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36 Oilfield Review

High Expectations from Deepwater Wells

Guy Carré

Emmanuel Pradié

TotalFinaElf Angola

Luanda, Angola

Alan Christie

Laurent Delabroy

Billy Greeson

Graham WatsonHouston, Texas, USA

Darryl Fett

Jose Piedras

TotalFinaElf E&P USA, Inc.

Houston, Texas

Roger Jenkins

David Schmidt

Murphy Sabah Oil Co. Ltd.

Kuala Lumpur, Malaysia

Eric Kolstad

Anadarko Petroleum

The Woodlands, Texas

Greg Stimatz

Graham Taylor

Marathon Oil Company

Houston, Texas

After more than two decades of activity, the daunting task of producing hydrocarbons

from deepwater accumulations has become somewhat demystified. Advances that

make deepwater production possible spring from both pure innovation and modifica-

tion of technology applied in other operating environments. Technical advances and

collaboration between operating companies, service companies and regulatory agen-

cies also help otherwise uneconomic projects to succeed.

The great challenge of producing hydrocarbons

from deepwater environments begins with iden-

tifying viable prospects. Geoscientists and

engineers have built an enviable record of suc-

cesses in deepwater exploration. Similarly, the

drilling community can point to its own techno-

logical developments for deepwater drilling.1 The

final test before beginning production lies incompleting deepwater wells, and there, too, the

petroleum industry is making tremendous strides.

How deep is deep? While various definitions

exist, many operators define deep water as

greater than 500 m [1640 ft] deep, and ultradeep

water as more than 2000 m [6562 ft] deep

(next page).2 The US Minerals Management

Service (MMS), which manages mineral

resources on the outer continental shelf, consid-

ers water more than 1000 ft [305 m] to be deep. 3

While the water depth alone presents signif-

icant operational challenges, operators also must

cope with additional downhole problems such asshallow-water or gas flows, heavy oil, hydrates,

paraffin-rich oil, and asphaltene deposition dur-

ing drilling, completion and production.4 These

difficulties are alleviated somewhat by gains in

seismic quality, improvements in well-logging

and well-testing technology, and advances and

experience in drilling, drilling fluids—including

cement—and well-completion technology.5

In this article, we examine a state-of-the-art

deepwater development in the Gulf of Mexico.

We also introduce new technologies for deepwa-

ter cementing and evaluate their usefulness in

the deep waters offshore USA, Malaysia and

West Africa.

Deepwater Completions

in the Gulf of Mexico

The earliest “deepwater” operations occurred in

the Gulf of Mexico (GOM), Brazil and West Africa

in the late 1970s.6 In the Gulf of Mexico, there

are now more than 150 discoveries in water

depths exceeding 1000 ft, of which 12 are in

more than 6000 ft [1829 m] of water.7 Three

of these deepest fields are included in the

Canyon Express project, operated by TotalFinaElf

E&P USA, which also operates the pipeline sys-

tem, Marathon Oil Company and BP withpartners Nippon Oil Exploration USA and Pioneer

Natural Resources.

Located 150 miles [241 km] southeast of New

Orleans, Louisiana, USA, the Canyon Express

fields now comprise nine wells. There are four

wells in the Aconcagua field operated by



For help in preparation of this article, thanks toRaafat Abbas and Trevor Munk, Clamart, France;Frederic Barde and Jean Lassus-Dessus, TotalFinaElfAngola, Luanda, Angola; Leo Burdylo, Mary Jo Caliandro,James Garner, Roger Keese and Duncan Newlands,Sugar Land, Texas, USA; Cameron, Houston, Texas; TimCurington, Rosharon, Texas; Graham Farr, Thomas Fiskaa,Matima Ratanapinyowong and Paulo Rubinstein, Houston,

Texas; Ayman Hamam, Cairo, Egypt; Knut Hansen,Bottesford, England; Dominic Ong, Kuala Lumpur, Malaysia;Mathieu Pasteris, Luanda, Angola; Charlie Vise, NewOrleans, Louisiana, USA; and Paul Weeditz, Marathon OilCompany, Houston, Texas.

AFIV (annular-controlled FIV system), CemCADE,Commander, DataFRAC, DeepCEM, DeepCRETE, DeepSeaEXPRES, DeepSTIM, FIV (Formation Isolation Valve),FlexSTONE, GASBLOK, LiteCRETE, MUDPUSH, QUANTUM,S.A.F.E. (Slapper-Actuated Firing Equipment), SenTREE,

Winter 2002/2003 37

TotalFinaElf, two in the Camden Hills field ofMarathon, and three in BP’s King’s Peak field.

First production from the Canyon Express project

occurred in September 2002. Produced fluids

from the three fields travel 56 miles [90 km]

through a dual-pipeline system to the CanyonStation platform in Block 261 of the Main Pass

planning area. Williams Energy operates this pro-

duction platform.

Before agreeing to a shared gathering system, the operating companies examined othe

options, such as spars and other stand-alone

facilities. The difficulty of subsea operations and

the reserve sizes made it uneconomic to develop

1. For a review of deepwater well construction: Cuvillier G,Edwards S, Johnson G, Plumb D, Sayers C, Denyer G,

Mendonça JE, Theuveny B and Vise C: “SolvingDeepwater Well-Construction Problems,” Oilfield Review 12, no. 1 (Spring 2000): 2–17.

2. Shirley K: “Global Depths Have Great Potential,” AAPG Explorer 23, no. 10 (October 2002): 16, 17 and 35.

3. http://www.gomr.mms.gov/homepg/offshore/deepwatr/deepover.html

4. For more on gas hydrates: Collett T, Lewis R andUchida T: “Growing Interest in Gas Hydrates,” Oilfield Review 12, no. 2 (Summer 2000): 42–57.

> Major deepwater hydrocarbon provinces (red).

For more on shallow-water flows: Alsos T, Eide A,Astratti D, Pickering S, Benabentos M, Dutta N,Mallick S, Schultz G, den Boer L, Livingstone M,Nickel M, Sønneland L, Schlaf J, Schoepfer P,Sigismondi M, Soldo JC and Strønen LK: “SeismicApplications Throughout the Life of the Reservoir,”Oilfield Review 14, no. 2 (Summer 2002): 48–65.

5. For more on subsea completions: Christie A, Kishino A,Cromb J, Hensley R, Kent E, McBeath B, Stewart H,Vidal A and Koot L: “Subsea Solutions,” Oilfield Review 11, no. 4 (Winter 1999/2000): 2–19.

6. Shirley, reference 2.

7. Approximately 50 of these discoveries were producinghydrocarbons as of 2002. For more information: Baud RDPeterson RH, Richardson GE, French LS, Regg J,Montgomery T, Williams TS, Doyle C and Dorner M:“Deepwater Gulf of Mexico 2002: America’s ExpandingFrontier,” OCS Report MMS 2002-021, April 2002.

STIMPAC, USI (UltraSonic Imager) and WELLCLEAN II aremarks of Schlumberger. AllFRAC is a mark of ExxonMobil;

this technology is licensed exclusively to Schlumberger.TXI is a mark of Texas Industries, Inc. WellDynamics is amark of PES Inc.



these fields independently. The subsea infras-

tructure for the Canyon Express wells is tied to a

subsea, multiphase gathering system (left).8 The

Canyon Express partners agreed to a number of

cooperative operating principles, but the most

important is that no reservoir assumes the reser-

voir-performance risks of the other reservoirs.9

Well-completion technology is a key aspect

of maximizing production from deepwater fields.

Completion techniques and procedures generally

are similar regardless of the water depth.

However, at greater depths, the technology

choices are more limited. For example, as water

depth goes beyond 6000 ft, the only system-

design option is a subsea wellhead system with

wet trees.

A wet tree is a subsea production system

(below left). Designed for deepwater wells, these

advanced systems typically are fitted with pres-

sure and temperature sensors, flow-control

valves and facilities for hydrate inhibition, and

all components are optimized to avoid well-

intervention operations. The well-interventioncosts for the deepest subsea wells, those with

wet trees, are so great that the wells are

designed with the expectation that physical

intervention will not occur. Dry trees, in contrast,

are similar to conventional completions for plat-

form wells. They are designed to produce to

compliant towers, spars and tension-leg plat-

forms (TLPs), from which well-intervention

operations are simpler and less expensive.10

Production risers, which are used for fixed off-

shore structures such as TLPs, are not an option

beyond about 4500-ft [1372-m] water depth.

Instead, flowlines are used to transmit producedfluids to production and testing facilities. All the

control valves for wet trees are subsea, and pro-

duction from the Canyon Express fields goes

through a flowline to production facilities.

There are significant difficulties in placing

production equipment on the seabed: deep

canyons, salt diapirs and potentially unstable

seabed surfaces. Cost and efficiency also are

major concerns. Well-completion operations

from a dynamically positioned drillship in more

than 7000 ft [2134 m] of water cost as much

as US$17,000 per hour and require the coordina-

tion of as many as 200 people from severalcompanies on location.11 The specific require-

ments for completion of each distinct reservoir

zone add another level of complexity to deep-

water projects.

Faced with these many problems, Marathon

Oil Company and TotalFinaElf E&P USA created a

joint project team, known as the Wells Integrated

Project Team (WIPT), to develop procedures,

38 Oilfield Review

> Canyon Express subsea infrastructure. Yellow cubes indicate subsea wells. The dual pipelines areshown in red, and the electrohydraulic umbilical that ties the platform to the fields is represented by

the yellow line. Flowlines transport produced gas 56 miles [90 km] to the Canyon Station platform.

> Subsea tree for Aconcagua and Camden Hills wells. These trees provide a horizontal rather thana vertical production path, simplifying well-completion operations. Weighing 102,000 lbm [46,266 kg],

they are strong enough to withstand ultradeepwater conditions, such as high hydrostatic pressure,and the operational demands during the entire productive life of the fields. (Illustrations courtesyof Cameron.)



Winter 2002/2003 39

procure equipment and plan well-completion

operations.12 The team began its work in October

2000; well completions were carried out from

January to September 2002.

The well completions for Aconcagua and

Camden Hills fields use similar techniques and

technology to link the reservoirs to production

facilities. Safe, rapid, interventionless and trouble-

free reserve depletion is the goal, with all

completion systems tailored to individual reser-

voirs. The two main requirements for the

completions are to provide sand control and

downhole flow control to deal with potential

water breakthrough in each producing zone. This

well-completion equipment also allows con-

trolled and measured production from each zone,

maximizing recovery.

Well-completion designs incorporated

state-of-the-art fracture stimulation and gravel

packing for long, heterogeneous reservoir inter-

vals, sand-control systems and subsea well-control

systems (right). The wells also contain flow-con-

trol valves and permanent gauges.13

Although theinitial investment in the completion equipment

and installation was more than US$20 million per

well, the project team also considered the poten-

tial cost of remedial well-intervention

operations—in this case, well intervention

would cost approximately US$10 million per

operation. Given the magnitude of these costs,

remotely controlled downhole equipment is

a cost-effective alternative to expensive, risky

interventions (see “Advances in Well and

Reservoir Surveillance,” page 14 ).

Well-completion operations for the

Aconcagua and Camden Hills wells were con-ducted from the Transocean Discoverer Spirit , a

dynamically positioned drillship. To optimize rig

time, completion operations were designed to

take advantage of the advanced pipe-handling

capabilities of the dual-derrick system. During

the completion operations, a pipeline-laying ves-

sel, a drillship and a vessel for a remotely

operated vehicle (ROV) were active in the area,

requiring careful coordination and vigilance by all

work crews.

8. For more on reservoir simulations used in production-facilities decisions: Wallace BK and Gudimetla R:“Canyon Express Field Performance Simulation,” paperOTC 13131, presented at the 2001 Offshore TechnologyConference, Houston, Texas, USA, April 30–May 3, 2001.

9. For more about Canyon Express operating principles:Clarke D, Allen M and Rijkens F: “Canyon Express—A Deepwater Affair in the Gulf of Mexico,” presented at

the Deep Offshore Technology International Conference,New Orleans, Louisiana, USA, November 6–9, 2000.

Tubing hanger

Methanol-injectionmandrel

TRC-DH-10-LOsafety valve

Chemical-injectionmandrel

Packer-setting device

Splice sub

Production packer

Upper flow-control valve

Lower flow-control valve

Landing nipple

Wireline reentry guide

7-in. shroud

Landing nipple forlower zone isolation

3 1 ⁄ 2-in. isolation tubing

QUANTUM isolation packer

Production-seal assembly

AFIV device

QUANTUM X packer

Mechanical FIV device

2 7 ⁄ 8-in. tubing withcarbide blast rings

AllFRAC screen

Shifting tool

Gauge carrier withthree pressure andtemperature sensors

Cross-nipple for upperzone isolation

Packer-settingmechanical override

9 5 ⁄ 8 -in. liner top

4 1 ⁄ 2 -in. productiontubing

QUANTUM X packer

Hydraulic/mechanicalFIV device

AllFRAC screen

Sump packer

Upperinterval

9 5 ⁄ 8 -in.linertop

Lower

interval

> Typical Camden Hills completion, Canyon Express development. The sumppacker, lower sand-control assembly, upper sand-control assembly andisolation assembly were installed in four separate runs. The upper comple-

tion equipment, from the production-seal assembly up, was installed ina single operation.

10. Cromb JR III: “Managing Deepwater Risks and Chal-lenges,” Oilfield Review 11, no. 4 (Winter 1999/2000): i.

11. Antosh N: “Go Deep Takes New Meaning,” The Houston Chronicle 102, no. 11 (October 24, 2002): 1B and 4B.

12. BP independently completed its wells in King’s Peakfield. Production from King’s Peak field, added to thatfrom Aconcagua and Camden Hills fields, yielded suffi-cient hydrocarbons to justify the Canyon Express project.

13. For more on the downhole flow-control equipment andpressure gauges: Jackson Nielsen VB, Piedras J,Stimatz GP and Webb TR: “Aconcagua, Camden Hills,and King’s Peak Fields, Gulf of Mexico Employ IntelligenCompletion Technology in Unique Field DevelopmentScenario,” paper SPE 71675, presented at the SPEAnnual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 30–October 3, 2001



Well-completion designs and procedures for

the six wells in the Aconcagua and Camden Hills

fields were similar. As the operations team

gained experience, the time required to complete

a well decreased (right).

First, the horizontal subsea tree was run and

tested immediately prior to completion opera-

tions. The drillship had two rotary tables; the tree

was run from the aft rotary while the marine

drilling riser with the blowout preventer (BOP)

was run on the forward rotary table.14 After the

subsea tree, the drilling riser and the interven-

tion and workover control-system were run, the

tree was tested. Completion-equipment installa-

tion began after the subsea BOP stack was run

and latched.

After the BOP stack was tested, the temporary

abandonment plugs were drilled out, and the well

was cleaned out by displacing drilling mud with

seawater and then calcium chloride [CaCl2] com-

pletion brine. Afterward, displacement pills,

casing scrapers, brushes and jetting tools were

used to minimize residual wellbore debris.15

Wireline was used to set the sump packer near

the bottom of the well to provide depth control for

subsequent perforating and sand-control opera-

tions. The upper and lower sand reservoirs were

then perforated using tubing-conveyed perforating

equipment and completed in a stacked frac-pack

configuration for commingled production.

Perforating operations for one of the Canyon

Express wells used S.A.F.E. Slapper-Actuated

Firing Equipment perforating technology instead

of electric detonators or packer-setting tool

igniters, which cannot be used while radios,

welders and other rig equipment are in use.16 Theexploding foil initiator of the S.A.F.E. system

requires higher currents than ordinary detonators

or igniters, so stray voltages are not a concern.

Using the S.A.F.E. system saves rig time during

perforating operations because radio silence is

not required; operations such as welding can

continue without interruption. The zones were

perforated slightly overbalanced; any perforation

damage would be overcome by fracturing opera-

tions that would extend beyond the damaged

zone. The FIV Formation Isolation Valve device,

described later, and a packer plug isolated the

lower zone during perforating and sand-controloperations in the upper zone.

The upper zone was gravel packed because of

a nearby water zone; the lower zone had a frac

pack. The zones were isolated after sand-control

operations to prevent fluid loss and fluid influx.

Innovative FIV technology was used with the

QUANTUM X packer, part of the QUANTUM

gravel-pack packer family, and STIMPAC fractur-

ing/gravel-packing service for sand control.

These remotely operated valves are activated by

pressure rather than physical intervention with

slickline; as a contingency, they can be opened

using slickline or coiled tubing. They isolate

zones completed separately to eliminate poten-

tial fluid-loss problems and formation damage.

When the fracturing service tool was pulled, the

FIV ball was shifted closed mechanically, provid-

ing positive shutoff in case of fluid loss or

reservoir influx during completion operations.

40 Oilfield Review

> Improved completion performance. The Wells Integrated Project Team calculated the time fromdrillship arrival on location to demobilization to be 40 days (pink curve with squares). Except for theMississippi Canyon Block 305 #2 well, which was temporarily abandoned for sidetrack drilling, thewells in Aconcagua and Camden Hills were completed in 39 days or less, with one well, MC305 #1,requiring only 24 days to complete.



Winter 2002/2003 4

Packers are downhole devices used in almost

every completion to isolate the annulus from the

production conduit and anchor the conduit in the

casing, enabling controlled production, injection

or treatment. The QUANTUM X packer is a ver-

satile, rugged packer designed for sand-control

completions, such as gravel packing, and high-

pressure, high-volume stimulation treatments. In

this case, STIMPAC services combined fracturing

and gravel packing in a single operation. This

frac-pack technique breaks through the formation

damage and minimizes productivity impairment

that is common in conventional cased-hole gravel

packs.17 This stimulation operation was executed

by the DeepSTIM I and DeepSTIM II offshore

stimulation vessels. The DeepSTIM vessels pro-

vide large-capacity treatments and high-rate,

high-pressure pumping, fracturing, acidizing or

gravel packing for remote or deepwater locations.

Following the final sand-control treatment, an

isolation-packer assembly was run on the work

string to establish the proper flow paths for sub-

sequent production. Fluids from the lower sandflow up the tubing path, and the upper sand is pro-

duced up the annulus between the isolation tubing

and the sand-control screen. The isolation assem-

bly also incorporated AFIV annular-controlled FIV

system technology to provide well control and

prevent fluid loss in the upper flow path.

The designs of the sandface completions dif-

fered somewhat because Marathon and

TotalFinaElf have different philosophies. For

example, TotalFinaElf used the DataFRAC frac-

ture data determination service before the job to

optimize the design of the fracturing operation.

TotalFinaElf selected specific wire-wrappedscreens with shunt tubes to optimize the frac-

pack jobs in long and deviated intervals, to

maximize productivity and to minimize the skin

effect. Marathon selected prepacked screens to

optimize sand control. The risk involved in the

lower completions was significant—several dis-

tinct operations were required to install each

component, any of which could damage the pay

zone if performed incorrectly. Once installed,

however, both completion designs provided an

effective and reliable foundation for the installa-

tion of the complicated upper completion.

The upper completion assembly was installedas a single unit, which could have been retrieved

if necessary. Nevertheless, running the upper

completion presented significant risks and

challenges. This equipment included a pro-

duction-seal assembly that locates and stings

into the isolation-packer assembly. The

WellDynamics Intelligent Well Completion

System (IWCS) equipment was run above the

seal assembly. The IWCS includes two flow-

control valves, which allow selective control of

each completed interval. The IWCS also includes

pressure and temperature gauges and a hydrauli-

cally set production packer.

A chemical-injection system for scale treat-

ment and surface-controlled subsurface safety

valves (SCSSVs) also were run in the Canyon

Express wells (see “At the Ready: Subsurface

Safety Valves,” page 52 ).18 Seabed temperatures

of 38°F [3°C] and the potential for gas hydrates

necessitated a methanol-injection system to

inhibit hydrate formation in the flowlines.

Another system at the wellheads minimizes pro-

duction problems caused by changes in the state

of hydrocarbon liquids, such as paraffin precipita-

tion. Nine control lines are used to operate the

various downhole systems.

The SCSSV was a tubing-retrievable, nitro-

gen-charged valve that incorporates dual,

redundant hydraulic operating systems. The

SCSSV was set deep enough to avoid hydrateformation, approximately 2500 ft [762 m] below

the seabed.19 A methanol-injection mandrel

installed just above the SCSSV offers further pro-

tection from hydrate formation. Production tubing

was run from this mandrel to the subsea tubing

hanger. The tubing-hanger running tool, operated

by the SenTREE 7 subsea well control system,

was latched to the tubing hanger.

The SenTREE 7 system provides shut-in, dis-

connect and well-control capability during well

cleanup and testing, and the system shuts off

flow from the well and can be removed safely in

15 seconds.20 This sophisticated, deepwater testtree was electrohydraulically controlled with a

small, multifunctional umbilical clamped to the

landing string. During completion installation,

the SenTREE 7 control system allowed the

SCSSV and IWCS equipment to function before

landing the tubing hanger. The Commander con-

trol system for subsea well control managed and

monitored the test tree and completion through-

out the operations.

A special riser-sealing mandrel was run in the

landing string to protect the umbilicals when

closing the diverter packer in case gas entered

the drilling riser above the BOP stack. The riser-sealing mandrel was positioned to accommodate

heave of the drilling vessel, downward motion

caused by loss of station keeping, and emer-

gency unlatching of the SenTREE 7 system.

Packer fluid was circulated into the wellbore

prior to setting the production packer. The pro-

duction packer was hydraulically set after the

tubing hanger was landed, locked and tested

The downhole isolation valves—FIV and AFIV

devices—were opened by applying a predeter

mined number of pressure cycles on the

production tubing. The AFIV device provides

zonal control for the upper zone; the FIV device

provides reliable fluid control before running the

production string.

The flow-control valves were configured to

produce the lower interval for cleanup and eval

uation. Produced gas and condensate were flared

throughout the flowback period, and samples o

each were captured at surface. Recovered stimu

lation fluids were stored either for flaring with

produced gas or for subsequent transfer to shore

for disposal. To eliminate the risk of hydrate for

mation and the mechanical risk of running

wireline, there was no downhole sampling.

The upper interval was flowed for cleanup

and evaluation in a similar manner. A short tes

of the commingled intervals confirmed that the

IWCS equipment functioned properly. The wel

was shut in at surface; the SCSSV was closedand fluid in the tubing above the SCSSV was dis

placed by methanol. The tubing-hanger crown

plug was run on wireline, and the SenTREE 7 uni

was unlatched and pulled.

14. A drilling riser is a large-diameter pipe that connects thesubsea BOP stack to a floating surface rig to take mudreturns to the surface. Without the riser, the mud wouldsimply spill out of the top of the BOP stack onto theseafloor. The riser might be loosely considered a tempo-rary extension of the wellbore to the surface.

15. A pill is any relatively small quantity—usually less than200 bbl [32 m3]—of a special blend of drilling fluid toaccomplish a specific task that the regular drilling fluidcannot perform. Examples include high-viscosity pills

to help lift cuttings out of a vertical wellbore, freshwater

pills to dissolve encroaching salt formations, pipe-freeing pills to destroy filter cake and relieve differentialsticking forces, and lost-circulation material pills to pluga thief zone.

16. For more on perforating technology: Behrmann L,Brooks JE, Farrant S, Fayard A, Venkitaraman A, Brown AMichel C, Noordemeer A, Smith P and Underdown D:“Perforating Practices That Optimize Productivity,”Oilfield Review 12, no. 1 (Spring 2000): 52–74.

17. For more on frac packing: Ali S, Norman D, Wagner D,Ayoub J, Desroches J, Morales H, Price P, Shepherd D,Toffanin E, Troncoso J and White S: “CombinedStimulation and Sand Control,” Oilfield Review 14, no. 2(Summer 2002): 30–47.

18. A safety valve is a device installed in a wellbore to pro-vide emergency closure of the producing conduits. Two

types of subsurface safety valve are available: surface-controlled and subsurface-controlled. In each type, the

safety-valve system is designed to be fail-safe, so that the wellbore is isolated in the event of any system failuror damage to the surface production-control facilities.

19. For more on the record-setting safety-valve installationin the Gulf of Mexico: Christie A and McCalvin D: “KeyComponents to Conquer the Deep,” Hart’s Deepwater Technology (August 2002): 37–38.

20. For more on the SenTREE 7 system: Christie et al,reference 5.



A wireline plug was preinstalled in the inter-

nal tree cap on surface, which was then run on

the work string using a mechanical running tool.

The mechanical running tool is operated by clos-

ing the appropriate set of pipe rams and applying

pressure down the choke or kill lines.

Finally, fluid from the well was unloaded to the

rig for production testing and cleanup. The tree

then was secured with a tubing-hanger wireline

plug and internal tree cap. The BOP stack, riser

and intervention and workover control-system

umbilical were disconnected, and the rig was

moved to the next well in the completion program.At the end of this project, Marathon and all

Camden Hills service providers conducted a

lengthy evaluation, and the many lessons learned

and ideas for improvement were captured

to enhance future completion operations.

TotalFinaElf held similar meetings with

Schlumberger to review each Aconcagua com-

pletion. The dual-activity rig added flexibility and

saved many days of rig time because the aft

rotary table was used to perform offline pressure

testing, equipment preparation and equipment

makeup prior to the use of the equipment in

activities on the forward rotary table.

Canyon Express well completions established

many records for deepwater projects; like world

records in any dynamic operating environment,

some of these have already been broken. In

Camden Hills field, for example, records included

the deepest water for field development at

7209 ft [2197 m], a world depth record at the time

for setting a surface-controlled subsurface safetyvalve at 9894 ft [3016 m] below sea level; the

first three stacked frac-packs with four zonal-iso-

lation devices; and the fastest SenTREE 7

dual-derrick transfer—just 25 minutes. To

improve the efficiency of moving the Discoverer

Spirit from one location to another, the BOP

remained deployed beneath the vessel, about

400 ft [122 m] above the seabed, saving millions

of dollars in rig time compared with fully retriev-

ing the BOP, moving, and redeploying it.21 These

and other milestones were reached ahead of

schedule with no lost-time injuries or accidents,

and with well cleanup and deliverability of the

reservoir zones occurring as planned.

Marathon and TotalFinaElf both credit careful

planning and execution for the success in the

Canyon Express project. Nothing was taken for

granted; WIPT members evaluated even the sim-

plest components of advanced completion

systems to be confident about their decisions.The wells were “completed on paper” many

times before actual operations began.

Advances in Deepwater Cementing

Zonal isolation is a key concern in deep water,

where shallow-water or gas flows below the

seabed can lead to well-control problems and

a host of related hazards that have cost the

42 Oilfield Review

> Fluid invasion in setting cement. Cement slurries undergo four main stages as they progress fromfully liquid to solid (middle) . The temperature increases during the third stage, hydration (top) . When

the static gel strength of the slurry reaches a point known as the critical wall shear stress (CWSS),gas or water from the formation can enter the slurry because the pressure transmitted by the slurry isequal to the pore pressure of the formation (bottom) . The CWSS also is the starting point for the criti-cal hydration period (CHP). The end of the CHP occurs when the cement matrix is impermeableenough to prevent gas or fluid migration. During the CHP, the slurry is highly vulnerable to gas or fluidmigration. Therefore, a short CHP is one of the key features that a cement slurry must have when shal-low-water or gas-flow hazards exist.



Winter 2002/2003 43

exploration and production (E&P) industry hun-

dreds of millions of dollars.22 Shallow-water or

gas flows tend to occur in areas of rapid sedi-

mentation, overpressured formations and weak

formations, conditions typical of all the major

deepwater provinces of interest to E&P compa-

nies. These hazards are detected primarily byanalysis of seismic and measurements-while-

drilling data, although the growing database

of deepwater wells in regions such as the

Gulf of Mexico has led to more reliable predic-

tions as well data are integrated with regional

seismic maps.23

The loss of several wellbores in the Ursa

field, Gulf of Mexico, in the 1990s triggered

new awareness of and respect for the hazards of

shallow-water or gas flows.24 As a result, opera-

tors have modified their drilling procedures and

cementing systems. Drilling locations are

selected and well trajectories are planned toavoid shallow-flow hazards. Development-well

spacing is increased if shallow flows are

expected because washouts from one well might

affect nearby wells. Casing designs for deep-

water wells now take into account the possibility

of having to set casing below zones of shallow-

water or gas flows, although setting extra casing

strings to counter shallow-flow hazards leads

to higher well-construction costs and smaller

production-casing diameters.

Shallow-water or gas flows affect cementing

systems in several ways.25 First, because these

flows often occur at relatively shallow depths rel-

ative to the mudline, or seabed surface—500 to

2500 ft [152 to 762 m]—and in weak, unconsoli-dated formations, the density of the cementing

system must be especially light to be lower than

the fracture pressure. The slurry design must

offer fluid-loss control of 50 mL/30 min API or

less to avoid altering the slurry density or rheol-

ogy.26 To reduce the possibility of fluid channels

forming in the cement, the slurry design must

minimize the amount of free water and particle

settling in the slurry, a phenomenon known as

sedimentation. The critical hydration period

(CHP) must be brief to prevent water or gas from

flowing into the cement (previous page and

above). Finally, the hardened or set cementshould have low permeability to provide effec-

tive, long-term zonal isolation.

Like other deepwater technologies, wellbore

cementing has advanced rapidly, and multiple

solutions are now available to counteract and

isolate shallow-water or gas flows. In some

deepwater development projects, foamed

cements are chosen to cement weakly consoli

dated formations. These slurries incorporate

nitrogen or another inert gas in a conventiona

Portland cement system to reduce slurry density

This technique allows adjustment of the slurry

density at the wellsite, good fluid-loss contro

and satisfactory compressive-strength development at low temperatures, but foamed

cementing systems require additional equipmen

21. Pallanich Hull J: “BOP-Deployed Move Saves Time,Money,” Offshore 62, no. 6 (June 2002): 36.

22. Ostermeier RM, Pelletier JH, Winker CD, Nicholson JW,Rambow FH and Cowan KM: “Dealing with Shallow-Water Flow in the Deepwater Gulf of Mexico,” paperOTC 11972, presented at the 2000 Offshore TechnologyConference, Houston, Texas, USA, May 1–4, 2000.

23. For more on the use of seismic data to predict drillinghazards: Alsos et al, reference 4.

24. Eaton LF: “Drilling Through Deepwater Shallow WaterFlow Zones at Ursa,” paper SPE/IADC 52780, presentedat the SPE/IADC Drilling Conference, Amsterdam, TheNetherlands, March 8–11, 1999.

25. For more on cementing in shallow-flow areas: Stiles DA“Successful Cementing in Areas Prone to ShallowSaltwater Flows in Deepwater Gulf of Mexico,” paperOTC 8305, presented at the Offshore TechnologyConference, Houston, Texas, USA, May 5–8, 1997.

26. Fluid loss is the leakage of the liquid phase of drillingfluid, slurry or treatment fluid containing solid particlesinto the formation matrix, measured in volume per unit o

time. The resulting buildup of solid material or filter cakemay be undesirable, as may the penetration of filtrate

through the formation. Fluid-loss additives are used tocontrol the process and avoid potential reservoir damage

> Critical aspects of cementing shallow-water and gas flows. The CWSS for an annulus with drillingfluid and cement, described in the equation (top) , is mainly a function of wellbore parameters and isindependent of most slurry properties, except for slurry density. The CHP, which begins at the timelabeled Tc and ends at time Tf, reflects static gel-strength development, or how quickly the slurry gels

after pumping ceases. Deepwater operators typically seek cement slurries that minimize CHP, espe-cially in areas with shallow-water or gas flows.



plus the appropriate gas. In remote areas, the

expense and logistical requirements often dic-

tate other choices.27 Also, foaming tends to

increase set-cement permeability, which is not

desirable for long-term isolation.

Another option, fast-setting gypsum cement,

also known as plaster cement or 60:40 right-

angle set cement, can be effective for casing

strings set in low-temperature environments.

However, this type of cement tends to be com-

plicated and costly to mix and pump.28 The

60:40 part of the name refers to the fact that one

sack of blend contains 60% gypsum by weight.

The other 40% is Class C Portland cement.

The base slurry density of these systems is

15.8 lbm/gal [1894 kg/m3], so the slurry must be

foamed if a lower density is required. The gyp-

sum sets quickly, so a key aspect of planning and

executing these jobs is correctly retarding the

slurry so that it does not set before or during

pumping operations (left).

The key advantage of gypsum cement is that

the rapid setting prevents fluid migration into the

cement, but this advantage comes with several

disadvantages. Gypsum quality is highly variable,

so each blend must be rigorously tested before

the job begins. Also, the slurry is sensitive to

contamination in tanks and pumping equipment,

requiring additional labor to clean all equipment.

Many operators prefer to avoid using multiple

cementing systems because space for storage

and equipment on deepwater drilling rigs is lim-

ited. Because gypsum cements typically are used

only for shallow sections of deepwater wells,

another cementing system must be available for

deeper sections.

A recent innovation, DeepCEM deepwater

cementing solutions technology, offers similarperformance to gypsum cements but simplifies

logistics. DeepCEM systems incorporate a non-

retarding dispersant and cement-set enhancer;

these serve to shorten the transition time. The

additives are convenient to mix and pump and

are compatible with any oil- or gas-well cement.

They also make slurries less sensitive to minor

variations in well conditions or additive concen-

trations. Slurries that incorporate DeepCEM

technology develop gel strength and compressive

strength quickly, even in the low temperatures

typical of the deepwater environment (next page).

Deepwater Cementing

in the Gulf of Mexico

In the deep water of Block 243 of the Mississippi

Canyon area, Gulf of Mexico, TotalFinaElf is

developing its Matterhorn discovery. The field

sits below 2816 ft [858 m] of water and currently

contains nine wells drilled and cemented

between December 2001 and October 2002; the

wells will be completed using a workover rig

during the summer of 2003, and production will

flow to a small tension leg platform, also called

a miniTLP.

TotalFinaElf expected shallow-water flowsand seabed temperatures of 40°F [4°C] in the

Matterhorn wells. Drilling-fluids, mud-removal

and well-cementing programs were the subject

of intensive feasibility studies before the com-

pany approved development of the Matterhorn

find, during the service-company bidding process

and also before the operations began.

44 Oilfield Review

10,000

1000

100

G e

l s t r e n g t h ,

l b f / 1 0 0 f t 2

10

Tc

Impermeablematrix

CHP

TimeTf

1

2000

1500

1000

G e l s t r e n g t h ,

l b f / 1 0 0 f t 2

500

1750

1250

750

250

0 50

DeepCEMcement-set enhancer

No DeepCEMcement-set enhancer

100 150 200 250 300 350 400Time, min

0

CWSS

0.4gal/sack 0.2gal/sack 0.15gal/sack

0.1

gal/sack

0.05

gal/sack

Transition time:No DeepCEM cement-set enhancer = 161 min0.2 gallons per sack DeepCEM cement-set enhancer = 70 min0.4 gallons per sack DeepCEM cement-set enhancer = 47 min

Class H cement0.5 gallons per sack low-temperature GASBLOK system0.06 gallons per sack DeepCEM nonretarding dispersantDensity = 16.4 lbm/galTemperature = 65°FPressure = 400 psi

> Optimizing cement setting time. The CHP can be reduced if the slurry exhibitsa “right-angle set” type of static gel-strength development in which strengthdevelops as soon as pumping ceases (top) . “Right-angle set” refers to theappearance of the plot of gel strength versus time because of the nearly90° bend in the curve (blue line). Steeper static gel-strength developmentcurves are desirable because they indicate shorter CHPs. Gel strength canbe modified using additives, such as DeepCEM additives, a key capabilitywhen drilling in areas prone to shallow-water or gas flows (bottom) .



Winter 2002/2003 45

To improve mud removal, TotalFinaElf used

the WELLCLEAN II Engineering Solution sim-

ulator to optimize flow rates and spacer sizes,

and selected the MUDPUSH spacer family

for cementing.29

TotalFinaElf chose a TXI Lightweight Well

Cement system incorporating DeepCEM technol-

ogy for 26-in. and 20-in. surface casing strings.30

The lead slurry for 20-in. casing strings was

foamed to control hydrostatic pressure during

transition time. The same system was used,

without foaming, for tail slurries. For inter-

mediate and production casings, the TXI system

with DeepCEM additives also was used to

reduce transition times and time spent waiting

on cement, a key consideration given that its

deepwater-rig cost was US$250,000 per day.

Selection of a single cementing system

proved to be a key element of successful cement-

ing operations for TotalFinaElf. The drilling rig

had just two cement tanks, so it would have been

impractical to attempt to use more than one type

of cement. Storing more than one type of cementblend also presents difficulties when storage

space is limited. In addition, logistics at the

onshore base would have been much more com-

plicated, especially since TotalFinaElf opted to

batch-drill the development wells: the cementing

crew on location was performing cementing

operations approximately once every three days.

A single supply vessel operated at capacity to

deliver large volumes of drilling fluids, including

cement, for operations in a shallow-water flow

environment. If more than one cementing system

had been chosen, the potential for confusion,

either at the supply base or on the drilling rig,would have increased.

TotalFinaElf encountered shallow-water

flows in five of the nine Matterhorn wells. All

cementing operations proceeded smoothly, with

no remedial cementing required for the casing

strings set and cemented in shallow-flow zones.

Leakoff tests (LOTs) of all casing strings were

adequate, allowing TotalFinaElf to drill ahead

safely and without drilling-fluid losses.

During well-completion operations in 2003,

TotalFinaElf plans to acquire cement-bond logs to

better evaluate cement-bond quality and the

effectiveness of zonal isolation. For the timebeing, the company believes that LOT results and

ROV checks for annular flow at the wellheads

indicate successful cementing operations. As a

result, TotalFinaElf plans to use similar cement-

ing technology for future wells.

Additional deepwater cementing technology

is now available to meet the needs for rapid set-

ting and prevention of gas migration in cold,

deepwater environments. DeepCRETE deepwater

cementing solution technology, with a specially

engineered particle-size distribution, now is used

to counteract shallow-water or gas flows and

low temperatures, yet requires no special equip-

ment or personnel.31 DeepCRETE systems, which

can be formulated at densities ranging from

8.0 to 13.5 lbm/gal [959 to 1619 kg/m3], incorpo

rate DeepCEM technology. The particle-size

distribution makes the slurry easy to pump

1400

1200

1000

800

600

S t a t i c g e l s t r e n g t h ,

l b f / 1 0 0 f t 2

200

400

0 20 40 60 80 100

Time, min

0

Class G and DeepCEM system

Right-angle set system

DeepCRETE and DeepCEM system

* Transition time

13 min*

22 min*

12 min*

2000

1800

1600

1400

1200

1000

800

C o m p r e s s i v e s t r e n g t h ,

p s i

200

600

400

0 5 10 15 20 25

Time, hours

0

Class G and DeepCEM system

Foamed right-angle set system

DeepCRETE and DeepCEM system

12.5 lbm/gal

15.8 lbm/gal

12.5 lbm/gal

> Static gel-strength development (top) and compressive-strength develop-ment of slurries used for deepwater cementing (bottom) . The DeepCRETE andDeepCEM system (green curves) was used in deepwater wells in Malaysia.

27. For more on foamed and ultralightweight cements:

Al Suwaidi A, Hun C, Bustillos JL, Guillot D, Rondeau J,Vigneaux P, Helou H, Martínez Ramírez JA and ReséndizRobles JL: “Light as a Feather, Hard as a Rock,” Oilfield Review 13, no. 2 (Summer 2001): 2–15.

28. Mohammedi N, Ferri A and Piot B: “Deepwater WellsBenefit from Cold-Temperature Cements,” World Oil 222,no. 4 (April 2001): 86, 88 and 91.

29. For more on mud removal: Abbas R, Cunningham E,Munk T, Bjelland B, Chukwueke V, Ferri A, Garrison G,Hollies D, Labat C and Moussa O: “Solutions forLong-Term Zonal Isolation,” Oilfield Review 14, no. 3(Autumn 2002): 16–29.

30. TXI lightweight cements are manufactured from inter-ground, lightweight aggregate clinker and Portland

cement clinker to produce a blend with relatively low

specific gravity. The fine grind of this blend results inhigher reactivity, but requires more mix water than ordi-nary Portland cements. See: Nelson EB, Baret J-F andMichaux M: “Cement Additives and Mechanisms ofAction,” in Nelson EB: Well Cementing . Sugar Land,Texas, USA: Schlumberger Dowell (1990): 13-3.

For more on TXI cements: http://www.txi.com/

31. For more on applications of DeepCRETE technology:Piot B, Ferri A, Mananga S-P, Kalabare C and Viela D:“West Africa Deepwater Wells Benefit from Low-Temperature Cements,” paper SPE/IADC 67774, presentedat the SPE/IADC Drilling Conference, Amsterdam, TheNetherlands, February 27–March 1, 2001.



46 Oilfield Review

> Solid fraction, permeability, compressive strength and fluid loss of slurries used fordeepwater cementing.

32. Excessive heat evolved through chemical reactions of the cement-hydration process could melt hydrates near the wellbore and destabilize sediments that were previ-ously frozen in place.

33. Cement returns are an indication of the quality of acementing operation, and the only indication of lossesduring a cementing operation. If returns are observedand pumping pressures remain within the expected

range during the operation, then no problems areexpected. If returns are not observed, or only partialreturns are observed, then losses occurred during theoperation. In this case, the top of cement will not be ashigh as planned and remedial cementing operations maybe necessary.

34. For more on the Marco Polo project: Watson P, Kolstad E,Borstmayer R, Pope T and Reseigh A: “An Innovative

Approach to Development Drilling in the DeepwaterGulf of Mexico,” paper SPE/IADC 79809, presentedat the SPE/IADC Drilling Conference, Amsterdam,The Netherlands, February 19–21, 2003.

For more on FlexSTONE technology: Abbas et al,reference 29.



Winter 2002/2003 47

improves set-cement properties such as

permeability and durability, and requires lower

concentrations of gas-migration additives than

do ordinary slurries (previous page). DeepCRETE

systems have a lower heat of hydration than ordi-

nary Portland cements, which reduces the risk of

cementing in areas with gas hydrates.32 The

range of density adjustments possible at the

wellsite is narrower than for foamed cements,

but this is often outweighed by such advantages

as rapid transition time, low fluid loss and lowset-cement permeability.

Anadarko Petroleum has been active in the

deep waters of the Gulf of Mexico for several

years, with approximately 30 wells drilled as of

2002. Although their cementing operations using

foamed cements were successful, Anadarko

sought simpler, safer and less expensive alter-

natives. Foamed cementing systems require

additional equipment and personnel, and the use

of energized fluids, like foamed cement, presents

safety and risk-management issues that many

operators strive to avoid.

Anadarko—the first operator in the Gulf of

Mexico to do so—opted to use DeepCRETE slur-

ries after seeing laboratory-test results for

gel-strength development. Slurries pumped in

areas prone to shallow-water or gas flows need to

develop gel strength rapidly. DeepCRETE slurries

were used for cementing the surface casing

strings in one deepwater exploratory well inthe Mississippi Canyon planning area (above).

Mixing and pumping operations proceeded as

planned. In the Marco Polo development project in

the Green Canyon area, also operated by

Anadarko, five 20-in. casing strings were

cemented with DeepCRETE slurries.

Logging tools cannot measure cement quality

in large-diameter wellbore sections, so cement-

ing operations in surface casing strings are

evaluated in other ways. In these deepwate

wells, Anadarko observed that returns to the

mudline were easy to see using an ROV. 33 LOT

results were better than expected.

The use of DeepCRETE systems resulted in

significant financial savings for Anadarko. By no

having a foamed-cementing crew on standby

and then not requiring that crew to wait to

cement the second surface casing string, the

company saved about US$200,000 on the

exploratory well. Development wells werecemented as a group, so waiting time for a

foamed-cementing crew would have been less

with estimated savings of approximately

US$100,000 per well. Drilling in the Marco Polo

field incorporates other advanced cementing

technologies, including FlexSTONE advanced

flexible cement technology slurries for produc

tion casing.34

> Locations of the Marco Polo field and Mississippi Canyon exploratory well, offshore Gulf of Mexico,

and schematic diagrams of wells (top) .



Deepwater Cementing Offshore Malaysia

Offshore Malaysia, in the South China Sea,

Murphy Sabah Oil Co. Ltd. successfully drilled

five deepwater wells in 2002 (above).35 All thedrilling locations exhibited potential for shallow-

water or gas flows, gas hydrates and weak,

unconsolidated formations. At water depths of

1300 to 3000 m [4265 to 9843 ft], seabed tem-

peratures were approximately 1.7°C [35°F];

CemCADE cementing design and evaluation soft-

ware simulations were used to evaluate the

effects of temperature on slurry pumpability and

compressive-strength development.

Initially, Murphy considered using foamed

cementing systems, but mobilizing the additional

equipment and personnel for these operations

added unacceptable complications. Ultimately,Murphy selected an optimized lightweight

cementing system to meet its stringent require-

ments for slurry density, compressive strength

and limited time waiting on cement. The

DeepCRETE system incorporated DeepCEM addi-

tives and GASBLOK gas migration control cement

system additives; the fluid-loss control, zero free

water, lack of sedimentation and short transition

time contributed to excellent slurry perfor-

mance.36 The system exhibited a low heat of

hydration, a key attribute in an area known tocontain gas hydrates.

Surface casing strings for all four wells were

cemented successfully, with full returns observed

during all surface casing jobs. LOTs at the surface

casing shoe also met operator requirements—

LOTs were adequate to allow Murphy to drill to

the next designed casing point without having to

set any intermediate contingency casing strings.

48 Oilfield Review

> Deepwater cementing offshore Malaysia. Murphy Sabah Oil Co. Ltd. cemented wells in Block K in April 2002. The wells, in water depths of 1300 to 3000 m[4265 to 9843 ft], were located in areas prone to shallow-water or gas flows, gas hydrates and weak, unconsolidated formations. A schematic diagram (top right) shows the casing and cement configuration.



Winter 2002/2003 49

Deepwater Cementing Offshore Angola

Other advanced cementing systems are being

used to advantage in deepwater wells. Cement-

ing operations for wells in the Girassol field,

offshore Angola, are challenging. Discovered by

TotalFinaElf in 1996, the Girassol field is a world-

class deepwater development that began

producing oil to a floating production, storage

and offloading (FPSO) facility in 2001 (above).37

For the Girassol 119 well in Block 17, the

operator wanted to ensure excellent zonal isola-

tion for the Oligocene-age B1 reservoir, which

would be frac-packed, and the overlying

B3 reservoir, which would not be completed in

this well. The well deviated as much as 75° from

vertical and the 121 ⁄ 4-in. hole was mostly in

gauge, although some localized washouts of

16- to 20-in. diameter were encountered across

interbedded shales of the B3 reservoir. There

were no significant drilling-fluid losses during cir-

culation or running of the casing.

The company required a low-density slurry to

allow higher displacement rates and accurate

cement placement, and good compressive

strength in the set cement to support the frac-

pack operation. Using the WELLCLEAN IIsimulator, cementing engineers designed a

LiteCRETE slurry and optimized displacement

rates within the limits of hole inclination, cen-

tralizer placement and equivalent circulating

density of the slurry. The significant inclination of

the wellbore made it difficult to achieve slurry

flow around the casing, particularly in the upper

part of the zone because fewer centralizers were

used to limit drag forces as the casing was run.

The cementing operations began with the

pumping of MUDPUSH spacer to remove oil-base

drilling mud. A 10.8-lbm/gal [1.3-g/cm3] LiteCRETE

slurry followed. The slurry was batch-mixed rathe

than mixed on the fly during cementing operations

to ensure that it had the proper density and slurry

quality throughout the job.

35. For more on Murphy’s deepwater cementing inMalaysia: Schmidt D, Ong D and El Marsafawi Y:“Cementing Challenges in Ultra Deep Water, OffshoreSabah, Malaysia,” presented at the OSEA InternationalConference, Singapore, October 29–31, 2002.

36. Thorough testing, performed at the Kuala Lumpur andHouston Client Support Labs (CSLs), ensured the slurryand additives would meet operator specifications. Formore on CSLs: Abbas et al, reference 29.

37. For more on the Girassol field: Hart Publications:“Girassol: Pushing the Deepwater Frontier,” supplement

to Hart’s E&P , May 2002.

> Location of Girassol field, Block 17, offshore Angola, and wellbore schematic for the 119 well. Thewell deviated as much as 75° from vertical (right) .



TotalFinaElf used the DeepSea EXPRES off-

shore plug launching system with a double-plug

cementing head system to separate drilling

fluids. The DeepSea EXPRES cementing head

offers enhanced reliability because of simpler

cement-plug design (right). Plugs are released

from the subsea tool without physical contact

between the darts and the plugs, avoiding dart-

to-plug sealing problems. This cementing head

reduces rig time because of more efficient,

remotely controlled dart release and because

casing pressure tests can be combined with

bumping the top plug.38 Operating companies are

experiencing improved job quality because there

is better cement placement, no fluid contamina-

tion and no microannulus. This cementing head

also allowed the operator to test casing immedi-

ately after bumping the cementing plug because

the surface-dart launcher is rated to 10,000 psi

[69 MPa], which exceeds the pressure rating of

plugs and float equipment.

The operations proceeded smoothly despite

minor logistical problems, such as contaminationof the blend during delivery to the drilling rig.

Nevertheless, the USI UltraSonic Imager log

indicated excellent cement quality in the critical

zone from 3375 to 3525 m [11,073 to 11,565 ft]

measured depth (next page).

Waves of the Future

Considerable deepwater activity awaits our

industry. Deepwater discoveries to date have

contributed approximately 60 billion barrels

[9.5 billion m3] of oil to worldwide reserves, yet

only about 25% of deepwater reserves have

been or are being developed; perhaps as little as5% has been produced.39 In the relatively short

time that oil and gas companies have explored

and produced in deep water, exploratory success

in this frontier has climbed from about 10% to

more than 30% worldwide.40 This increasing suc-

cess rate comes at a critical time as the industry

copes with increasing energy demand.

Substantial work remains in deepwater reser-

voir characterization. Many deepwater reservoirs

turn out to be more complex than initially

thought, not surprising given that first-pass

interpretations are made on the basis of rela-

tively limited static data from seismic surveys,possibly logs from one or more exploratory wells

and, rarely, cores. Dynamic data, including time-

lapse seismic surveys, measurements from

permanent sensors and production data, are con-

tributing more to our understanding of deepwater

50 Oilfield Review

38. “Bumping the plug” refers to an increase in pumppressure during cementing operations, indicating that

the top cement plug has been placed on the bottomplug or landing collar. Bumping the plug concludes thecementing operation.

39. Shirley, reference 2.

40. Shirley, reference 2.41. Turbidites are sedimentary deposits formed by turbidity

currents in deep water at the base of the continentalslope and on the abyssal plain. For more on turbiditereservoirs: Weimer P, Slatt RM, Dromgoole P, Mowman Mand Leonard M: “Developing and Managing TurbiditeReservoirs: Case Histories and Experiences: Resultsof the 1998 EAGE/AAPG Research Conference,” AAPG Bulletin 84, no. 4 (April 2000): 453–465.

> Improved equipment for deepwater cementing. The subsea tool (left) holds casing-wiper plugs until

they are released by darts pumped from a surface-dart launcher(right)

. Wiper plugs separate thecement slurry from other fluids, reducing contamination and maintaining predictable slurry propertiesand performance. The bottom plug is launched ahead of the cement slurry to minimize contaminationby drilling fluids inside the casing prior to cementing. Increasing pump pressure ruptures a diaphragmin the plug body to allow the cement slurry to pass through after a plug reaches the landing collar.The top plug has a solid body that provides positive indication of contact with the landing collar andbottom plug through an increase in pump pressure.

42. Kallaur C: “The Deepwater Gulf of Mexico—LessonsLearned,” presented at the Institute of PetroleumInternational Conference on Deepwater Exploration andProduction, London, England, February 22, 2001.

43. For more on the Deep Spills Task Force: Lane JS andLaBelle RP: “Meeting the Challenge of PotentialDeepwater Spills: Cooperative Research Effort BetweenIndustry and Government,” paper SPE 61114, presentedat the SPE International Conference on Health, Safety,and the Environment in Oil and Gas Exploration andProduction, Stavanger, Norway, June 26–28, 2000.

44. For more on SINTEF: http://www.sintef.no



reservoirs and their production. Data from analo-gous reservoirs, either in outcrop or the

subsurface, also guide reservoir interpretations

(see “Shallow Clues for Deep Exploration,”page 2 ).

Unexpected deepwater reservoir complexity

commonly leads to changes in the number or

placement of wells to optimize hydrocarbon recov-ery. Of greater concern to operators, however, are

the unfortunate cases of facilities designs that

turn out to be inadequate to handle actual produc-

tion. Improved understanding of deepwater

reservoirs should lead to more accurate production

models and correctly sized production facilities a

the outset of field development.

Turbidite reservoirs are commanding atten

tion from geoscientists, who are devoting

particular attention to such issues as reservoi

quality, reservoir continuity and reservoir drive.4

In addition to establishing reliable analog models

for future turbidite discoveries, deepwate

geoscientists are compiling lessons learned

about data collection and knowledge sharing

throughout the life of deepwater reservoirs

Naturally, collection and analysis of data involve

crossdisciplinary collaboration.

Most deepwater developments demand sig

nificant cooperation and innovation: no single

company can “go it alone.” Canyon Express and

projects like it set a new standard for application

of deepwater technology. Cooperation in deep

water extends to other impressive projects. Fo

example, industry participants invited the US

Minerals Management Service, the US Coas

Guard and other organizations to join the

DeepStar consortium that examines the technicaissues surrounding deepwater operations.42

The DeepStar consortium has been working

since 1992 to improve technology and operations

and enhance profitability for fields in up to 10,000 f

[3048 m] of water. This group also studies safety

and environmental issues associated with deep

water operations. For example, the Deep Spills

Task Force has studied the potential effects o

blowouts and spills.43 Organizations such as the

Foundation for Scientific and Industrial Research

at the Norwegian Institute of Technology (SINTEF

are also contributing to the industry’s understand

ing of equipment design and reliability.44

In addition to new cementing systems and

related equipment, improvements in other tech

nologies facilitate deepwater production

Artificial lift, tool conveyance and flow assurance

are areas of active research and development fo

service and E&P companies.

Production from deepwater fields remains an

enormous challenge, but the collaborative efforts

of E&P companies, service companies and

government agencies are making the task less

daunting with time. —GMG

> High-quality zonal isolation in a Girassol well. The USI UltraSonic Imager log shows excellent cementbonding between cement and casing from approximately 3375 to 3525 m [11,073 to 11,565 ft].

high expectation from deepwater_slb

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