function of other environmental con-

straints, such as wind, wave, and current conditions at

the site. Severe conditions tend to lower the jackup rig’s

maximum water-depth capacity.

Drillship water depths range from approximately 100

to 8,000 ft with today’s technology. The shallow side is

limited by clearance between the bottom of the hull and

the subsea blowout preventer (BOP) equipment. Maxi-

mum water-depth limits occur because of riser-system

limitations and other constraints that will be discussed

later.

Semisubmersible water depths range from approximate-

ly 150 to 8,000 ft. The semisubmersible must stay in

slightly deeper water than a ship because of the clearance

between the submerged hull (60 to 90 ft below the water

surface during normal drilling operations) and the sub-

sea BOP equipment. Until 1978, semisubmersible maxi-

mum water depth was limited by the practical depth of

conventional mooring systems-approximately 2,200 ft.

One dynamically positioned semisubmersible that required

no conventional mooring system, thus extending the de-

sign working depth to 8,000 ft, was commissioned in

1978. Today, several dynamically positioned semisub-

mersibles are under construction or in service.

The industry water-depth record currently stands at

6.848 ft for a well drilled off the U.S. east coast during

the summer 1983.

Expected Envir onmental Conditions. Wind, waves,

and current are all important site-specific data to help in

rig selection and in determination of vessel heading, moor-

ing pattern, mooring line tensions, riser tensions, subsea

equipment selection, and equipment operational limits.

Wind, wave, current, and climatological data are gener-

ally the responsibility of an oceanographic consulting firm

or your own company’s oceanographer. Many sources of

environmental data are available-the marine climatic at-

las, ship observations, U.S. Navy publications. private-

ly funded oceanographic studies, and university-sponsored

research. Converting these data into useful site-specific

wind, wave, and current information is the scientific

specialty of oceanography.

The oceanographer must have specified coordinates of

the location and the time of the year (with some cushion

on both ends) in which operations are expected. With that,

he can develop the expected wind, wave, and current con-

ditions for the location. For an exploratory location, the

oceanographer may provide environmental data for oper-

ational weather, seasonal one-year storm, and seasonal

IO-year storm. With that information, the drilling engi-

neer and technical support staff can accomplish several

tasks necessary in planning the well.

1. A preliminary rig selection can be made based on

water depth, wind, wave, and current information.

2. A preliminary estimate of vessel heading can be

determined. Before a final heading is specified, however,

local knowledge of the area should be considered. Local

conditions-such as swell, tide-generated currents, and

rapidly changing wind directions-frequently can affect

the optimum vessel heading significantly. The primary

objective of optimum vessel heading is to minimize ves-

sel motion (primarily pitch, roll, and heave) while keep-

ing the vessel’s mooring line forces within acceptable

limits and providing a lee side (calm-water side) for sup-

ply and crew boats to tie up.

3. To assist in vessel selection, a vessel motion or

downtime analysis can be run. Computer programs that

compare a particular vessel’s motion characteristics with

the predicted wind and waves are available. The result

indicates vessel motion. The resulting motion can be com-

pared with a previously established set of acceptable oper-

ating limits (by computer analysis or manually) to

determine an approximate downtime to be expected. This

analytical tool is most useful in comparing two rigs for

a particular location.

4. After the vessel is selected, mooring and riser anal-

yses can be run to determine whether the vessel is ade-

quately equipped for the location. In addition, both

mooring and riser operating tensions can be determined.

Both are necessary after the rig arrives on location. Typi-

cally, the mooring system is analyzed with a one-year

seasonal storm to determine what operating tensions

should be pulled on the anchor lines. A IO-year storm

can be analyzed to determine the level of proof test to

pull on each mooring line. With reasonable risk consid-

ered, if each line can withstand a IO-year storm proof test,

normal operations should be safe without the fear of slip-

ping an anchor or breaking a mooring line. Drilling riser

top tensions are developed to minimize ball-joint angles

and riser sag while keeping riser-pipe stresses within ac-

ceptable limits.

For jackup rig evaluation, comparing water depth, cur-

rent, wind, and tides with the maximum recommended

criteria established by the rig designer is extremely im-

portant. In water depths nearing the rig’s maximum capa-

bility, strong current or other environmental factors may

reduce the acceptable water depth.

Soil or foundation competency at the site must be known

for jackup operations also. At an exploratory location with

unknown soil consistency, soil borings generally will be

required before the rig’s arrival on location. They are use-

ful in determining depth of leg penetration and to ensure

that the soil can adequately support the rig.

Logistics Considerations. Logistics must also be con-

sidered in rig selection. Remote locations require substan-

tially more planning and preparation than do locations

adjacent to established bases and supplies. Consideration

must be given to (1) frequency of consumables supply;

(2) distance from supply base (length of boat run); (3)

number of people the rig can accommodate; (4) availa-

bility of spare parts: and (5) shipment delays caused by

customs regulations.


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OFFSHORE OPERATIONS

Floating rigs’ (ships and semisubmersibles) variabledeck-load capacity must be considered and compared with

frequency of consumable supplies required. Ships, as anexample, have much greater variable deck-load capacitythan semisubmersible drilling rigs (15,000 vs. 3,000 tons).If the location is in an extremely rough environment, how-ever, the semisubmersible is more stable in rough seasthan the ship. Trade-offs and compromises are necessary

ingredients in rig selection.Availability of pipe, mud, fuel, water, and other con-

sumables must be carefully determined during the plan-ning effort. Helicopters to transport personnel and light

equipment in routine and emergency situations are a nec-

essary part of most floating drilling operations. Those lo-

cated within a few minutes of the coastline and support bases are sometimes exceptions.

Climatological conditions have a major effect on

helicopter operations. Fog and impaired visibility condi-

tions will ground flight operations and, depending on their

extent, can have a major effect on the resupply of con-

sumables, transportation of crews to and from support

bases, and overall rig operations. Floating ice, low tem- perature, and high currents offer special considerationsthat are discussed at the end of the Offshore Drilling sec-tion of this chapter.

Seismic and Other L ocation Studies. Preparation todrill an exploratory location will include running andevaluating a suite of location surveys. Site surveys gener-ally are run by seismic companies specializing in prespudsite studies. These companies will conduct the surveys,evaluate the data, and prepare formal reports that pre-sent the data that will be useful in selecting the exact lo-cation, in preparing the mooring plan, and in determin-ing how the top hole will be drilled.

For exploratory drilling in federal offshore waters, the

U.S. Mineral Management Service issued a set of guide-lines that require certain surveys to be performed and an-alyzed before it will issue a permit to drill. Theseguidelines cover studies on shallow geological hazards,culture and archaeology, and biology.

The operator or lease holder must cover a minimum prescribed grid of traverse lines in carrying out thesestudies. In addition, certain minimum instrumentation isrequired to be run during the surveys. These include spar-ker, uniboom, sub-bottom profiler, side-scan sonar, andfathometer for surveys of shallow geological hazards. If the drilling equipment is to be on board a floating vessel,no bottom sampling is required. If a bottom-setting jack-up barge is to be used, then a bottom sample or core must

be obtained. Side-scan-sonar, magnetometer, and fathom-eter are required for cultural and archaeological surveys.For biological surveys, box-core samples of hard-bottomareas and ocean-floor photography or TV view of hard- bottom areas are required.

The shallow-hazard surveys are required for all sites.The grid must be at least 8,000 ft on a side, centered onthe proposed location, and surveyed on 1,000-R grid lines.The cultural surveys need to be run only in waters of lessthan 400-ft depth. The biological surveys must be run inareas where endangered species exist or hard-bottom sedi-ments might be disturbed. Navigation and location of thesurvey grid during the water-borne surveys must be ac-curate to within 50± ft.

Fig. 18.2– Jackup rig.

Rig-Selection Considerations

Rig-selection criteria and rig types were discussed brief-ly earlier. In this section, we will discuss the differencesin four rigs that are used for offshore drilling: jackups,submersibles, semisubmersibles, and ships. We will alsoconsider drilling equipment, mooring systems, and proce-dure manuals.

Rig types. Jackup rigs (see Fig. 18.2) consist of barge-

shaped hulls with three or four (sometimes more) struc-tural or tubular legs. Jackups must be towed to locationor loaded on specially built ships for major moves. Shiptransportation of jackups is becoming more frequent asnew special transport vessels become available. Shiptransport is considerably faster for long moves (6 to 8 vs.2 to 3 knots) and much less risky. Loading and offload-ing the jackup requires a calm-water site at both ends of the move. Once the jackup is in its “jacked-up” position,drilling proceeds in a way similar to land or platform op-erations. However, several subtle differences should bementioned.

First, water conditions must be relatively calm— generally less than 6- to 7-ft waves-before the rig can

jack its hull out of the water. Major concerns are impactand lateral loading on the legs just as it comes in contactwith the ocean floor. If the rig is rolling and pitching be-yond specified limits, the jacking operation must be suspended until calmer conditions prevail. The same logicapplies when the rig is jacking down.

Second, once the rig is jacked up to working positionwith a safe air gap between the ocean surface and the un-derside of the hull, primary concerns are lateral loadingon the legs and scouring around the leg mats caused bycurrent. Excessive current can cause troublesome vibra-tion, and scouring can lead to foundation failure. Bothconditions are monitored closely, and corrective actionsare taken when necessary.


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18-6 PETROLEUM ENGINEERING HANDBOOK

Fig. 18.3– Submersible rig

Third, the drilling operation is similar to a land opera-tion after the outer casing is driven or drilled and cementedin place. Surface BOP and conventional drilling equip-ment are used.

Fourth, the casing extending from the ocean floor tothe rig is a structural member and should be analyzed be-fore installation. Wall thickness and strength of the pipeshould be specified (and will vary if a mudline suspen-sion system is used) to ensure that it will withstand the

lateral loads of the current and the axial loads of the sur-face BOP and successive casing strings.

Submersible rigs (see Fig. 18.3) are limited to shallow-water drilling. Once the rig is on location and ballastedto sit on the ocean floor, drilling operations proceed ason a land site. Foundation considerations are as impor-tant here as in jackup operations. Logistics and supplyconsiderations are common to all offshore operations, so

jackups and submersibles can be just as severely hampered by fog and bad weather as floating drilling rigs.

Semisubmersible rigs (see Fig. 18.4) evolved from sub-mersibles. Some semisubmersibles can operate when rest-ing on the ocean floor or in their normal semisubmerged

Fig. 18.4– Semisubmersible rig


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OFFSHORE OPERATIONS 18-7

Fig. 18.5– Drillships. Fig. 18.6– Vessel-motion terminology.

position. The major advantage of a semisubmersible isthat it provides a stable floating drilling platform. Roll, pitch, and heave are minimized because minimum struc-ture is exposed to the water plane. The rig’s main disad-vantage is that variable deck-load capacity is limited byits reserve buoyancy or the amount of watertight volumeabove the water line. A semisubmersible with four 50-ft-diameter columns breaking the water plane displaces about62 tons of seawater for each foot of displacement of thecolumn. An equivalent 400-ft-long by 60-ft-wide ship displaces 756 tons for each foot of hull displacement. Be-cause semisubmersibles are sensitive to variations in deck load, they are outfitted with extensive ballasting systemsthat are capable of shifting ballast rapidly to maintain proper trim and of deballasting or ballasting as cargo isloaded or offloaded. The semisubmersible is highlyregarded as the year-round drilling vessel for the open-sea environment because it is very stable in pitch, roll,and heave.

3

Drillships (see Fig. 18.5) are noted for their mobilityand high storage capacity. Drillships have a definite ad-vantage over semisubmersibles because of their size andspeed. Most drillships are designed to pass through themajor canals of the world, thereby substantially reduc-ing the distance between oceans. The distance from theGulf of Mexico to the U.S. west coast by the way of thePanama Canal is 4,500 miles. The distance around SouthAmerica to the U.S. west coast (the route a semisubmer-sible must travel because it is too large to pass throughthe Panama Canal) is 15,000 miles. The cost of movingthe ship to the west coast is generally much less than thatof moving a semisubmersible because of time savings (lessday rate) and distance savings (less fuel). Ships general-ly can travel at a higher speed than a semisubmersible(12 to 13 vs. 8 to 9 knots) for even more time savings.As pointed out in the semisubmersible discussion, thedrillship can carry a much larger variable deck load, whichoffers the advantage of less frequent resupply.

The very nature of drillships (long, narrow hulls withlarge water planes), however, dictates their sensitivity tosea conditions in pitch, roll, and heave. Operations can

be carried out with minimum weather downtime, how-ever, by working drillships in protected waters at seasonswhen conditions are best for open-sea drilling. Clearly,the biggest disadvantage of a drillship working in severeenvironments is its motion characteristics, especially in pitch, roll, and heave.

3

Motion Characteristics. To compare the advantage of one drilling vessel over another, their relative motioncharacteristics must be considered carefully. Vessel mo-tions for ships and semisubmersibles can be analyzed bydetermining the rig’s response in the six degrees of free-dom (pitch, roll, heave, yaw, surge, and sway) relativeto the uniform waves (see Fig. 18.6). All vessels shouldhave a set of motion-response curves. The curves gener-ally are obtained for each rig configuration in a model

basin. Each hull shape has a unique set of curves. Rolland heave generally control the limiting operation. Withcurves like those shown in Figs. 18.7 and 18.8, vesselmotion in roll and heave can be determined for a particu-

lar set of wave data representing the drilling period. Oceanwaves represent a spectrum of wave heights and wave periods. Computer programs are available to calculatevessel motion by entering wave data and the rig’s motioncurves. The result will be a motion history of that partic-ular rig for a specific drilling period.

Performance Evaluation. The next step is to comparethe performance of the two rigs. One performance yard-stick is the weather-related downtime the rigs will suffer under the same environmental conditions. Downtime anal-ysis can be particularly useful when comparing availabledrilling vessels for a one-well project or a complete drill-ing program. While one vessel may appear to be more


8/52

18-8


20

.

Fig. 18.7-Vessel response-roll.

economical because it has a lower day rate, it may cost

more to complete the job because of weather-related

downtime.

The key to weather-related downtime is identifying the

maximum limit in degrees of roll, feet of heave, degrees

of pitch, etc., that can be tolerated during each discrete

operation of floating drilling. The maximum level may

be based on equipment operating limits, safety consider-

ations, work efficiency, potential for damage, or other

factors. Although such a limit is seldom concise, it can

be a fair comparison to evaluate relative rig performance.

Implementing an operating limit by shutting down an op-

eration on the rig is completely a judgment call with many

variables to be considered on the spot. Each rig should

have its own set of operating limits established from ex-

perience with the rig or from experience of the rig oper-

ating personnel. Table 18.1 is an example of limiting

vessel motions for most floating drilling operations.

With the appropriate operating limits, the percent of

the time each applies, and the rig’s motion history,

weather-related downtime can be calculated. A number

of papers have been published on downtime analysis. Var-

ious techniques (both manual and computer-aided analy-

ses) can be applied to calculate weather-related

downtime. 4

TABLE l l-DRILLING VESSEL OPERATING LIMITS

Heave

Limit

Operation ft m

--

Anchoring, running riser,

landing BOP

6 1.8

Running casing, coring,

well testing

IO 3.0

Drilling, tripping, logging

12

3.6

Circulate and condition mud

20 6.1

Time

Criterion

Roll Applied

Limit

Per Well

(deg.)

(04

3

10

3

40

6

30

10

20

Fig. l 8-Vessel response-heave

An additional item normally not included in the motion-

related operating limits is wind. High winds frequently

result in shutdown because the rig crane cannot safely han-

dle casing or riser. This is a valid input to the rig’s over-

all performance and should be included in the final

downtime comparison. Occurrences other than severe

weather also cause operating downtime. Equipment break-

down and repair downtime (sometimes the result of se-

vere weather, but not always) must be determined from

experience and operating history with a particular rig or

company. This increment of downtime is unpredictable

and difficult to estimate.

Mooring Systems Stationkeeping). Once the engineers

are satisfied that a particular rig or group of rigs is capa-

ble of handling the environment of a specified offshore

location, other equipment systems must be evaluated and

compared.

Mooring equipment provided to keep the rig on loca-

tion is of major significance. Major questions to be an-

swered regarding mooring equipment include the

following: (1) is the mooring line (chain, wire, or a com-

bination of chain and wire) strong enough to withstand

the loads during the strongest anticipated storm; (2) does

the rig have sufficient wire or chain on board or availa-

ble for the water depth at the specified location; (3) do

the anchor handling or supply boats that are being con-

sidered have adequate pennant-wire-handling equipment

on board (lengths must be greater than the water depth

and sufficiently strong to handle the 30- to 40-ton anchors

and can approach 2.5 to 3 in. diameter); (4) does the ves-

sel have adequate instrumentation to monitor mooring-

line loads; and (5) does the rig have adequate chain-locker

capacity to hold the desired amount of chain, or must part

or all of the chain be stored on supply boats? (Vessels

that don’t carry their own chain have greater in-transit

deck-load capability but normally will require longer to

moor up because of the additional chain-handling re-

quirements.)


9/52

OFFSHORE OPERATIONS

18-9

_I VESSEL

OFFSET

1, /

,- ZERO ANGLE

Fig. 18.9-Optimum vessel position.

These questions must be answered to specify an ade-

quate mooring system properly. Mooring analysis, which

is necessary to answer several of the questions, will be

discussed later in this section.

Adequate stationkeeping (keeping the vessel within ac-

ceptable limits on the location) is a result of a properly

designed and operated mooring system. Why is station-

keeping important? Ideally, the vessel should be located

directly over the well. However, wind and current forces

can cause the vessel to take an offset downstream from

the wellhead location. Waves cause the vessel to oscil-

late around that offset position.

the top of the BOP can cause rapid and excessive wear

‘:&

”

if the angular offset exceeds 1 to 2” for an extended length

of time; (3) excessive vessel offset can cause increased*.

riser sag, compounding both the ball-joint offset and the

wear problems. Proper monitoring of the ball-joint angle

and adjustment of the mooring system will result in a ves-

sel offset upstream of the current and wind that will

minimize the lower ball-joint angle. Optimum vessel offset

would yield a zero ball-joint angle (see Fig. 18.9).

There are many variations in mooring patterns. Differ-

ently shaped vessels will require different mooring pat-

terns (see Fig. 18.10).

It is important to keep the vessel reasonably close to

One criterion in mooring-system design is that the

the wellhead position for several reasons: (1) the subsea

restoring forces should be able to withstand nearly the

drilling equipment can accommodate angular offsets of

same storm conditions from any direction.5 The moor-

up to lo”, but beyond that the equipment mechanically

ing pattern is designed to fit the vessel and particular en-

locks up; (2) drillpipe that is rotating in the ball joint at

vironmental conditions anticipated at the site.

A\

400

A

\

>

c

3

d AJ

SYMMETRIC NINE LINE

SYMMETRIC TEN LINE

30”-70” EIGHT LINE

SYMMETRIC EIGHT LINE

44

45O-90° EIGHT LINE

45”-90“ TEN LINE

30°-60” EIGHT LINE

Fig. 18.10-Typical spread mooring patterns,

4.:


10/52

18-10


r-@---i

VESSEL

VESSEL

I f

- 9f

f

I

/’

LEGEND

WATER LINE

-

I

--

@ HORZONTAL FORCE AT VESSEL.

0

TOTAL VESSEL MOVEMENT FROM ZERO

I’

HORlZONTAL LOAD TO SPECIFIED

HORZONTAL LOAD.

ANCHOR

LINE , ,’

@ TOTALhNE REMAINING ON BOTTOM

@ @

/’

@ ANGLE OF LINE FROM HORIZONTAL

AT ANCHOR.

/

/

/

BL /

0

VERTlCAL FORCE ON ANCHOR.

/

/

/

0

ANGLE OF ,.,NE FROM HORIZONTAL

D

/

AT VESSEL

\

NOTE’ D B E AREZERO UNTIL C

ANCHOR

BECOMES ZERO

Fig. 18.11-Typical catenary configuration.

The restoring forces are generated by the niboring line.

Environmental loads acting on a vessel displace it horizon-

tally until an equal and opposite horizontal force (restor-

ing force) is developed by the anchor and mooring lines.

As the vessel is displaced, tension in the anchor line in-

creases because of additional line being lifted off the ocean

floor and because the vertical component of a&nor line

tension, which increases as line is lified off-bottom, is af-

fected by the angle in the anchopline at the vessel (see

Fig. 18.11).

.

Vertical or uplifting [orces on the anchor are zero as.

long as line-remains on botto

proFrly designed and

operated mooring system sho

ways have line remain-

ing on bottom during maximum storm conditions. If all

the line comes off-bottom,+the chances of dislodging an

anchor are high.

W&h a spread mooring system, vessel excursion in

moderate weathei conditions can be restricted to 2 to 3 7%

of water depth by‘pulling initial operating tensions in each

line. Fig. 18.12 shows the nonlinear behavior ofborizon-

tal force (horizontal component of line tension) and ves-

sel disphcement for a typical spread mooring. If the vessel

_ _

9 ,

i

I

1

i’

._-,_--;

0 10 . 20 30

40

50

DISPLACEMENT, FT.

NOTE: KS1 = PSI X 1000

Fig. 18.12-Single-line catenary horizontal force vs. horizontal

displacement.

had two opposing mooring lines and could pull tension

on each line initially, vessel displacement could be greatly

reduced for the same environmental loads because the line

would operate in a much “stiffer” region of its horizon-

tal force vs. displacement curve.

/

Initial operating tension, however, does affect the max-

imum line tension that will be required in maximum storm

weather. The same environmental loads on the vessel are

produced during maximum storm weather regardless of

the value of initial operating tension. This force must be

balanced by one or more mooring lines. This restoring

force is in addition to most of the horizontal components

of the initial tension in the line. The vessel will probably

not be displaced enough to reduce the initial tension in

the leeward lines completely. In actual operations, lee-

ward lines can be slacked off during maximum storm

weather to reduce maximum line tension and vessel off-

set. In general, the higher the initial tension, the higher

the maximum line tension during maximum storm condi-

tions. Too little initial tension

,pwever, will result in un-

acceptable vessel offset during operating weather

conditions. Table 18.2 identifies desirable stationkeeping

criteria.

Dynamic positioning is another method of stationkeep-

ing where no mooring lines are used. These systems re-

quire acoustic positioning beacons, multiple thrusters on

the vessel’, and an on-board computer system and are

primarily for deepwater drilling. Dynamic positioning will

be discussed briefly in the last section, Special Consider-

ations.

Drilling-Equipment Considerations. Rig-selection con-

siderations should include a review of the vessel’s drill-

ing equipment. Much of the drilling equipment found on

board floating drilling vessels is identical or similar to

equipment on land drilling rigs. This discussion will be

limited to equipment unique to floating drilling.

Fig. 18.13 identifies the major components of the sub-

sea drilling system and related shipboard ,systems. The

figtire sho& some of the components of the drilling sys-

tem’that have been developed to accommodate vessel mo-

tion and water ‘depth. The components to be explained


11/52

OFFSHORE OPERATIONS

18-11

TABLE 18.2-DESIRABLE CRITERIA OF STATIONKEEPING

Operational:

Minimal weather

Maximum vessel excursion

Nonoperational, But Riser-Connected:

Maximum weather condition

Maximum line tension

Minimum line remaining on bottom

Maximum vess%l excursion

Riser-Disconnected:

Weather conditions

Maximum line tension

Minimum line remaining on bottom

are the BOP, the flex joint, riser, riser slip joint, riser

and guideline tensioners, drillstring motion compensator,

guidelines, and control system.

BOP. The subsea BOP stack is a major change from

land or platform drilling operations. Drilling riser, ex-

tended kill and choke lines, remote hydraulic and elec-

trohydraulic control systems, and subsea wellhead

equipment are all product modifications needed because

the BOP was relocated on the ocean floor. The well’s

major pressure-containing components were put on the

ocean floor because of the need to compensate for vessel

motion.

A BOP stack, whether located on the surface or sub-

sea, is considered a last resort for preventing a well kick

from becoming a blowout. Several steps are taken to con-

trol unusual well conditions before use of the well shut-

in device (BOP). If the previous steps have failed and it

becomes necessary to shut the well in, the shut-in equip-

ment must be highly reliable. BOP equipment is designed

with reliability as its ultimate criterion. Because of its rela-

tive inaccessibility, the subsea BOP requires additional

redundancy and reliability.

The BOP stack is a combination of individual BOP’s

designed to shut in a well under pressure so that forma-

tion fluids that have mov&l into the wellbore can be cir-

culated out while continuous control of the well is

maintained.

A description of the BOP stack components is included

below (see Fig. 18.14).

Rum Preventers. The massive steel rams have rubber

seals, and are hydraulically actuated to seal off the well-

bore. Pipe rams seal the annulus around the drillpipe and

are designed so that an entire string of drillpipe and col-

lars can be suspended from a pipe joint landed on a ram.

The ram seals must be the correct size to seal; 3-in. seals

cannot be used for 5-in. drillpipe. Conventionally, three

pipe rams are used. A fourth ram, a blind-shear ram, is

used to seal over the open hole and to shear drillpipe when

necessary: Shearing pipe is, of course, one of the last

resorts in an emergency situation. 5 Variable-bore rams

are an option that is offered$or tapered drillstrings.

Annular Preventers. Annular preventers are comprised 9

of specially designed, reinforced rubber elements that can

seal around any tubular or near-tubular objects that &ill

go through the BOP’s. They will also seal over the open

hole and can pass drillpipe tool joints without severely

Drilling operations can be carried out

That which results in ~3~ lower

ball-joint angle, generally

2 to 3% of water depth

Seasonal l-year storm

% breaking strength

500 ft

That which results in ~5~ lower

ball-joint angle, generally

5 to 6% of water depth

Seasonal 1O-year storm

I/Z breaking strength

100 ft

GUIDE LINE

TENSIONER -

4 EA TYP

4. 6, OR 6 EA TYP

TOP FLEX JOINT

c STORAGE REEL

TO KILL 8 CHOKE

FLEXIBLE HOSE

a

CONDUCTOR CASING

SURFACE CASING

l

Fig. 18.13-Floating drilling system.


12/52

18-12 PETROLEUM ENGINEERING HANDBOOK

in addition to the spring or fail-safe close feature. Twovalves in each line should always be used for redundan-cy. They should be located as close to the stack as possible for mechanical protection.

5

Unitized BOP Stuck. The unitized BOP stack that con-sists of two hydraulic connectors, three or four ram

preventers, one or two annular preventers, four K&Cvalves, one flex joint, and a control system is generally

handled in one or two pieces on board the rig. The complete assembly can weigh f rom 200,000 to 400,000 lbmand stand 25 to 30 ft high.

3

Handling and moving the BOP stack from its storage position to the moonpool and back presents unique prob-lems. Generally, either special overhead cranes or hydrau-lically actuated carts are used to move the stacks.

BOP maintenance is extremely important. The only timeavailable for routine maintenance is between locations.On short field moves, this can present problems. LandBOP systems are frequently broken down and sent to theshop for maintenance between wells, but that is virtuallyimpossible to do without causing major delays on a float-ing drilling rig. A few rigs are equipped with backup BOP

stacks to minimize the chance of major delay.BOP testing is done in two steps. The stack must be

completely function-tested (each of the 30 to 40 hydraul-ic functions actuated to verify that each works) before run-ning. It must also be completely pressure-tested beforeit leaves the deck. Each pressure-containing component(rams, annulars, and K&C valves) must be tested to a

pressure specified by the operator. API RP 53 on BOP’s6

identifies testing procedures as a minimum safe guideline.After the BOP has been run and latched on to the subseawellhead, it must again be pressure-tested. Following procedures defined by regulatory agencies, periodic func-tion and pressure-testing must be done on the BOP equip-ment during the course of a well. A complete deck and

subsea BOP testing checklist simplifies frequent testingrequirements.F lex Joints.

3A flex joint is installed between the lower

end of the riser and the BOP stack. This joint essentiallyacts as a pinned connection to minimize bending stressesin the riser as the drilling vessel is moved by wind, wave,and current action.

The first flex joints were made from bag-type annular BOP’s fitted over a mandrel flanged to the top of the BOPstack. The rubber element in the preventer was inflatedagainst the mandrel to a pressure high enough to keepdrilling fluid in the riser from leaking past it. This typeof flex joint, which was not positively locked to the BOP,worked fine in shallow waters (200 ft or less) where ten-

sion was not pulled on the riser.The next flex joints were the pressure-balanced ball joints. These joints came into existence when operationsmoved into deeper waters and it became necessary to pulltension in the riser through the ball joint into the BOPitself. With this positive pull upward on the ball joint, itwas necessary to provide a pressurized oil pad betweenthe male and female halves of the ball joint to minimizewear. Pressurized oil was provided through a line fromthe surface and was contained between upper and lower O-ring seals within the ball joint. The balancing pressureon the ball joint was determined by dividing the tension pulled through the ball joint by the projected horizontalarea between the ball-joint seals.

Fig. 18.14– BOP stack

damaging the sealing element. Annular preventers are ac-tuated by an annular piston that squeezes the seal into the

bore. The piston area is large relative to the other func-tions on the stack and, except for initial closure, should be operated at pressures lower than the other stack func-tions. This decreases the possi bility of extruding the rubber seal out of the preventer.

5Frequently, two annular

preventers are used. One normally will be located abovethe upper hydraulic connector so that it can be retrievedwith the riser.

Hydraulic Connectors.3Hydraulic connectors provide

the main pressure seal between the wellhead housing andthe BOP and between the top of the BOP and the lower marine riser package (LMRP–usually contains the topannular preventer, flex joint, control system, and cross-over to the bottom riser joint). The high-pressure well-

head housing is the male portion of the connector. It will be a mandrel or a hub type. The connector is the female portion and consists of a series of hydraulic cylinders thatactuate locking dogs into grooves machined into the well-head housing or collet fingers that clamp over the well-head housing hub. Both types of connectors use metal-ringseals. This provides continuous metal-to-metal sealing upthrough the BOP.

Kill-and-Choke Valves. These valves are the subseashutoff of the high-pressure kill and choke (K&C) linesthat run from the BOP’s to the choke manifold on the rig.K&C valves are hydraulically controlled from the sur-face and are designed to close by spring action when open-ing pressure is released. Some valves close hydraulically


13/52

OFFSHORE OPERATIONS

Steel-laminated elastomers now are replacing ball joints

as riser flex joints. These joints are longer-lived and re-

quire less maintenance than the pressurized ball joints.

They also eliminate the need for the pressure source and

hydraulic lines.

Some operators also require the installation of a flex

joint between the upper end of the riser and the slip joint.

Pressurized ball joints and elastomeric joints have been

used successfully in this application. Most flex joints are

designed for an angular travel of f 10” for a total included

angle of 20”.

SZip Joints. 3 All floating drilling vessels, ship-shaped

or semisubmersible, heave up and down as swells go by.

A slip joint is the link between the riser fastened to the

bottom of the ocean and the heaving drilling vessel. The

slip joint, similar in action to a trombone, consists of an

inner and an outer barrel. The outer barrel is connected

to the riser and the inner barrel to the ship. As the ship

heaves up and down, the inner barrel strokes in and out

of the outer barrel. A pair of inflatable rubber elements

mounted on the upper end of the outer barrel serve as the

seal between the barrels to prevent loss of drilling fluid.

The second seal is for redundancy.

Riser Tensioner. For a drilling riser to survive, two

things must happen.3 First, the drilling vessel must be

kept within prescribed limits as it moves about in surge

and sway. Second, the riser must be tensioned properly

so that it will not sag and ultimately be overstressed in

bending.

The controlling criterion is not vessel position relative

to the well on the ocean floor, but the angle between the

axis of the lower end of the riser and the vertical axis of

the BOP stack. This angle is called the lower riser angle.

During drilling, this angle should be kept at less than 3”.

A greater angle will cause the rotating drillpipe to cut into

the flex joint and BOP stack. In extreme cases, lost cir-

culation has resulted from a worn-through flex joint. In

normal drilling, the riser angle is kept to less than lo.

If it exceeds 3”, drilling is stopped until the vessel can

be repositioned.

To keep the lower riser angle as near 0” as possible

in areas where ocean current is a factor, the drilling ves-

sel may have to be located up-current from the well.

If the drilling vessel is located up-current, as shown in

Fig. 18.9, but inadequate tension is pulled on the riser,

the riser could sag, as denoted by the dotted line. If the

drilling vessel is moving about and there is heavy drill-

ing fluid in the riser, the angle at the flex joint could ex-

ceed 10” and put bending stresses in the riser. If this

situation is not corrected, the riser ultimately will fail.

Hydropneumatic tensioning units were developed to

keep constant tension pulled on the riser. Determination

of the tension required is a complex problem in which

water depth, riser size, mud weight, ocean current, ves-

sel motion, and sea conditions must be considered. A

number of computer programs, both time and frequency

domain, have been developed to determine the tension

needed. Many oil companies that operate offshore have

their own riser programs or have access to them. These

programs give the riser tension required and the desired

vessel offset.

The tensioner system works on the principle that dis-

placement of a relatively small amount of hydraulic fluid

against a large pressurized volume of air results in a very

18-13

Fig. 18.15-Riser tensioner unit.

small change in the hydraulic pressure. Variation in ten-

sion on the riser can be kept to less than 5% by proper

design.

The tensioning unit (see Fig. 18.15) consists of a ser-

ies of large air storage tanks that are connected to the air

or gas side of an accumulator that serves as the interface

between the air and hydraulic systems. The tensioner is

a cylinder/piston arrangement that has wire-rope sheaves

mounted on the lower end of the cylinder and on the up-

per end of the piston rod that extends out of the cylinder.

A wire rope that is dead-ended on a storage reel is reeved

through the sheaves over alignment sheaves and is attached

to the outer barrel of the slip joint. As the drilling vessel

heaves up, it pulls on the line, which pulls the piston into

the cylinder, displacing fluid into the accumulator against

the large volume of air. The air is precharged to give the

desired tension. Similarly, when the vessel moves down,

the gas pressure displaces hydraulic fluid against the

piston, extending the piston rod and maintaining a con-

stant pull on the riser.

Guideline tensioning systems, developed to keep con-

stant tension in the guidelines, operate in much the same

manner as the riser tensioners. The only difference is that

they are smaller because less tension is required on the

guidelines.

Drillstring Motion Compensators.

Without drillstring

motion compensation, 3 the drill bit would be constantly

lifting off and banging down into the bottom of the hole

as the drilling vessel heaves up and down. Weight con-

trol on the bit under these conditions without some type

of motion compensation is next to impossible. Bumper

subs (trombone-type slip joints) in the drillstring above

the drill collars were used initially to provide some relief

from vessel motion. However, with bumper subs, once

the drillstring was in the hole, the weight on the bit (WOB)

(weight of the drill collars) was fixed and could be changed


14/52

18-14


tor. When the vessel heaves down, the piston is forced

up by the pressurized hydraulic fluid from the accumula-

tor. The gas side of the accumulator is connected to large-

volume gas bottles. The small volume of fluid displaced

by the piston against the large volume of gas gives a low

compression ratio. This means that there is very little

change in the gas pressure and the hydraulic pressure, re-

sulting in an almost constant WOB.

At the start of drilling, the gas pressure is adjusted so

that it will barely support the weight of the drillstring.

WOB is increased simply by reducing the gas pressure.

This transfers weight from the drillstring motion compen-

sator to the bit. As a hole is made, the blocks are lowered

to keep the compensator at midstroke of the piston. To

reduce the WOB, the gas pressure is increased. Large air

bottles are kept charged with high-pressure air for this

purpose.

Re-Entry Systems. Re-entering a 3-ft-diameter hole in

the ocean floor in shallow waters without too much cur-

rent, say less than half a knot, isn’t too difficult. 3 If that

same hole is put under half a mile of water in an area

with l- to 2-knot currents, the problem obviously is more

difficult.

Almost from the beginning of floating drilling, wire-

rope guidelines have been used to guide drillstrings,

Fig. 18.18-Drillstring motion compensator

only by pulling the drilling assembly and changing the

number of drill collars. Another disadvantage was that

the early bumper subs were not hydraulically balanced.

Mud pressure in the drillstring that was higher than the

external pressure in the drillpipe/hole annulus, as when

jet bits are used, caused the bumper subs to “pump” open

and to become as stiff as the drillpipe, making them in-

effective.

Balanced bumper subs that have the internal pressure

routed to both sides of the stroking member were invent-

ed to solve this problem. These solved one problem and

created another. When working in sandy drilling fluids,

the balanced bumper subs’ seals wore out after relatively

short runs, making it necessary to come out of the hole

with “green” bits to replace the worn-out, leaking subs.

Because of their short lives, the worn-out bumper subs

were repaired on board, which required an inventory of

spare parts and personnel trained in their repair.

These considerations led to development of drillstring

motion compensators (see Fig. 18.16). These hydropneu-

matic units are installed either between the traveling blocks

and the hook or in the crown block at the top of the der-

rick. These units have been successful for both drilling-

bit weight control and running and landing heavy subsea

equipment (such as 400,000-lbm BOP stacks). They are

common on most drilling vessels today.

Drillstring motion compensators are similar to riser ten-

sioners in the way they function-i.e., a small volume of

hydraulic fluid is displaced against a large volume of pres-

surized gas. The weight of the drillstring is supported on

a vertical piston inside a cylinder that is connected to the

rig blocks. The piston is supported by pressurized hydraul-

ic fluid between the piston and cylinder. As the vessel

heaves up, the piston is pulled down into the cylinder,

displacing hydraulic fluid into a gas-charged accumula-

casing, BOP stacks, and riser pipe into or onto subsea

wells. In most instances, the guidelines are anchored to

the ocean floor by the temporary guidebase. In some

cases, when the hole for the structural pile is spudded

without a temporary guidebase, the mud pumps were run

at full capacity as the bit entered the ocean bottom. This

washed a large conical hole in the ocean floor that, with

luck, could be re-entered without guidelines. However,

under these conditions, when the structural casing and the

permanent guidebase are run, the guidelines are attached

to the permanent guidebase for subsequent re-entry op-

erations.

With the advent of dynamically positioned drillships,

guidelineless re-entry systems were developed. These sys-

tems still had temporary and permanent guidebases; how-

ever, instead of using guidelines and guideposts, they were

fitted with guidecones that provided a large target for the

tools or casing being run. TV cameras were run through

the drillpipe, casing, riser, or BOP stack (depending on

what was being run) to provide guidance into the hole or

back onto the BOP stack. Combinations of TV and sonar

also have been used for re-entry guidance. With the

dynamic-positioning system, the driller can take control

of the drilling vessel from his station and position it as

required for re-entry . Re-entry by means of these systems

has been made in waters as deep as 6,800 ft.

Marine Risers.

The first floating-drilling systems did

not use marine risers for mud returns. 3 Hoses that were

connected below a rotating packer mounted on top of the

BOP stack brought mud returns back to the drilling ves-

sel. The rotating packers, which sealed around the drill-

pipe, were very short-lived and allowed drilling fluid to

leak into the ocean when they failed. It was the failure

of rotating packers that led to development of today’s ma-

rine risers.

As may be seen in Fig. 8.14, the marine riser extends

from the BOP stack on the ocean floor up to the drilling

vessel. The marine riser, in the parlance of land drilling,

is just a very long pitcher nipple. In addition to serving


15/52

OFFSHORE OPERATIONS

18-15

as a pitcher nipple or mud-return conduit, the marine riser

serves another useful purpose: it guides the drillstring

through the BOP’s and into the hole being drilled in the

ocean floor.

The riser joints can be ordered in any length desired,

but the length normally is determined by the geometry

of the drillship. Normal riser joints are 50 ft long, and

at least one riser made of 75-ft joints is in service.

In the beginning, riser couplings were simply threaded

collars. Cross threading of couplings being made up on

a moving vessel led to the development of clamp-type cou-

plings, piloted union-type couplings, and finally the radi-

ally driven dog-and-groove couplings. Riser couplings

now being developed for waters in excess of 7,000 ft are

of a piloted-bolted type.

As drilling entered deeper waters and drilling vessels

ran out of space to install more and more riser tension-

ers, it became necessary to reduce the weight of the riser

by adding buoyancy material. Syntactic foam was used

first. Later, air cans were installed around the riser joints

to make them air buoyant. Both types of buoyancy are

now in everyday use. The cost of the dense syntactic foam

that is required for deeper waters is offset by the cost of

high-pressure air compressors for air-buoyancy risers.

Air-buoyant risers do have one advantage over the foam

riser package: the air in the buoyancy cans can be dumped

so that the riser will plumb bob vertically below the drill-

ing vessel and not tend to drift off with the current.

For ultradeep waters (deeper than about 10,000 ft), free-

standing risers are visualized. Work done in conjunction

with the Natl. Science Foundation’s proposed Advanced

Ocean Drilling Program indicates that to provide the

means for rapid disconnect of the drilling vessel from the

well, it will be necessary to establish a disconnect point

in the riser at about 1,000 ft below the ocean surface. To

support the riser vertically below the disconnect point after

a disconnect, IO-ft-diameter buoyancy cans will be fitted

to an appropriate number of riser joints. The disconnect

point will include shear rams to cut the drillpipe if an

emergency disconnect becomes necessary. This intermedi-

ate disconnect point is essential because it is estimated

that pulling 10,000 ft of riser could take from 7 to 10 days,

well outside our weather-forecasting capability.

K C Systems. On land rigs, the K&C outlets3 on the

BOP stack are plugged directly into the K&C manifolds

on the rig floor. In floating drilling, where the BOP’s may

be from several hundred to several thousand feet below

the rig floor, K&C lines must be provided to bridge the

water depth.

In the early days in relatively shallow waters, high-

pressure hoses were connected to the BOP stack and, as

the stack was lowered, were paid off hose reels. When

the stack was landed on the wellhead, the hoses were con-

nected to the K&C manifolds. As water depths became

greater, the hose reels became too large for convenient

use, and another way to bridge the water depth had to

be found. This was done first by installing guide funnels

at about 15-ft intervals along the length of the riser as it

was run. These funnels were lined up with receptacles

immediately above the K&C valves on the BOP stack.

With the riser in place, screwed-pipe K&C lines were run

down through the guide funnels and stabbed into the recep-

tacles on the stack. Their upper ends were connected into

the K&C manifolds.

This system, while functionally satisfactory, was time-

consuming to run and test, so another method was devel-

oped. This method was to make the K&C lines integral

with the riser. The tops of the K&C joints were fitted with

a female seal pocket filled with chevron packing, and the

lower end fitted with a male seal nipple. When the riser

was run, the seal nipples dropped vertically into the fe-

male seal assembly. No rotation or screwing was required.

The joints were held together by the riser couplings.

Some manufacturers of flexible high-pressure pipe now

are proposing to provide long K&C lines that would be

stored on reels and paid out with the BOP stack when it

is run down to the ocean floor. On the larger vessels now

in service, there is space for the large hose reels required.

Control Systems. The simplest way to operate an actu-

ator in a hydraulic control system is to connect hydraulic

lines from a pressure source through control valves direct-

ly to the actuator. 3 Some actuators require two lines to

complete the control cycle; others, such as spring-return

fail-safe actuators, require only one line.

Subsea BOP’s were controlled this way during the start

of floating drilling. An early stack consisting of a hydrau-

lically actuated connector top and bottom, K&C valves,

four ram preventers, an annular preventer, and a pressure-

balanced ball joint would require as many as 17 control

hoses. These hoses, bundled together, were stored on a

large hose reel. All hoses first were connected directly

to their function on the stack, then pressure- and function-

tested before the stack was run. Improperly tagged hoses

led to many hours of troubleshooting to get the stack to

work properly. This time-consuming job had to be done

each time the stack was run.

Eventually, male and female multifunction stab plates

were developed that reduced some of the hookup time,

but the same problem of larger hose reels in deeper waters

resulted. In addition, as BOP’s became more complex,

as many as 30 to 40 hoses were included in the hose bun-

dles, doubling and tripling their size. To solve the prob-

lem of large hose reels, multihose bundles, and their

slower actuator response times in deeper waters, two new

types of control systems were developed: the piloted all-

hydraulic control system and the direct-wired electro-

hydraulic control system.

Backup Control Systems. In spite of the best-laid plans

and even with two control pods providing 100% redun-

dancy, problems or failures still occur in the most modern

control systems. It is desirable to have reliable backup

systems if the primary controls fail. This has led to de-

velopment of two types of backup control systems: the

acoustic control system and the last-chance hydraulic stab

system. 3

The acoustic backup system uses acoustic signals

through the water as the control link between the drilling

vessel and the BOP stack on the ocean floor. Energy to

power the acoustic signal receiver and to position con-

trol valves is provided by dry-cell batteries. Hydraulic

energy to power selected functions on the BOP stack

comes from accumulators mounted on the BOP stack.

These accumulators are kept charged because they are part

of the normal control system. Typical functions are to

close shear rams, to close pipe rams, and to disconnect

the riser at the lower marine-riser package.

An acoustic transmitter located on a surface vessel,

drilling vessel, work boat, or other vessel is used to send


16/52

18-16

MSSEL

CHARACTERISTICS

PRIVARY SSEL

KIIRING INE

LOCATIIX?

CHARACTERISTICS BATtM?3RY

I I

HORIZOifIALORCE KIRIZONIALISPlAC'd%V

rl

WEtiTtER

DATA

4

KORING REW:+t3.UATlON:

V,

,IU,;W Xl f'D3RINGINE O DC 3Y

,:i,T,,?iFEUTING TtUSlON

,PRCUF R lEJ7 EXiON

Fig. 18.17-Mooring analysis method.

a signal that is coded for the desired function, down to

the receiver on the BOP stack. This signal is interpreted

and the proper control valve is actuated, directing hydraul-

ic fluid from the accumulators to the desired function.

Acoustic backup systems now are installed on most deep-

water drillships. Solid-propellant gas generators also have

been tested successfully as backup subsea energy sources.

The last-chance hydraulic stab system provides the

means for actuating several selected functions when all

else has failed. A hydraulic stab that is ported to accom-

modate the desired functions is run down to the BOP stack

on drillpipe. It may be guided down guidelines or direct-

ed by sonar or TV. Hydraulic hoses are connected to the

stab and are run in with the drillpipe as the stab is lo-

wered down to the receptacle on the stack. Once the stab

is in place, control is accomplished by pressuring up the

appropriate hydraulic line. The stab also can retrieve the

lower-marine-riser package or the complete BOP stack

in the event of a failed riser. The stab receptacle is con-

nected with shear bolts to a mounting plate on the lower-

marine-riser package. The receptacle also is attached to

the lower-marine-riser package with a heavy wire-rope

bridle. The stab contains a connector that, when lowered

into the receptacle, latches the stab to the receptacle. To

retrieve the lower-marine-riser package, for example, the

stab is run in on drillpipe and is stabbed and latched into

the receptacle. After the lower-marine-riser-package dis-

connect is actuated, the drillpipe is picked up, the shear

bolts sheared, and the load transferred to the wire-rope

bridle. The piece then is recovered by pulling the drillpipe.

Extended- Water-Depth Capabili ty. Occasionally, a

drilling vessel is considered that has a maximum-water-

depth capability just short of the wellsite water depth

(1,300-ft water depth with a 1 OOO-ft capacity rig as an

example). To ensure that the rig is adequate for the loca-

tion,

consider

additional riser availability and storage

space; additional riser tension (or added buoyancy);

lengthened control hoses and TV cable; additional guide-

line length; mooring system adequacy (mooring lines and


pennant wire); size of control hose reels (large enough

to hold additional hose; ease of installing larger ones);

size of guideline winch drums (large enough to handle

additional line); and substructure strength (enough to sup-

port the added tension requirement).

Generally, the added water depth can be accommodat-

ed,

but

each rig and each site should be considered

separately.

Operating Manuals and Emergency Procedures

Rig selection considerations should include a review of

each drilling vessel’s operations manual and emergency

procedures plan. The operations manual will include drill-

ing operations and equipment-handling procedures. Nor-

mal operating limits for discrete drilling operations will

be specified. The emergency procedures plan should cover

detailed responses and courses of action to be followed

during marine emergencies, well emergencies, and bad

weather situations. Disconnect and hang-off procedures

must be identified, and special equipment should be on

board to accomplish the suspension under adverse condi-

tions. An agreement on well-control procedures should

be reached between the drilling contractor and the oil com-

pany personnel. The drilling contractor personnel will im-

plement the procedure, so if it is different from their

previous procedures, additional training should be con-

ducted.

Mooring and Riser Analyses

Mooring Analysis. Mooring systems and the objectives

of station-keeping have been discussed briefly. The con-

cept of the catenary and horizontal restoring force were

mentioned. Combining these forces with the wellsite water

depth, physical description of the rig’s mooring equip-

ment, and environmental data is the task of a mooring

analysis. Several commercial computer programs are

available to perform mooring analysis. Some companies

have developed their own programs. Mooring-analysis

methods are documented in numerous articles and papers.

Two are referenced at the end of the Floating Drilling

section. In addition, API RP 2P discusses mooring

analyses. ’

Fig. 18.17 describes the basic procedure followed in

mooring analysis. Combining vessel characteristics and

mooring-equipment specifics with bathymetry and weather

data yields the length of mooring line to deploy, the ini-

tial operating tension, and the proof or test tension. The

results can be obtained for a number of mooring config-

urations to determine which is optimum or simply to verify

a recommended configuration.

Riser Analysis.

Marine or drilling risers were described

earlier. Accurate performance of drilling risers can be

determined only by analysis. In floating drilling opera-

tions, the riser behaves as a string. It gains all of its struc-

tural integrity from tension. The single most important

parameter in operation of the system, therefore, is riser

top tension. Insufficient top tension can result in opera-

tional problems associated with large ball-joint angles and,

if low enough, buckling of the riser pipe body. Overten-

sioning, however, produces high stresses in the riser that

can result in a shortening of its life because of fatigue

cracking. For each combination of environmental condi-

tions, mud weight, riser weight,

and vessel offset, there

is an optimum range of riser top tension.


17/52

OFFSHORE OPERATIONS

18-17

Commercial programs are available to do riser analy-

sis. As with mooring analysis, some companies have de-

veloped their own programs. API RP 2Q addresses riser

design* and API RP 2K discusses riser use and main-

tenance. 9 Papers written on riser-analysis procedures are

referenced at the end of the Floating Drilling section. The

following discussion covers riser-analysis criteria and

operational considerations, but not details of the complex

analysis.

The items considered in riser analysis are riser stress,

ball-joint angle, top tension, riser top angle, tensioner line

angle, sheave friction, and riser pipe collapse.

Riser Pipe Stress. Static and dynamic stresses in riser

pipe are calculated by the riser-analysis program. Static

loads are caused by the riser weight, mud weight, current-

induced hydrodynamic forces, the applied top tension, and

deflection of the top of the riser. Deflection of the top

of the riser is caused by vessel offset. Dynamic loads re-

sult from wave-induced water-particle motion and vessel

surge/sway motion. Wave-induced surge/sway motion

produces dynamic riser deflections and hydrodynamic

forces because of the relative motion of the riser and the

water.

The criteria for acceptable static and dynamic stress lev-

els is shown in Fig. 18.18. For purely static loads (no

dynamic load applied), stresses up to 50% of the pipe-

material yield strength are allowed for normal operations

and stresses up to 67% of yield strength for limited or

emergency operations. These allowable stresses have fac-

tors of safety of 2.0 and 1.5, respectively. For purely dy-

namic stresses, the allowables have been reduced to 25 %

of the pipe-material yield strength and 25 % of the pipe-

material ultimate strength because of fatigue considera-

tions. Combined static and dynamic stress states must fall

within the recommended range indicated on the graph.

High stresses occur in the pipe-to-connector weld and at

the base of the groove in the connector pin. These two

areas should be inspected frequently.

Bull Joint Angle. To minimize wear by the drillpipe,

the angle of approach of the riser to the BOP stack should

be kept as small as possible. Problems are minimized if

this angle is maintained to less than lo--a goal readily

attainable in a mild environment. With moderate to se-

vere environments, establishing an allowable ball-joint an-

gle of 3” is a compromise between wear problems and

the application of criteria too restrictive to permit eco-

nomical drilling operations.

The lower ball-joint angle is affected by many varia-

bles. Of these, rig personnel can readily adjust only riser

top tension and vessel position. The rig’s riser-angle in-

dicator should be monitored continuously and the vessel

position and/or riser tension adjusted accordingly. Chang-

ing the vessel location relative to the wellhead is the best

method of minimizing ball-joint angle. The lower ball-

joint (flex-joint) angle is the most important operating

criterion to maintain.

Top Tension. For long-term operations, it is not desir-

able to work riser-tensioner systems at more than about

75 % of their rated capacity. To do so will result in prema-

ture failure, generally in the tensioner lines. Tension re-

quirements can be reduced by the use of buoyancy.

Sufficient tension/buoyancy should be specified to pre-

vent drastic consequences should one tensioner fail. Af-

ter ball-joint angle, this criterion is the most restrictive

Fig. 18.18-Recommended stress ranges.

on tension requirements. When operating at the recom-

mended tension, failure of one tensioner should not cause

increases in ball-joint angle past 3’) and stress should re-

main in the recommended range for normal operations

(see Fig. 18.18).

Minimum operating tension should always be sufficient

for emergency disconnect. An overpull at the lower-

marine-riser package connector of about 50,000 lbf is rec-

ommended to ensure that the lower-marine-riser package

and riser will retract sufficiently to clear the top of the

BOP.

Increasing riser top tension within the specified range

can reduce bottom ball-joint angle. Increased tension be-

yond the maximum recommended, however, will signif-

icantly increase pipe stresses and have very little effect

on decreasing ball-joint angle. At that point, the vessel

must be moved to correct excessive ball-joint angle.

Riser Top Angl e. Although the lower ball-joint angle

is the most cri

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