high expectations from deepwater wells - semantic scholar · 2019-06-25 · otc 13131, presented at...

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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 Watson Houston, 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 in completing 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 as shallow-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 with partners 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

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Page 1: High Expectations from Deepwater Wells - Semantic Scholar · 2019-06-25 · OTC 13131, presented at the 2001 Offshore Technology Conference, Houston, Texas, USA, April 30–May 3,

36 Oilfield Review

High Expectations from Deepwater Wells

Guy CarréEmmanuel PradiéTotalFinaElf AngolaLuanda, Angola

Alan ChristieLaurent DelabroyBilly GreesonGraham WatsonHouston, Texas, USA

Darryl FettJose PiedrasTotalFinaElf E&P USA, Inc.Houston, Texas

Roger JenkinsDavid SchmidtMurphy Sabah Oil Co. Ltd.Kuala Lumpur, Malaysia

Eric KolstadAnadarko PetroleumThe Woodlands, Texas

Greg StimatzGraham TaylorMarathon Oil CompanyHouston, 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 hydrocarbonsfrom deepwater environments begins with iden-tifying viable prospects. Geoscientists andengineers have built an enviable record of suc-cesses in deepwater exploration. Similarly, thedrilling community can point to its own techno-logical developments for deepwater drilling.1 Thefinal test before beginning production lies incompleting deepwater wells, and there, too, thepetroleum industry is making tremendous strides.

How deep is deep? While various definitionsexist, many operators define deep water asgreater than 500 m [1640 ft] deep, and ultradeepwater as more than 2000 m [6562 ft] deep (next page).2 The US Minerals ManagementService (MMS), which manages mineralresources 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 mustcope 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 Thesedifficulties are alleviated somewhat by gains inseismic quality, improvements in well-loggingand well-testing technology, and advances and

experience in drilling, drilling fluids—includingcement—and well-completion technology.5

In this article, we examine a state-of-the-artdeepwater development in the Gulf of Mexico.We also introduce new technologies for deepwa-ter cementing and evaluate their usefulness inthe deep waters offshore USA, Malaysia andWest Africa.

Deepwater Completions in the Gulf of MexicoThe earliest “deepwater” operations occurred inthe Gulf of Mexico (GOM), Brazil and West Africain the late 1970s.6 In the Gulf of Mexico, thereare now more than 150 discoveries in waterdepths exceeding 1000 ft, of which 12 are inmore than 6000 ft [1829 m] of water.7 Threeof these deepest fields are included in theCanyon Express project, operated by TotalFinaElfE&P USA, which also operates the pipeline sys-tem, Marathon Oil Company and BP withpartners Nippon Oil Exploration USA and PioneerNatural Resources.

Located 150 miles [241 km] southeast of NewOrleans, Louisiana, USA, the Canyon Expressfields now comprise nine wells. There are fourwells in the Aconcagua field operated by

Page 2: High Expectations from Deepwater Wells - Semantic Scholar · 2019-06-25 · OTC 13131, presented at the 2001 Offshore Technology Conference, Houston, Texas, USA, April 30–May 3,

For help in preparation of this article, thanks to Raafat 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 projectoccurred in September 2002. Produced fluidsfrom the three fields travel 56 miles [90 km]

through a dual-pipeline system to the CanyonStation platform in Block 261 of the Main Passplanning area. Williams Energy operates this pro-duction platform.

Before agreeing to a shared gathering sys-tem, the operating companies examined otheroptions, such as spars and other stand-alonefacilities. The difficulty of subsea operations andthe 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 Review12, no. 1 (Spring 2000): 2–17.

2. Shirley K: “Global Depths Have Great Potential,” AAPGExplorer 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 and Uchida T: “Growing Interest in Gas Hydrates,” OilfieldReview 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 Review11, no. 4 (Winter 1999/2000): 2–19.

6. Shirley, reference 2.7. Approximately 50 of these discoveries were producing

hydrocarbons as of 2002. For more information: Baud RD,Peterson 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.

Page 3: High Expectations from Deepwater Wells - Semantic Scholar · 2019-06-25 · OTC 13131, presented at the 2001 Offshore Technology Conference, Houston, Texas, USA, April 30–May 3,

these fields independently. The subsea infras-tructure for the Canyon Express wells is tied to asubsea, multiphase gathering system (left).8 TheCanyon Express partners agreed to a number ofcooperative operating principles, but the mostimportant is that no reservoir assumes the reser-voir-performance risks of the other reservoirs.9

Well-completion technology is a key aspectof maximizing production from deepwater fields.Completion techniques and procedures generallyare similar regardless of the water depth.However, at greater depths, the technologychoices are more limited. For example, as waterdepth goes beyond 6000 ft, the only system-design option is a subsea wellhead system withwet trees.

A wet tree is a subsea production system(below left). Designed for deepwater wells, theseadvanced systems typically are fitted with pres-sure and temperature sensors, flow-controlvalves and facilities for hydrate inhibition, and all components are optimized to avoid well-intervention operations. The well-interventioncosts for the deepest subsea wells, those withwet trees, are so great that the wells aredesigned with the expectation that physicalintervention will not occur. Dry trees, in contrast,are similar to conventional completions for plat-form wells. They are designed to produce tocompliant towers, spars and tension-leg plat-forms (TLPs), from which well-interventionoperations are simpler and less expensive.10

Production risers, which are used for fixed off-shore structures such as TLPs, are not an optionbeyond about 4500-ft [1372-m] water depth.Instead, flowlines are used to transmit producedfluids to production and testing facilities. All thecontrol valves for wet trees are subsea, and pro-duction from the Canyon Express fields goesthrough a flowline to production facilities.

There are significant difficulties in placingproduction equipment on the seabed: deepcanyons, salt diapirs and potentially unstableseabed surfaces. Cost and efficiency also aremajor concerns. Well-completion operationsfrom a dynamically positioned drillship in morethan 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 reservoirzone add another level of complexity to deep-water projects.

Faced with these many problems, MarathonOil Company and TotalFinaElf E&P USA created ajoint project team, known as the Wells IntegratedProject 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 bythe 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 than a 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 courtesy of Cameron.)

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Winter 2002/2003 39

procure equipment and plan well-completionoperations.12 The team began its work in October2000; well completions were carried out fromJanuary to September 2002.

The well completions for Aconcagua andCamden Hills fields use similar techniques andtechnology to link the reservoirs to productionfacilities. Safe, rapid, interventionless and trouble-free reserve depletion is the goal, with allcompletion systems tailored to individual reser-voirs. The two main requirements for thecompletions are to provide sand control anddownhole flow control to deal with potentialwater breakthrough in each producing zone. Thiswell-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 gravelpacking for long, heterogeneous reservoir inter-vals, sand-control systems and subsea well-controlsystems (right). The wells also contain flow-con-trol valves and permanent gauges.13 Although theinitial investment in the completion equipmentand installation was more than US$20 million perwell, the project team also considered the poten-tial cost of remedial well-interventionoperations—in this case, well interventionwould cost approximately US$10 million peroperation. Given the magnitude of these costs,remotely controlled downhole equipment is a cost-effective alternative to expensive, riskyinterventions (see “Advances in Well andReservoir Surveillance,” page 14).

Well-completion operations for theAconcagua and Camden Hills wells were con-ducted from the Transocean Discoverer Spirit, adynamically positioned drillship. To optimize rigtime, completion operations were designed totake advantage of the advanced pipe-handlingcapabilities of the dual-derrick system. Duringthe completion operations, a pipeline-laying ves-sel, a drillship and a vessel for a remotelyoperated vehicle (ROV) were active in the area,requiring careful coordination and vigilance by allwork 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 atthe Deep Offshore Technology International Conference,New Orleans, Louisiana, USA, November 6–9, 2000.

Tubing hanger

Methanol-injectionmandrelTRC-DH-10-LOsafety valve

Chemical-injectionmandrelPacker-setting device

Splice subProduction packer

Upper flow-control valveLower flow-control valveLanding nippleWireline reentry guide7-in. shroudLanding nipple forlower zone isolation3 1⁄2-in. isolation tubingQUANTUM isolation packerProduction-seal assembly

AFIV deviceQUANTUM X packerMechanical FIV device2 7⁄8-in. tubing withcarbide blast ringsAllFRAC screenShifting tool

Gauge carrier withthree pressure andtemperature sensorsCross-nipple for upper zone isolation

Packer-setting mechanical override

9 5⁄8 -in. liner top

4 1⁄2 -in. productiontubing

QUANTUM X packerHydraulic/mechanicalFIV deviceAllFRAC screenSump packer

Upperinterval

9 5⁄8 -in.linertop

Lowerinterval

> 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 in a 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 HoustonChronicle 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 IntelligentCompletion Technology in Unique Field DevelopmentScenario,” paper SPE 71675, presented at the SPEAnnual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 30–October 3, 2001.

Page 5: High Expectations from Deepwater Wells - Semantic Scholar · 2019-06-25 · OTC 13131, presented at the 2001 Offshore Technology Conference, Houston, Texas, USA, April 30–May 3,

Well-completion designs and procedures forthe six wells in the Aconcagua and Camden Hillsfields were similar. As the operations teamgained experience, the time required to completea well decreased (right).

First, the horizontal subsea tree was run andtested immediately prior to completion opera-tions. The drillship had two rotary tables; the treewas run from the aft rotary while the marinedrilling riser with the blowout preventer (BOP)was run on the forward rotary table.14 After thesubsea tree, the drilling riser and the interven-tion and workover control-system were run, thetree was tested. Completion-equipment installa-tion began after the subsea BOP stack was runand latched.

After the BOP stack was tested, the temporaryabandonment plugs were drilled out, and the wellwas cleaned out by displacing drilling mud withseawater and then calcium chloride [CaCl2] com-pletion brine. Afterward, displacement pills,casing scrapers, brushes and jetting tools wereused to minimize residual wellbore debris.15

Wireline was used to set the sump packer nearthe bottom of the well to provide depth control forsubsequent perforating and sand-control opera-tions. The upper and lower sand reservoirs werethen perforated using tubing-conveyed perforatingequipment and completed in a stacked frac-packconfiguration for commingled production.

Perforating operations for one of the CanyonExpress wells used S.A.F.E. Slapper-ActuatedFiring Equipment perforating technology insteadof electric detonators or packer-setting tooligniters, which cannot be used while radios,welders and other rig equipment are in use.16 Theexploding foil initiator of the S.A.F.E. systemrequires higher currents than ordinary detonatorsor igniters, so stray voltages are not a concern.Using the S.A.F.E. system saves rig time duringperforating operations because radio silence isnot required; operations such as welding cancontinue without interruption. The zones wereperforated slightly overbalanced; any perforationdamage would be overcome by fracturing opera-tions that would extend beyond the damagedzone. The FIV Formation Isolation Valve device,described later, and a packer plug isolated thelower zone during perforating and sand-controloperations in the upper zone.

The upper zone was gravel packed because ofa nearby water zone; the lower zone had a fracpack. The zones were isolated after sand-controloperations to prevent fluid loss and fluid influx.

Innovative FIV technology was used with theQUANTUM 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 bypressure rather than physical intervention withslickline; as a contingency, they can be openedusing 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, theFIV ball was shifted closed mechanically, provid-ing positive shutoff in case of fluid loss orreservoir 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.

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Winter 2002/2003 41

Packers are downhole devices used in almostevery completion to isolate the annulus from theproduction conduit and anchor the conduit in thecasing, enabling controlled production, injectionor treatment. The QUANTUM X packer is a ver-satile, rugged packer designed for sand-controlcompletions, such as gravel packing, and high-pressure, high-volume stimulation treatments. Inthis case, STIMPAC services combined fracturingand gravel packing in a single operation. Thisfrac-pack technique breaks through the formationdamage and minimizes productivity impairmentthat is common in conventional cased-hole gravelpacks.17 This stimulation operation was executedby the DeepSTIM I and DeepSTIM II offshorestimulation vessels. The DeepSTIM vessels pro-vide large-capacity treatments and high-rate,high-pressure pumping, fracturing, acidizing orgravel packing for remote or deepwater locations.

Following the final sand-control treatment, anisolation-packer assembly was run on the workstring 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 tubingand the sand-control screen. The isolation assem-bly also incorporated AFIV annular-controlled FIVsystem technology to provide well control andprevent fluid loss in the upper flow path.

The designs of the sandface completions dif-fered somewhat because Marathon andTotalFinaElf have different philosophies. Forexample, TotalFinaElf used the DataFRAC frac-ture data determination service before the job tooptimize 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, tomaximize productivity and to minimize the skineffect. Marathon selected prepacked screens tooptimize sand control. The risk involved in thelower completions was significant—several dis-tinct operations were required to install eachcomponent, any of which could damage the payzone if performed incorrectly. Once installed,however, both completion designs provided aneffective 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 retrievedif necessary. Nevertheless, running the uppercompletion presented significant risks andchallenges. This equipment included a pro-duction-seal assembly that locates and stingsinto the isolation-packer assembly. TheWellDynamics Intelligent Well Completion

System (IWCS) equipment was run above theseal assembly. The IWCS includes two flow-control valves, which allow selective control ofeach completed interval. The IWCS also includespressure and temperature gauges and a hydrauli-cally set production packer.

A chemical-injection system for scale treat-ment and surface-controlled subsurface safetyvalves (SCSSVs) also were run in the CanyonExpress wells (see “At the Ready: SubsurfaceSafety Valves,” page 52).18 Seabed temperaturesof 38°F [3°C] and the potential for gas hydratesnecessitated a methanol-injection system toinhibit hydrate formation in the flowlines.Another system at the wellheads minimizes pro-duction problems caused by changes in the stateof hydrocarbon liquids, such as paraffin precipita-tion. Nine control lines are used to operate thevarious downhole systems.

The SCSSV was a tubing-retrievable, nitro-gen-charged valve that incorporates dual,redundant hydraulic operating systems. TheSCSSV was set deep enough to avoid hydrateformation, approximately 2500 ft [762 m] belowthe seabed.19 A methanol-injection mandrelinstalled just above the SCSSV offers further pro-tection from hydrate formation. Production tubingwas run from this mandrel to the subsea tubinghanger. The tubing-hanger running tool, operatedby 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 wellcleanup and testing, and the system shuts offflow from the well and can be removed safely in15 seconds.20 This sophisticated, deepwater testtree was electrohydraulically controlled with asmall, multifunctional umbilical clamped to thelanding string. During completion installation,the SenTREE 7 control system allowed theSCSSV and IWCS equipment to function beforelanding the tubing hanger. The Commander con-trol system for subsea well control managed andmonitored the test tree and completion through-out the operations.

A special riser-sealing mandrel was run in thelanding string to protect the umbilicals whenclosing the diverter packer in case gas enteredthe drilling riser above the BOP stack. The riser-sealing mandrel was positioned to accommodateheave of the drilling vessel, downward motioncaused by loss of station keeping, and emer-gency unlatching of the SenTREE 7 system.

Packer fluid was circulated into the wellboreprior 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 AFIVdevices—were opened by applying a predeter-mined number of pressure cycles on theproduction tubing. The AFIV device provideszonal control for the upper zone; the FIV deviceprovides reliable fluid control before running theproduction string.

The flow-control valves were configured toproduce the lower interval for cleanup and eval-uation. Produced gas and condensate were flaredthroughout the flowback period, and samples ofeach were captured at surface. Recovered stimu-lation fluids were stored either for flaring withproduced gas or for subsequent transfer to shorefor disposal. To eliminate the risk of hydrate for-mation and the mechanical risk of runningwireline, there was no downhole sampling.

The upper interval was flowed for cleanupand evaluation in a similar manner. A short testof the commingled intervals confirmed that theIWCS equipment functioned properly. The wellwas shut in at surface; the SCSSV was closed,and fluid in the tubing above the SCSSV was dis-placed by methanol. The tubing-hanger crownplug was run on wireline, and the SenTREE 7 unitwas 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, freshwaterpills to dissolve encroaching salt formations, pipe-freeing pills to destroy filter cake and relieve differential-sticking 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 A,Michel 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. Twotypes of subsurface safety valve are available: surface-controlled and subsurface-controlled. In each type, thesafety-valve system is designed to be fail-safe, so thatthe wellbore is isolated in the event of any system failureor 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 DeepwaterTechnology (August 2002): 37–38.

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

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A wireline plug was preinstalled in the inter-nal tree cap on surface, which was then run onthe work string using a mechanical running tool.The mechanical running tool is operated by clos-ing the appropriate set of pipe rams and applyingpressure down the choke or kill lines.

Finally, fluid from the well was unloaded to therig for production testing and cleanup. The treethen was secured with a tubing-hanger wirelineplug and internal tree cap. The BOP stack, riserand intervention and workover control-systemumbilical were disconnected, and the rig wasmoved to the next well in the completion program.

At the end of this project, Marathon and allCamden Hills service providers conducted alengthy evaluation, and the many lessons learnedand ideas for improvement were captured to enhance future completion operations.TotalFinaElf held similar meetings withSchlumberger to review each Aconcagua com-pletion. The dual-activity rig added flexibility and

saved many days of rig time because the aftrotary table was used to perform offline pressuretesting, equipment preparation and equipmentmakeup prior to the use of the equipment inactivities on the forward rotary table.

Canyon Express well completions establishedmany records for deepwater projects; like worldrecords in any dynamic operating environment,some of these have already been broken. InCamden Hills field, for example, records includedthe deepest water for field development at 7209 ft [2197 m], a world depth record at the timefor setting a surface-controlled subsurface safetyvalve at 9894 ft [3016 m] below sea level; thefirst three stacked frac-packs with four zonal-iso-lation devices; and the fastest SenTREE 7dual-derrick transfer—just 25 minutes. Toimprove the efficiency of moving the DiscovererSpirit from one location to another, the BOPremained deployed beneath the vessel, about

400 ft [122 m] above the seabed, saving millionsof dollars in rig time compared with fully retriev-ing the BOP, moving, and redeploying it.21 Theseand other milestones were reached ahead ofschedule with no lost-time injuries or accidents,and with well cleanup and deliverability of thereservoir zones occurring as planned.

Marathon and TotalFinaElf both credit carefulplanning and execution for the success in theCanyon Express project. Nothing was taken forgranted; WIPT members evaluated even the sim-plest components of advanced completionsystems to be confident about their decisions.The wells were “completed on paper” manytimes before actual operations began.

Advances in Deepwater CementingZonal isolation is a key concern in deep water,where shallow-water or gas flows below theseabed 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). Whenthe 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.

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Winter 2002/2003 43

exploration and production (E&P) industry hun-dreds of millions of dollars.22 Shallow-water orgas flows tend to occur in areas of rapid sedi-mentation, overpressured formations and weakformations, conditions typical of all the majordeepwater 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 Ursafield, Gulf of Mexico, in the 1990s triggered new awareness of and respect for the hazards ofshallow-water or gas flows.24 As a result, opera-tors have modified their drilling procedures andcementing systems. Drilling locations areselected and well trajectories are planned toavoid shallow-flow hazards. Development-wellspacing is increased if shallow flows areexpected because washouts from one well mightaffect nearby wells. Casing designs for deep-water wells now take into account the possibilityof having to set casing below zones of shallow-water or gas flows, although setting extra casingstrings to counter shallow-flow hazards leads

to higher well-construction costs and smallerproduction-casing diameters.

Shallow-water or gas flows affect cementingsystems in several ways.25 First, because theseflows often occur at relatively shallow depths rel-ative to the mudline, or seabed surface—500 to2500 ft [152 to 762 m]—and in weak, unconsoli-dated formations, the density of the cementingsystem must be especially light to be lower thanthe fracture pressure. The slurry design mustoffer fluid-loss control of 50 mL/30 min API orless to avoid altering the slurry density or rheol-ogy.26 To reduce the possibility of fluid channelsforming in the cement, the slurry design mustminimize the amount of free water and particlesettling in the slurry, a phenomenon known assedimentation. The critical hydration period(CHP) must be brief to prevent water or gas fromflowing into the cement (previous page andabove). Finally, the hardened or set cementshould have low permeability to provide effec-tive, long-term zonal isolation.

Like other deepwater technologies, wellborecementing has advanced rapidly, and multiplesolutions are now available to counteract andisolate shallow-water or gas flows. In somedeepwater development projects, foamed

cements are chosen to cement weakly consoli-dated formations. These slurries incorporatenitrogen or another inert gas in a conventionalPortland cement system to reduce slurry density.This technique allows adjustment of the slurrydensity at the wellsite, good fluid-loss controland satisfactory compressive-strength devel-opment at low temperatures, but foamedcementing systems require additional equipment

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 oftime. The resulting buildup of solid material or filter cakemay be undesirable, as may the penetration of filtratethrough 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 gelsafter pumping ceases. Deepwater operators typically seek cement slurries that minimize CHP, espe-cially in areas with shallow-water or gas flows.

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plus the appropriate gas. In remote areas, theexpense and logistical requirements often dic-tate other choices.27 Also, foaming tends toincrease set-cement permeability, which is notdesirable 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 The60:40 part of the name refers to the fact that onesack 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 befoamed if a lower density is required. The gyp-sum sets quickly, so a key aspect of planning andexecuting these jobs is correctly retarding theslurry so that it does not set before or duringpumping operations (left).

The key advantage of gypsum cement is thatthe rapid setting prevents fluid migration into thecement, but this advantage comes with severaldisadvantages. Gypsum quality is highly variable,so each blend must be rigorously tested beforethe job begins. Also, the slurry is sensitive tocontamination in tanks and pumping equipment,requiring additional labor to clean all equipment.Many operators prefer to avoid using multiplecementing systems because space for storageand equipment on deepwater drilling rigs is lim-ited. Because gypsum cements typically are usedonly for shallow sections of deepwater wells,another cementing system must be available fordeeper sections.

A recent innovation, DeepCEM deepwatercementing solutions technology, offers similarperformance to gypsum cements but simplifieslogistics. DeepCEM systems incorporate a non-retarding dispersant and cement-set enhancer;these serve to shorten the transition time. Theadditives are convenient to mix and pump andare compatible with any oil- or gas-well cement.They also make slurries less sensitive to minorvariations in well conditions or additive concen-trations. Slurries that incorporate DeepCEMtechnology develop gel strength and compressivestrength quickly, even in the low temperaturestypical of the deepwater environment (next page).

Deepwater Cementing in the Gulf of MexicoIn the deep water of Block 243 of the MississippiCanyon area, Gulf of Mexico, TotalFinaElf isdeveloping its Matterhorn discovery. The fieldsits below 2816 ft [858 m] of water and currentlycontains nine wells drilled and cementedbetween December 2001 and October 2002; thewells will be completed using a workover rigduring the summer of 2003, and production willflow to a small tension leg platform, also called a miniTLP.

TotalFinaElf expected shallow-water flowsand seabed temperatures of 40°F [4°C] in theMatterhorn wells. Drilling-fluids, mud-removaland well-cementing programs were the subjectof intensive feasibility studies before the com-pany approved development of the Matterhornfind, during the service-company bidding processand also before the operations began.

44 Oilfield Review

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Class H cement0.5 gallons per sack low-temperature GASBLOK system0.06 gallons per sack DeepCEM nonretarding dispersantDensity = 16.4 lbm/gal Temperature = 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 nearly 90° 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).

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Winter 2002/2003 45

To improve mud removal, TotalFinaElf usedthe 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 WellCement system incorporating DeepCEM technol-ogy for 26-in. and 20-in. surface casing strings.30

The lead slurry for 20-in. casing strings wasfoamed to control hydrostatic pressure duringtransition time. The same system was used,without foaming, for tail slurries. For inter-mediate and production casings, the TXI systemwith DeepCEM additives also was used toreduce transition times and time spent waitingon cement, a key consideration given that itsdeepwater-rig cost was US$250,000 per day.

Selection of a single cementing systemproved to be a key element of successful cement-ing operations for TotalFinaElf. The drilling righad just two cement tanks, so it would have beenimpractical to attempt to use more than one typeof cement. Storing more than one type of cementblend also presents difficulties when storagespace is limited. In addition, logistics at theonshore base would have been much more com-plicated, especially since TotalFinaElf opted tobatch-drill the development wells: the cementingcrew on location was performing cementingoperations approximately once every three days.A single supply vessel operated at capacity todeliver large volumes of drilling fluids, includingcement, for operations in a shallow-water flowenvironment. If more than one cementing systemhad been chosen, the potential for confusion,either at the supply base or on the drilling rig,would have increased.

TotalFinaElf encountered shallow-waterflows in five of the nine Matterhorn wells. Allcementing operations proceeded smoothly, withno remedial cementing required for the casingstrings set and cemented in shallow-flow zones.Leakoff tests (LOTs) of all casing strings wereadequate, allowing TotalFinaElf to drill aheadsafely and without drilling-fluid losses.

During well-completion operations in 2003,TotalFinaElf plans to acquire cement-bond logs tobetter evaluate cement-bond quality and theeffectiveness of zonal isolation. For the timebeing, the company believes that LOT results andROV checks for annular flow at the wellheadsindicate successful cementing operations. As aresult, TotalFinaElf plans to use similar cement-ing technology for future wells.

Additional deepwater cementing technologyis now available to meet the needs for rapid set-ting and prevention of gas migration in cold,

deepwater environments. DeepCRETE deepwatercementing solution technology, with a speciallyengineered particle-size distribution, now is usedto counteract shallow-water or gas flows andlow temperatures, yet requires no special equip-

ment or personnel.31 DeepCRETE systems, whichcan be formulated at densities ranging from 8.0 to 13.5 lbm/gal [959 to 1619 kg/m3], incorpo-rate DeepCEM technology. The particle-sizedistribution makes the slurry easy to pump,

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> 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,” OilfieldReview 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 for Long-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 lowspecific 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.

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46 Oilfield Review

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

32. Excessive heat evolved through chemical reactions ofthe cement-hydration process could melt hydrates nearthe 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 Deepwater Gulf of Mexico,” paper SPE/IADC 79809, presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, February 19–21, 2003.For more on FlexSTONE technology: Abbas et al,reference 29.

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Winter 2002/2003 47

improves set-cement properties such as permeability and durability, and requires lowerconcentrations of gas-migration additives thando ordinary slurries (previous page). DeepCRETEsystems have a lower heat of hydration than ordi-nary Portland cements, which reduces the risk ofcementing in areas with gas hydrates.32 Therange of density adjustments possible at thewellsite is narrower than for foamed cements,but this is often outweighed by such advantagesas rapid transition time, low fluid loss and lowset-cement permeability.

Anadarko Petroleum has been active in thedeep waters of the Gulf of Mexico for severalyears, with approximately 30 wells drilled as of2002. Although their cementing operations usingfoamed cements were successful, Anadarkosought simpler, safer and less expensive alter-natives. Foamed cementing systems requireadditional equipment and personnel, and the use

of energized fluids, like foamed cement, presentssafety and risk-management issues that manyoperators strive to avoid.

Anadarko—the first operator in the Gulf ofMexico to do so—opted to use DeepCRETE slur-ries after seeing laboratory-test results forgel-strength development. Slurries pumped inareas prone to shallow-water or gas flows need todevelop gel strength rapidly. DeepCRETE slurrieswere used for cementing the surface casingstrings in one deepwater exploratory well in the Mississippi Canyon planning area (above).Mixing and pumping operations proceeded asplanned. In the Marco Polo development project inthe Green Canyon area, also operated byAnadarko, five 20-in. casing strings werecemented with DeepCRETE slurries.

Logging tools cannot measure cement qualityin large-diameter wellbore sections, so cement-ing operations in surface casing strings are

evaluated in other ways. In these deepwaterwells, Anadarko observed that returns to themudline were easy to see using an ROV.33 LOTresults were better than expected.

The use of DeepCRETE systems resulted insignificant financial savings for Anadarko. By nothaving a foamed-cementing crew on standby,and then not requiring that crew to wait tocement the second surface casing string, thecompany saved about US$200,000 on theexploratory well. Development wells werecemented as a group, so waiting time for afoamed-cementing crew would have been less,with estimated savings of approximatelyUS$100,000 per well. Drilling in the Marco Polofield incorporates other advanced cementingtechnologies, including FlexSTONE advancedflexible 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).

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Deepwater Cementing Offshore MalaysiaOffshore Malaysia, in the South China Sea,Murphy Sabah Oil Co. Ltd. successfully drilledfive 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 of1300 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 theeffects of temperature on slurry pumpability andcompressive-strength development.

Initially, Murphy considered using foamedcementing systems, but mobilizing the additionalequipment and personnel for these operationsadded unacceptable complications. Ultimately,Murphy selected an optimized lightweightcementing system to meet its stringent require-ments for slurry density, compressive strengthand limited time waiting on cement. TheDeepCRETE system incorporated DeepCEM addi-tives and GASBLOK gas migration control cementsystem additives; the fluid-loss control, zero free

water, lack of sedimentation and short transitiontime contributed to excellent slurry perfor-mance.36 The system exhibited a low heat ofhydration, a key attribute in an area known tocontain gas hydrates.

Surface casing strings for all four wells werecemented successfully, with full returns observedduring all surface casing jobs. LOTs at the surfacecasing shoe also met operator requirements—LOTs were adequate to allow Murphy to drill tothe next designed casing point without having toset 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 (topright) shows the casing and cement configuration.

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Deepwater Cementing Offshore AngolaOther advanced cementing systems are beingused to advantage in deepwater wells. Cement-ing operations for wells in the Girassol field,offshore Angola, are challenging. Discovered byTotalFinaElf in 1996, the Girassol field is a world-class deepwater development that beganproducing oil to a floating production, storageand offloading (FPSO) facility in 2001 (above).37

For the Girassol 119 well in Block 17, theoperator wanted to ensure excellent zonal isola-tion for the Oligocene-age B1 reservoir, whichwould be frac-packed, and the overlying B3 reservoir, which would not be completed inthis well. The well deviated as much as 75° fromvertical and the 121⁄4-in. hole was mostly ingauge, although some localized washouts of

16- to 20-in. diameter were encountered acrossinterbedded shales of the B3 reservoir. Therewere no significant drilling-fluid losses during cir-culation or running of the casing.

The company required a low-density slurry toallow higher displacement rates and accuratecement placement, and good compressivestrength in the set cement to support the frac-pack operation. Using the WELLCLEAN IIsimulator, cementing engineers designed aLiteCRETE slurry and optimized displacementrates within the limits of hole inclination, cen-tralizer placement and equivalent circulatingdensity of the slurry. The significant inclination ofthe wellbore made it difficult to achieve slurryflow around the casing, particularly in the upperpart of the zone because fewer centralizers wereused to limit drag forces as the casing was run.

The cementing operations began with thepumping of MUDPUSH spacer to remove oil-basedrilling mud. A 10.8-lbm/gal [1.3-g/cm3] LiteCRETEslurry followed. The slurry was batch-mixed ratherthan mixed on the fly during cementing operationsto ensure that it had the proper density and slurryquality 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,” supplementto 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).

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TotalFinaElf used the DeepSea EXPRES off-shore plug launching system with a double-plugcementing head system to separate drillingfluids. The DeepSea EXPRES cementing headoffers enhanced reliability because of simplercement-plug design (right). Plugs are releasedfrom the subsea tool without physical contactbetween the darts and the plugs, avoiding dart-to-plug sealing problems. This cementing headreduces rig time because of more efficient,remotely controlled dart release and becausecasing pressure tests can be combined withbumping the top plug.38 Operating companies areexperiencing improved job quality because thereis better cement placement, no fluid contamina-tion and no microannulus. This cementing headalso allowed the operator to test casing immedi-ately after bumping the cementing plug becausethe surface-dart launcher is rated to 10,000 psi[69 MPa], which exceeds the pressure rating ofplugs and float equipment.

The operations proceeded smoothly despiteminor 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 criticalzone from 3375 to 3525 m [11,073 to 11,565 ft]measured depth (next page).

Waves of the FutureConsiderable deepwater activity awaits ourindustry. Deepwater discoveries to date havecontributed approximately 60 billion barrels [9.5 billion m3] of oil to worldwide reserves, yetonly about 25% of deepwater reserves havebeen or are being developed; perhaps as little as5% has been produced.39 In the relatively shorttime that oil and gas companies have exploredand produced in deep water, exploratory successin this frontier has climbed from about 10% tomore than 30% worldwide.40 This increasing suc-cess rate comes at a critical time as the industrycopes with increasing energy demand.

Substantial work remains in deepwater reser-voir characterization. Many deepwater reservoirsturn out to be more complex than initiallythought, 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 wellsand, rarely, cores. Dynamic data, including time-lapse seismic surveys, measurements frompermanent 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 thatthe top cement plug has been placed on the bottom plug 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: Results of the 1998 EAGE/AAPG Research Conference,” AAPGBulletin 84, no. 4 (April 2000): 453–465.

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

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Winter 2002/2003 51

reservoirs and their production. Data from analo-gous reservoirs, either in outcrop or thesubsurface, also guide reservoir interpretations(see “Shallow Clues for Deep Exploration,” page 2).

Unexpected deepwater reservoir complexitycommonly leads to changes in the number or

placement of wells to optimize hydrocarbon recov-ery. Of greater concern to operators, however, arethe unfortunate cases of facilities designs thatturn out to be inadequate to handle actual produc-tion. Improved understanding of deepwaterreservoirs should lead to more accurate production

models and correctly sized production facilities atthe outset of field development.

Turbidite reservoirs are commanding atten-tion from geoscientists, who are devotingparticular attention to such issues as reservoirquality, reservoir continuity and reservoir drive.41

In addition to establishing reliable analog modelsfor future turbidite discoveries, deepwater geoscientists are compiling lessons learnedabout data collection and knowledge sharingthroughout the life of deepwater reservoirs.Naturally, collection and analysis of data involvecrossdisciplinary collaboration.

Most deepwater developments demand sig-nificant cooperation and innovation: no singlecompany can “go it alone.” Canyon Express andprojects like it set a new standard for applicationof deepwater technology. Cooperation in deepwater extends to other impressive projects. Forexample, industry participants invited the USMinerals Management Service, the US CoastGuard and other organizations to join theDeepStar consortium that examines the technicalissues surrounding deepwater operations.42

The DeepStar consortium has been workingsince 1992 to improve technology and operationsand enhance profitability for fields in up to 10,000 ft[3048 m] of water. This group also studies safetyand environmental issues associated with deep-water operations. For example, the Deep SpillsTask Force has studied the potential effects ofblowouts and spills.43 Organizations such as theFoundation for Scientific and Industrial Researchat 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 andrelated equipment, improvements in other tech-nologies facilitate deepwater production.Artificial lift, tool conveyance and flow assuranceare areas of active research and development forservice and E&P companies.

Production from deepwater fields remains anenormous challenge, but the collaborative effortsof E&P companies, service companies andgovernment agencies are making the task lessdaunting 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].