2 Oilfield Review

Solving Deepwater Well-Construction Problems

Gérard CuvillierStephen EdwardsGreg JohnsonDick PlumbColin SayersHouston, Texas, USA

Glen DenyerEEX CorporationHouston, Texas

José Eduardo MendonçaPetrobrasRio de Janeiro, Brazil

Bertrand TheuvenySandsli, Norway

Charlie ViseNew Orleans, Louisiana, USA

For help in preparation of this article, thanks to Alain Boitel,Pointe Noire, Republic of Congo; Alan Christie and AshleyKishino, Rosharon, Texas, USA; Gary Dunlap, Rio de Janeiro,Brazil; Frank Mitton and Robin Walker, Houston, Texas; LesNutt, Fuchinobe, Japan; James Nutter, Macae, Brazil; andDavid Viela, Luanda, Angola.AIT (Array Induction Imager Tool), CDR (Compensated Dual Resistivity), DeepCRETE, INFORM (Integrated Forward Modeling), ISONIC (IDEAL sonic-while-drilling tool), MDT (Modular Formation Dynamics Tester), PERFORM (Performance Through Risk Management) and RFT (Repeat Formation Tester) are marks of Schlumberger.

Deepwater wells are key to the oil industry’s future. Constructing

wells in water depths measured in miles and kilometers requires

new solutions and challenges the industry to perform at its best.

Spring 2000 3

Huge volumes of the world’s future oil reserveslie in deep waters at the very limit of our currentreach, and just beyond. By all indications, tomor-row we will be drilling even deeper. The rapidadvances in deepwater exploration and produc-tion (E&P) methods over the past five yearsensure that as soon as one deepwater record isbroken, another surpasses it.

Operators are drawn to the arena of deepwa-ter exploration by the promise of extensivereserves and high production rates that justify theextra expense and risk. Some deepwater fieldsweigh in above the 2 billion-barrel [320 million-m3]mark, and a single well can produce 50,000 bar-rels per day [8000 m3/d]. At the end of 1998, the28 fields producing from water depths of 500 m[1640 ft] or deeper delivered 935,000 B/D[150,000 m3]. Most of these fields are in the Gulfof Mexico and offshore Brazil, but even moredeepwater discoveries have been made or areexpected offshore West Africa, in the Far Eastand on the North Atlantic margin (near right).Analysts report that worldwide, an additional43.5 billion bbl [6.9 billion m3] have been discov-ered in water deeper than 500 m, with the potentialfor an additional 86.5 billion bbl [13.7 billion m3] (farright).1 Only about half of the deepwater acreageexpected to hold hydrocarbons has been explored.Some estimates suggest that 90% of the world’sundiscovered offshore hydrocarbon reserves hidein water depths greater than 1000 m [3280 ft].2

There are multiple definitions of “deep”water, which vary depending on the activitybeing considered. Generally, for well construc-tion, 1500 ft, or 500 m, is considered deep.Deeper than that, the technology requirementschange but solutions are available. And deeperthan 7000 ft, or about 2000 m, is ultradeepwater. Solutions, if available, are tailored toeach project. Government and regulatory agen-cies may adopt other definitions for deep, suchas beyond the break between continental shelfand continental slope, and confer royalty or tax-ation relief on fields that qualify.

Scientific drilling by groups such as the inter-nationally funded Ocean Drilling Program and itspredecessor, the Deep Sea Drilling Project, hasachieved the astounding water depth of 7044 m[23,111 ft]. However, research holes like this oneare drilled without many of the economic andoperational constraints imposed on the offshoreE&P industry.3

The current water depth record in drilling forhydrocarbons is held by a Petrobras well in 9111 ft[2780 m] of water offshore Brazil.4 The record wasbroken four times in 1999, as the depth increasedfrom 7718 to 9111 ft [2353 to 2780 m]—as manytimes as in the five preceding years, when it pro-gressed from 6592 to 7712 ft [2009 to 2351 m].

The greatest challenges in constructing wellsin deep water are related somewhat to the greatdepths, but also to the conditions encountered ineach deepwater oil province. In the deepestwaters, drilling can be accomplished only fromdynamically positioned semisubmersible rigs ordrillships. Conventionally moored drilling rigshave drilled as deep as 6023 ft [1836 m] in theGulf of Mexico. Conditions offshore West Africacan be substantially different from thoseencountered in the Gulf of Mexico, where thepresence of subsea currents makes drilling-risermanagement more critical. More powerful andlarger rigs are required to maintain station under

1998 1999 2000 2001 2002

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by

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0

100

25

50

75US GulfBrazilWest AfricaFar EastOther regions

> Recent production and the forecast for deepwater fields.(Adapted from Thomas, reference 1.)

1. Thomas M: “Into the Ultradeep,” Deepwater Technology,Supplement to Petroleum Engineer International 72, no. 5(May 1999): 1-3, 5, 7.Moritis G: “Options to Produce Deepwater Oil, Gas to Proliferate,” Oil & Gas Journal 97, no. 50 (December 13, 1999): 69-72.

2. Moritis, reference 1.3. Scientific wells can be drilled without blowout preventers

(BOPs) or drilling risers for mud return, and are not cased or completed. Their aim is to produce information,not hydrocarbons, and, in fact, if hydrocarbons or overpressure are detected, drilling is terminated.

4. DeLuca M: “International Focus,” Offshore 60, no. 1 (January 2000): 10.

0

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> Billions of barrels of discoveredand potential deepwater reserves.(Adapted from Thomas, reference 1.)

high currents and to carry the extra mud volumeand marine riser needed to construct the well. Inaddition, the extreme water depth may also sig-nificantly impact rig downtime. For example, if arig’s subsea blowout preventer (BOP) malfunc-tions, it can take three days just to retrieve it tosurface for repair.

The primary challenge facing deepwater wellconstruction is to drill a stable hole. In youngsedimentary basins with rapid rates of deposi-tion, such as the Gulf of Mexico and parts of off-shore Brazil and West Africa, sediments canbecome undercompacted during burial. Porepressures can be high and fracture gradients lowcompared with those in land wells at the samedepth, and the window between pore-pressureand fracture gradient can be narrow. Safe well-design and control practice requires advanceknowledge of pore-pressure and fracture gradi-ent. Drilling a hydraulically stable hole can beachieved only by keeping drilling mud weightwithin the margin between fracture and pore-pressure gradient. In some projects, so manystrings of casing are needed to control shallowunconsolidated sediments as well as deeperpressure-transition zones that the reservoir can-not be reached. Or, if it is reached, the diameterof tubing that will fit through the final casing isso small as to render the project uneconomicalbecause of restricted flow rates.

In areas such as the Gulf of Mexico, shallowflow hazards make well construction difficult.These zones below the seabed are capable of flowing water and, when encountered by adrill bit, cause severe borehole stability prob-lems. Water-flow zones also impede logging andreentry in open hole and the setting of cementbehind casing.

In the deepest waters, today’s wells are com-pleted with wellheads and production trees onthe seafloor that connect to flowlines for trans-porting hydrocarbons to surface. The surfacestructures may be floating production, storageand offloading (FPSO) vessels or nearby hostplatforms. Controlling live subsea wells for test-ing, completion and intervention requires spe-cially designed, reliable equipment.5 Fluids oftenmust flow through miles of lines and sometimesrely on submersible pumps or other artificial-lifttechniques in order to reach the surface.6 Thewells may be made more productive by implant-ing permanent monitoring and flow-controldevices downhole.7

Keeping fluids flowing at the highest possi-ble rates requires not only adequate tubing size,but also attention to conditions that can lead toother flow blockages. At the high pressures andlow temperatures that deepwater wellsencounter near the seabed, solid, ice-like com-pounds called gas hydrates can form from mix-

tures of water and natural gas. These solids canblock flow in tubulars, and depressurize explo-sively when brought to surface. They have beenresponsible for offshore drilling catastrophes inthe past. Hydrates can also form naturally at andbelow the seabed, creating a drilling hazard ifpenetrated. Other solids such as paraffins mustalso be prevented from blocking flowlines.

To ensure cost-effective, safe and efficientoperations in deep waters, the industry mustdevelop solutions to these and many other prob-lems. In some cases, the solution will be a newtool or completely new technique; in others, aninnovative application of existing technology willprovide the answer. In this article, we describesome of the newly proven methods and promis-ing directions that will permit the continuedexpansion of E&P activities into deeper waters.

Deepwater ExcellenceThe kinds of advances required to break the barri-ers imposed by the great oceans are not of thesort that can be achieved single-handedly, by anindividual or even by a single company. Oil com-panies, service companies, drilling contractors,academic institutions, government groups andequipment manufacturers are all working towardsolutions. Some oil companies are setting up theirown specialized global deepwater drilling groupsto oversee drilling at the deepwater asset level.Many operators and contractors are participating

4 Oilfield Review

Well Construction

Drilling optimization

Riser technology

Alternative vessels

Drilling fluids

Directional drilling

Cementing technology

Geologyand Geophysics

Seismic(marine, borehole)

Ultradeep formationevaluation

Geotechnicalshallow hazards

Reservoir optimization

Alliances R&D CentersOther Centers of Excellence Product Engineering CentersSubsea Engineering

Productionand Intervention

Application of coiled tubing

Subsea tree systems

Directional drilling

Cementing technology•Production systems•Intervention systems•Intervention vessels

Full field development

Floating production systems

Flow assurance

Completion Systems

Completion technologies

Sand-control systems

Perforating

Well testing

Intelligent systems

Zonal isolation

Production equipment

Deepwater Center of Excellence

> Deepwater Center of Excellence organization. The center works to identify technology gaps, prioritize needs and facilitatethe development of solutions to deepwater problems. Four technical domains link with other elements of the Schlumbergerorganization to transfer knowledge.

Spring 2000 5

in industry consortia, initiatives and joint industryprojects to identify technology gaps and pool theirknowledge and resources. Examples of these arethe Deepstar consortium led by Texaco in the US,PROCAP by Petrobras in Brazil, the Atlantic Mar-gin Joint Industry Group (AMJIG) in the UK andthe Norwegian Deepwater Programme.

To address the demand for current and futuredeepwater technical solutions, Schlumberger hasformed the Deepwater Center of Excellence, asolutions center led by experts in Houston, Texas,USA. The center’s mission is to achieve a globalcooperative effort with the industry, focused onidentifying and developing cost-effective, best-in-class solutions to meet deepwater challenges.

The Deepwater Center of Excellence hasdefined specific methods for meeting these objec-tives. First, the organization must recognize exist-ing successful deepwater applications within allthe company’s groups, prioritize needs for newtechnology and propose technical solutions to theengineering centers and clients. Second, internaland external networks have to be established totransfer knowledge and learning. Experts in theDeepwater Center of Excellence manage and fos-ter the development of solutions in one of fourspecific technical domains—well construction,completion systems, production and intervention,and geology and geophysics (previous page).These are aligned with critical well processes andwith current oil-company structures. Finally, thecenter also acts as the Schlumberger representa-tive in deepwater-related joint industry projects tohelp put the acquired knowledge into practice.

Several joint industry projects (JIPs) have beenformed in attempts to overcome a wide range ofdeepwater E&P obstacles. Some projects havebeen established to investigate ways to reducecosts or operate with less impact on the environ-ment, while others are designed to enable activi-ties in deeper water—without them, industry willnot develop the reserves found in ultradeep water.

Drilling Joint Industry ProjectsOne such JIP is a project to design a new methodfor drilling and constructing deepwater wells witha minimum number casing strings so that deepgeological objectives can be reached with a holesize that allows hydrocarbons to be produced athigh flow rates. In the Gulf of Mexico and basinsoffshore West Africa, high depositional ratescause sediments to accumulate rapidly and reachconsiderable depths without compacting, or giv-ing up their pore water. In these weak, unconsoli-dated formations, pore pressures are high andformation fluids must be kept at bay by heavydrilling mud. However, fracture pressures are low;the great distance from the rig to the formationcreates an unbearably heavy column of mud inthe drillstring and riser, and the weight of the mudfractures the formation unless casing is set. Sev-eral casing strings are set in these upper portions

of the well, reducing the number of contingencystrings left available for deeper difficulties, suchas lost-circulation zones, overpressured forma-tions and other well-control incidents. A deepwa-ter well in this kind of formation might cost morethan $50 million and still not reach its objective.

In 1996, 22 companies joined a JIP aimed atremoving the effect of water depth from deep-water well planning and drilling. The group deter-mined that the most viable solution involvedreducing the weight of the mud on the formationby changing the way mud returns to surface (above). The Subsea Mudlift Drilling JIP, nowmade up of representatives from Conoco, Chevron,Texaco, BP Amoco, Diamond Offshore, GlobalMarine, Schlumberger and Hydril, is developingthis technology and remains on track to deliver itto the industry in 2002.

Conventional

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> Conventional (left) and subsea mudlift (right) deepwater drilling technology. In conventional drilling,the weight of the mud column in the riser often is too high to drill without fracturing weak formations.Subsea mudlift technology isolates mud and pumps it back to surface outside the riser to lessen theload, allowing drilling to proceed without fracturing.

5. Christie A, Kishino A, Cromb J, Hensley J, Kent E,McBeath B, Stewart H, Vidal A and Koot L: “Subsea Solu-tions,” Oilfield Review 11, no. 4 (Winter 1999/2000): 2-19.

6. Fleshman R, Harryson and Lekic O: “Artificial Lift for High-Volume Production,” Oilfield Review 11, no. 1 (Spring 1999): 48-63.

7. Algeroy J, Morris AJ, Stracke M, Auzerais F, Bryant I,Raghuraman B, Rathnasingham R, Davies J, Gai H,Johannessen O, Malde O, Toekje J and Newberry P:“Controlling Reservoirs from Afar,” Oilfield Review 11, no. 3 (Autumn 1999): 18-29.Eck J, Ewherido U, Mohammed J, Ogunlowo R, Ford J, Fry L, Hiron S, Osugo L, Simonian S, Oyewole T andVeneruso T: “Downhole Monitoring: The Story So Far,”Oilfield Review 11, no. 4 (Winter 1999/2000): 20-33.

In conventional drilling, the mud columnextends from the rig to the bottom of the well,forming a single mud-pressure gradient (left).The effect of lowering the load in the riser is toreplace the single pressure gradient with a dual-gradient system: a hydrostatic pressure gradientacts from the rig to the seabed, sometimescalled the mudline; a new, higher, mud-pressuregradient acts from the mudline to the bottom ofthe hole. In the dual-gradient system, the pore-,fracture- and mud-pressure gradients becomereferenced to the mudline instead of to the rig(below left).

The decrease in wellbore mud pressure cansave as many as four casing strings in the welldesign (next page, top). The dual-gradient tech-nology allows any well, regardless of waterdepth, to reach its reservoir target with a 121⁄4-in.hole size. The large-bore wells made possible bysubsea mudlift drilling will be able to run 7-in.tubing to the mudline, letting many wells achievetheir highest flow-rate potential. Alternatively,this larger hole size will allow for horizontals ormultilaterals necessary to optimize reservoirdrainage. As a consequence, fewer wells willneed to be drilled to adequately drain a reservoir,resulting in considerable reduction of field devel-opment capital expenditure and greater ultimaterecovery. The lower mud pressure also results infewer well kicks and lost-circulation problems.The JIP estimates these benefits can lead to savings of $5 million to $15 million per well.

There are several ways to reduce the weightof the mud in the drilling riser. The SubseaMudlift Drilling JIP is developing a system withtwo main components. First, a subsea rotatingdiverter isolates the fluid in the riser from thewellbore and diverts the return drilling fluid fromthe base of the riser to the second key compo-nent, a mudlift pump. The mudlift pump directsthe mud back up to the rig in a flowline isolatedfrom the riser and keeps the hydrostatic pres-sure of the mud in the return line from beingtransmitted back to the wellbore.

The system design and preliminary field test-ing will take place in the year 2000 and early2001, and full-scale deepwater tests will follow.The commercial system will be built in 2001 andtested in 2002, opening the way for drilling inhundreds of deepwater leases.

6 Oilfield Review

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<Single-gradient conventional drilling, requiring manycasing strings. When the margin between pore pressureand fracture pressure is narrow, conventional drilling,with its pressure gradient referenced to the rig, requiresfrequent mud-weight increases, accompanied by casingstrings to avoid fracturing.

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<Dual-gradient drilling for fewer casing strings. Becausethe pore-, fracture- and mud-pressure gradients are refer-enced to the mudline rather than the rig, dual-gradientdrilling permits successful well construction with fewercasing strings even when the margin between pore andfracture pressure is slim.

8. Furlow W: “Shell Moves Forward with Dual GradientDeepwater Drilling Solution,” Offshore 60, no. 3 (March 2000): 54, 96.

9. For selected references on pore-pressure estimation: Bowers GL: “Pore Pressure Estimation from VelocityData: Accounting for Pore-Pressure MechanismsBesides Undercompaction,” SPE Drilling and Completion10, no. 2 (June 1995): 89-95.Dutta NC: “Pressure Prediction from Seismic Data: Implication for Seal Distribution and Hydrocarbon Exploration and Exploitation in Deepwater Gulf of Mexico,” in Moller-Pedersen P and Koestler AG (eds):Hydrocarbon Seals: Importance for Exploration and Production, NPF Special Publication, no. 7. Singapore:Elsevier Science, 1997.

Eaton BA: “The Equation for Geopressure Predictionfrom Well Logs,” paper SPE 5544, presented at the SPE Annual Fall Meeting, Dallas, Texas, USA, September 28-October 1, 1975.Hottman CE and Johnson RK: “Estimation of FormationPressures from Log-Derived Shale Properties,” Journal of Petroleum Technology 16, no. 6 (June 1965): 717-722.Pennebaker ES: “Seismic Data Indicate Depth, Magnitude of Abnormal Pressures,” World Oil 166, no. 7 (June 1968): 73-78.

10. Armstrong P and Nutt L: “Drilling Optimization Using Drill-Bit Seismic in the Deepwater Gulf of Mexico,” paper IADC/SPE 59222, presented at the IADC/SPEDrilling Conference, New Orleans, Louisiana, USA,February 23-25, 2000.

Spring 2000 7

Other JIPs are looking into solving the sameproblem in different ways. Since 1996, ShellE&P has been funding and developing a subseapumping system that accomplishes dual-gradient drilling with existing technology wherepossible.8 Several companies, including FMCKongsberg, Alcatel, Centrilift, Dril-Quip and Robicon have participated in the project, whichinvolves subsea separation of larger cuttings sothat electrical submersible pumps can be usedto return mud to surface. Cuttings are left on the seafloor.

Predicting PressuresIn typical sedimentary basins, formations compactas they are buried. Pore fluids are expelled, sedi-ments compact to form consolidated rocks, andpore pressure increases hydrostatically withdepth. In basins with high rates of deposition,such as the Gulf of Mexico, excess fluids can betrapped in low-permeability sediments as theycontinue to be buried. These formations becomeundercompacted and develop overpressure, or

pore pressure greater than hydrostatic. In over-pressured zones, the rock porosity, or some logmeasurement sensitive to porosity, such as sonictraveltime or resistivity, deviates from the normalcompaction trend. These overpressured zones canbe hazardous during drilling. They can cause kicksif they are not detected and require additional cas-ing strings to keep the mud weight within the win-dow between pore pressure and fracture gradient.

Accurate knowledge of pore pressures is akey requirement for safe and economic deep-water well construction. Before drilling, porepressure can be estimated from other properties,such as local seismic velocities, drilling experi-ence, mud weights, and sonic and resistivitymeasurements in nearby wells.9 The worth ofthe pore-pressure prediction depends on thequality of the input data, suitability of themethod used to compute pore pressure and oncalibration with measured pressures. Althoughnot routinely done, the pore-pressure model canbe enhanced by updating it with local calibrationdata from drilling observations, while-drillinglogs and look-ahead vertical seismic profilesusing either surface sources or the drill bit as asource (below).10

> Fewer casing strings and greater bottomhole completion diameter using the dual-gradient method. The lower number of casing strings in dual-gradient deepwaterdrilling (right) compared with conventional drilling (left) saves money and results inlarger diameter tubing at bottom for greater productivity.

Load Project DataSeismic dataOffset well logsOffset well drilling data

Calibration DataMud weightsKicks, lossesRFT, MDT pressures

Pore-Pressure PredictionPore-pressure profile

Inputs to Well PlanCasing seatsMud weightRisksNew data requirements

Revised Well Plan

Stress ModelFracture gradient

Log Data ProcessingPreprocess editingMechanical stratigraphyOverburden stressVp, resistivity profileTime-depth relationship

Seismic ProcessingInterval velocity profile

Real-Time LogsCheck-shot surveyISONIC, gamma ray,pressure whiledrilling data

>Pore-pressure predictionworkflow. Seismic data, pressures and logs help engineers develop an initialpore-pressure prediction andstress model, which in turn helps fine-tune the well plan.Real-time information acquiredwhile drilling can update thewell plan.

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This approach was the key to success in arecent deepwater Gulf of Mexico three-welldrilling project for EEX Corporation. The first wellwas spudded using a preliminary pore-pressureprediction that required updating during thedrilling process. The prediction was updated andcalibrated with kick information.

In the second well, the new pore-pressureprediction technique was applied. Sonic andresistivity logs, mud weights and drilling experi-ence in an offset well helped create the prelimi-nary pore-pressure model. The new well waspredicted to encounter the same geology as the offset well but would not approach the salt that the offset well encountered near 6500 ft [1980 m] until much deeper.

A normal compaction trend appears in theoffset-well sonic logging data down to about8000 ft [2440 m], where a zone of higher thannormal pressure is penetrated (below). The porepressure predicted from the sonic data can becalibrated by actual pressures measured during the drilling process—a kick occurred at5000 ft [1520 m] where pore pressure surpasseddrilling mud weight. After that, drilling proceeded

overbalanced, with mud that was heavier thannecessary. A similar pore-pressure prediction wasmade from resistivity data.

A danger in applying these pore-pressurepredictions in regions of active salt tectonism isthat the measurements made at the offset-welllocation may not be representative of the geol-ogy traversed by the new well, especiallydeeper, in salt-prone sections. The only informa-tion type common to the two sites is intervalvelocity derived from processing the surfaceseismic line that ties the two wells. Seismicinterval velocities produce a much lower resolu-tion pore-pressure prediction, but still serve todefine both a normal compaction trend and apredicted pressure trend to support the predic-tions from other measurements.

The seismic interval velocities over the newwell location, combined with the log-derivedpredictions from the offset well, help constructthe final predrill pore-pressure prediction (nextpage, top). The seismic-derived pore pressuresindicate a narrowing safe mud-weight windowwith depth—less than 2 lbm/gal [0.24 g/cm3] atthe target depth of 20,000 ft [6100 m].

In all three wells, the pore pressures obtainedusing the Schlumberger calibration method accu-rately predicted the pore pressures encounteredin the well. Each well was drilled with the ser-vices of a Schlumberger PERFORM (PerformanceThrough Risk Management) engineer, who moni-tored the drilling process with while-drilling mea-surements and helped update the well plan.11

Refining Predrill Pressure PredictionsAs the previous example shows, offset-well datacan produce a high-resolution pore-pressure pre-diction. However, the prediction may not hold inthe vicinity of the new well. Adding the pore-pressure information from seismic interval veloci-ties provides areal coverage, but interval velocitieshave several drawbacks. They are not of highenough resolution to produce pore-pressure predictions adequate for well-planning purposes.They also are not physical traveltime velocities,but rather are derived from stacking velocities—by-products of seismic data processing that hap-pen to have the units of distance divided by time.They can correspond to actual seismic velocities

8 Oilfield Review

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> Input data from offset well and corresponding pore-pressure predictions. Sonic data, resistivity measurements and seismic velocities eachshow normal compaction trends at shallow levels but deviate deeper. All three data types lead to comparable pore-pressure predictions that arecalibrated by actual pressures encountered when mud weights are insufficient to prevent kicks (black diamond in track 4).

Spring 2000 9

when the subsurface comprises flat homoge-neous layers. However, each velocity value repre-sents an average over the spatial extent of theseismic source and receivers used—often up to8 km [5 miles] in deep water. And interval veloci-ties are not representative of true subsurfacevelocities in the cases of dipping layers, lateralvariations in velocity or pressure, or changes inlayer thickness, exactly the circumstances inwhich one would not be able to rely on offset-well log data and would hope to use seismicdata for pore-pressure prediction.

Schlumberger geophysicists have devised away to extract physically meaningful velocitiesfrom 3D seismic data to derive an enhanced-resolution predrill pore-pressure prediction.12

The technique, called tomographic inversion, incorporates an automated process that usesall the traveltime patterns in the recorded seis-mic data to produce a laterally varying velocitymodel and so an improved pore-pressure pre-diction (below).

11. Aldred W, Plumb D, Bradford I, Cook J, Gholkar V,Cousins L, Minton R, Fuller J, Goraya S and Tucker D:“Managing Drilling Risk,” Oilfield Review 11, no. 2 (Summer 1999): 2-19.

12. Sayers CM, Johnson GM and Denyer G: “Predrill Pore Pressure Prediction Using Seismic Data,” paperIADC/SPE 59122, presented at the IADC/SPE Drilling Conference, New Orleans, Louisiana, USA, February 23-25, 2000.

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> Normal trend observed in seismic interval velocities (track 1) and finalpredrill pore-pressure predictions (track 2) for the new well location.

<A conventional pore-pressure prediction basedon stacking velocities (left) compared with onebased on tomographic inversion (right). The initialprediction has lower resolution, a lower range ofpore pressures and is laterally smoothed. Therefined prediction shows detail that correspondsto subsurface geology accurately.

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The method has been tested on a deepwaterwell project for EEX in the Gulf of Mexico. Anexisting 2D marine seismic survey was repro-cessed using tomographic inversion to generatea refined velocity model for transformation topore pressure (left). The resulting velocity modelhas sufficient detail to derive an accurate pore-pressure prediction away from the offset well tothe south. A drilling trajectory between the twosalt bodies imaged in the seismic line couldencounter a predicted low-velocity zone, whichmay indicate the presence of overpressure. Thespatial extent of this anomaly is not well-definedby the stacking-velocity image. However, theimproved resolution in the tomography-basedvelocities allows a more reliable predrill pore-pressure estimate to be made (next page, top).

10 Oilfield Review

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> Velocity models over existing wells and proposed well location. Interval velocities derived fromstacking velocities (top) do not appear to correspond to the geological interpretation of the seismicline. The interpretation is drawn in fine lines on the image. The refined velocity model constructedusing tomographic inversion (bottom) corresponds to subsurface salt features interpreted in seismicsection and contains enough detail to produce an accurate pore-pressure prediction.

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Overburdenstress gradient

Overpressurepredictions

> Pore pressures predicted in the vicinityof the proposed well location and thelow-velocity zone indicated in the seismicvelocity model. The prediction shows anincrease in pressure at about 7600 ft[2320 m].

Spring 2000 11

The proposed well location is in the vicinityof the low-velocity zone, and the pore-pressureprediction shows a corresponding jump in pres-sure at about 7600 ft [2320 m] (previous page,right). The predicted pore pressures are in goodagreement with the actual mud weights subse-quently used to drill the well.

Deepwater Drilling SolutionsA variety of other problems can hinder the well-construction process in deep water. The followingexamples illustrate some of the latest solutions.

Wellbore stability—Cooling of the drillingfluid in the riser can cause higher mud viscosity,increased gel strength and high frictional pres-sure losses. These factors increase the likeli-hood of lost-circulation problems, and drillingengineers must take appropriate steps to avoidexceeding formation fracture pressures. Real-time measurement of annular pressure whiledrilling helps monitor the equivalent circulatingdensity (ECD) of mud to allow drillers to keepwithin the narrow stability window found inmany deepwater holes. Equivalent circulatingdensity is the effective mud weight at a givendepth created by the combined hydrostatic anddynamic pressures.

Real-time monitoring of annular pressurewhile drilling helped during construction of adeepwater well in the Gulf of Mexico (below).13

Mud weight was just below the pore pressurepredicted from seismic interval velocities whena kick occurred in Zone A. Mud weight wasincreased to control the well and 133⁄8-in. casingwas set. The next two hole sections were drilledwithout incident, then another kick was taken inZone B, so 9 5⁄8-in. casing was set to permitanother increase in mud weight. The heaviermud exceeded overburden pressure and somelost circulation was experienced in Zone C, butdrilling continued successfully thereafter.

Dept

h, ft

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2000

4000

6000

8000

10,000

12,000

14,000

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pre

ssur

e, lb

m/g

al

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10

11

12

13

14

15

16

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8000 10,000 12,000 14,000 16,000 18,000 20,000

Zone A

Zone B

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20

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16

13 3/8

113/4

9 5/8

Kick

Kick

7 5/8

Overburden gradient, lbm/gal

Resistivity pore pressure estimate, lbm/gal

ECD, lbm/gal

Seismic pore pressure estimate, lbm/gal 1710

> Real-time annular pressure while drilling measurements indicating when effective circulating density (ECD) begins to fall outside the margin between pore pressure and fracture pressure. When ECD is too low, pore pressure causes kicks. Increasing mud weight may control the well, but if the margin between pore and fracture pressure is narrow, casing must be set to accommodate the heavier mud.

13. Aldred W, Cook J, Bern P, Carpenter B, Hutchinson M,Lovell J, Rezmer-Cooper I and Leder PC: “Using Down-hole Annular Pressure Measurements to Improve DrillingPerformance,” Oilfield Review 10, no. 4 (Winter 1998): 40-55.

> Two-dimensional predrill pore-pressure predictiondeveloped from a tomography-based velocity model.

Water-flow zones—Since 1987, operatorshave reported hazardous water flows in 60 Gulfof Mexico lease blocks involving 45 oil and gasfields.14 These abnormally pressured formationsare usually sands caught in quickly slumping androtating fault blocks or in reworked channelssealed by impermeable clay. Water flows havebeen reported between 800 and 5500 ft [244 to1680 m] depth below the seafloor. A flow maycontain gas and may develop solid gas hydratesin and near seabed equipment. Uncontrolledwater flow can lead to formation cave-in, and ifinflux is severe enough, the well can be lost.Washouts can undermine the large casing, orconductor pipe, that is the main support struc-ture for the well.

The industry spends an average of $1.6 mil-lion per deepwater well for the prevention orcorrection of problems associated with shallowflows.15 A combination of techniques is used tocombat the problem, including acquiring mea-surements while drilling, setting extra casing,drilling pilot holes, using a riser and pumpingspecial cements. The while-drilling measure-ments—by far the least expensive of thesteps—are designed to identify water-flowzones as soon as they are encountered.

Operators have started to use real-timeannular pressure measurements to detect water-flow zones. An example comes from deepwaterGulf of Mexico, where a water-flow zone wasidentified on gamma ray, resistivity and annularpressure while drilling logs (right).16 The jump inequivalent circulating density indicated possibleinflux of solids. Visual confirmation of water flowwas confirmed by remotely operated video at theseafloor. Mud weight was increased to controlthe flow, and drilling continued. Similar flowzones were detected within the next few hun-dred meters. All the water-flow zones weresafely contained. Early warning of water influxprovided by the real-time measurements made itpossible to keep on drilling to the planned depth.

Deepwater cementing—Water flows alsopresent problems during cementing operations.Water influx can keep cement from solidifying,jeopardizing the integrity of the well. A deep-water consortium including Schlumberger andseveral oil companies sought to formulate acement for deepwater wells that would be able

to hold up against water flows but also be lightenough not to fracture weak formations. The keywas to find a cement with a short transitiontime—the period when it changes from a liquidto a solid—to minimize the interval during whichits strength is too low to hold back water flow.

A foamed deepwater right-angle set (RAS)slurry was the solution. The deepwater RAS hasthe requisite short transition time and early com-pressive strength and thus prevents any waterflow from penetrating the cement bond. As afoam, the cement density can be modified withnitrogen injection during mixing to create aslurry that is light enough to avoid fracturingweak deepwater formations.

The deepwater RAS cement has helped stopwater flow and provided successful cement jobsin more than 50 deepwater wells, even atrecord-breaking depths. This includes cementingthe conductor and surface strings for theChevron Atwater 18 #1 well in 7718 ft [2352 m]of water in the Gulf of Mexico.

Foamed cement requires a nitrogen supply, spe-cialized equipment for injecting it, and a cementingteam trained in its use—all of which may be challenging to coordinate on a deepwater rig.

12 Oilfield Review

Dept

h, m

Attenuation resistivityGamma ray0

A

150 0 10 8 9

500 0 0 10 2000 3000

0 2 50 100

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Phase-shift resistivity

ECD

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Rate of penetrationft/hr

lbm/galohm-mAPI

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> Detecting water-flow zones in deepwater wells with annular pressure while drillingmeasurements. Three water-flow zones A, B and D (light blue highlight) were identifiedwith the help of the while-drilling data. In each case, increasing the mud weight successfully controlled the flow, and drilling continued to total depth.

Conventionalcement 68

DeepCRETEcement 11

0 25 50 75

Setting time, hr

Spring 2000 13

An alternative to foamed cement, DeepCRETEtechnology, has been developed for such deep-water wells. DeepCRETE cement strengthensquickly even at temperatures as low as 4°C[39°F], reducing waiting-on-cement times.17

Operators offshore Angola, Africa report signif-icant savings with DeepCRETE cement for wellconstruction in deepwater areas, where the low-temperature environment causes long settingtimes and ordinary cements suffer from losses dueto the low fracture gradient. In one case, using aconventional cement in a well with a bottomholecirculating temperature of 12°C [54°F], the 15.8-lbm/gal [1.89-g/cm3] slurry exceeded the fracturegradient at the seabed. It took 68 hours to achievethe first 500-psi [3.4-MPa] setting. In the secondcase, with DeepCRETE cement, a 12.5-lbm/gal[1.5-g/cm3] slurry set in 11 hours with no evidenceof cement loss to fracturing (right). The 57-hourreduction in rig time translated to savings of$475,000.

Reservoir evaluation—Difficulties in deep-water well construction manifest themselvesagain later as challenges in formation evalua-tion. Low fracture gradients and water-flowzones cause washouts and inadequate cement-ing, leading in turn to adverse hole conditionsfor logging. Logging-while-drilling (LWD) mea-surements help obtain formation-evaluationinformation before hole conditions deteriorate.This technique has been successful in therapidly growing market offshore Angola, wheredeepwater production is projected to reach 1.38million B/D [219,000 m3/d] by the year 2005 (right).18 In a well drilled in 1200-m [3940-ft]

14. Minerals Management Services, US Department of Interior. http://www.mms.gov. andhttp://www.gomr.mms.gov/homepg/offshore/safety/wtrflow.html

15. Alberty M: “Cost Analysis of SWF Preventative, Remedial Measures in Deepwater Drilling,” Offshore 60,no. 1 (January 2000): 58, 60, 62, 64.

16. Aldred et al, reference 13.17. Boisnault JM, Guillot D, Bourahla B, Tirlia T, Dahl T,

Holmes C, Raiturkar AM, Maroy P, Moffett C, Mejia GP,Martinez IR, Revil P and Roemer R: “Concrete Develop-ments in Cement Technology,” Oilfield Review 11, no. 1(Spring 1999): 16-29.

18. “Kuito Kicks off for Angola,” Offshore Engineer 24, no. 10(October 1999): 26-28.

> Faster setting DeepCRETE cement for controlling water flow and savingrig time. In this deepwater offshore Africa example, a conventionalcement system exceeded the fracture gradient at the seabed and took68 hours to set. The DeepCRETE cement, a less dense slurry, set in 11hours with no fracturing.

ANGOLA

ZAIRE

CONGO

GABON

NAMIBIA

EQUATORIALGUINEA

CAMEROON

AFRICA

> Offshore Angola, where production from deepwater wells is estimated togrow to 1.38 million B/D in five years.

deep water offshore Angola, CDR CompensatedDual Resistivity tool measurements were madeto determine casing and coring points (left).After drilling several hundred meters into thereservoir with oil-base mud (OBM), substantialmud losses were incurred. These were believedto originate at the bottom of the hole. WirelineAIT Array Induction Imager Tool measurementsrun seven days later, after mud losses totaled300 m3, showed a completely different logresponse between about X050 and X130 m com-pared with the earlier CDR results. Increasedvalues of wireline resistivity indicated the shalesection had been altered and possibly fracturedby the OBM.

Similar cases often have been documentedin the past, but less common with OBM is thereversal observed in the order of the AIT curves.Here, the deeper reading AIT resistivities exhibithigher values than the near-reading ones. Tounderstand these results, Schlumberger engi-neers modeled the formation, fracture and mea-surements using INFORM forward modelingsoftware. Different fracture openings and rela-tive angles of intersection with the boreholewere tested to find the conditions under whichthe observed reversal of the AIT curves wouldoccur (next page, top). The INFORM modelingshowed that a fracture dipping at 75° can repro-duce the order of the AIT readings.

Constructing Productive WellsAchieving optimal hydrocarbon production fromdeepwater wells requires special attention to flowassurance. Assuring flow is a multidisciplinaryeffort, covering issues from asphaltene depositionand hydrate formation to hydrocarbon flow proper-ties and flowline reliability. Any potential problemthat could hinder flow from the reservoir to theproduction export vessel or pipeline falls under theheading of flow assurance.

Offshore Brazil and elsewhere, deepwaterdevelopment layouts have been constrained byreservoir pressures. Reservoir pressure controlledthe distance that could be tolerated between welland platform without critical flow loss. Pressuredecline could be combated by water injection, orbackpressure could be reduced by gas lift. How-ever, gas-lift efficiency suffers in wells with thelong horizontal tie-backs typical of subsea com-pletions. Sustaining oil production from thesedeepwater subsea wells requires new solutionsto increase flow rates, simplify production facilitylayouts, decrease the number of platforms and

14 Oilfield Review

CDR-attenuation

CDR-phase shift

AIT 10

AIT 30

AIT 60

AIT 90

Gamma Ray0 150API 0.2 2000ohm-m

Dept

h, m

X050

X100

X150

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> Comparison between while-drilling logs from the CDR Compensated Dual Resistivity tool and wirelinelogs from the AIT Array Induction Imager Tool series. The AIT curves acquired after significant mudloss exhibit indications of alteration and fracturing between X050 and X130 m. However, the order ofthe curves, with deeper reading measurements seeing higher resistivity, seemed unusual for invasionby oil-base mud.

SOUTH

AMERICA

AlbacoraAlbacora East

Roncador

Marlim

Marlim South

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Campos

Vermelho

PargoCarapeba

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1000

m

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B R A Z I L

> Offshore Brazil, the site of the deepwater subsea electrical submersible pump test.

Spring 2000 15

reduce investments and operating costs. Severalsolutions are being investigated, including down-hole boosting, subsea multiphase pumps and sub-sea separation.

Downhole pumps—In 1992, the PetrobrasPROCAP program initiated a project to developthese boosting technologies. The downholeboosting method was the first to reach the fieldin deepwater offshore Brazil, in the form of theelectrical submersible pump.19 Petrobras alreadyhad significant experience with electrical sub-mersible pumps on fixed towers in shallowerwater and in dry completions onshore. In oneoffshore development from eight fixed towers inthe area comprising the Carapeba, Pargo andVermelho oil fields of the Campos basin, 132wells produce with these pumps (right).

For use of electrical submersible pumps to befeasible in the deepest water, the pumps wouldneed to assure flow through extended tie-backsto surface facilities. It was important to test theviability of the method in shallow water beforeinvesting in the development of a deepwater sys-tem. Six other companies cooperated in thedevelopment and installation of the system: Redaand Lasalle (both now part of Schlumberger),Tronic, Pirelli, Cameron and Sade-Vigesa. A Redapump was installed in subsea well RJS-221,powered from the Carapeba 1 fixed tower 1640 ft[500 m] away. From there, with only the energyfrom the pump, production flowed to the Pargo 1platform 8.4 miles [13 km] away. The pump wasput into operation in October 1994 and func-tioned for 34 months before a failure occurred.

19. Mendonça JE: “Electrical-Submersible-Pump Installationin a Deepwater Offshore Brazil Well,” Journal ofPetroleum Technology 50, no. 4 (April 1998): 78-80.Mendonça JE: “Deepwater Installation of an ElectricalSubmersible Pump in Campos Basin, Brazil,” paper OTC8474, presented at the 1997 Offshore Technology Confer-ence, Houston, Texas, USA, May 5-6, 1997.

AT90AT60AT30AT20AT10

AIT curves

1 cm

Relative angle = 75°

Shale resistivity, 0.5 ohm-m

Fracture resistivity, 1000 ohm-m

AIT-

H, o

hm-m

10,000

1000

100

10

1

0.1-20 -10 0 10 20

Offset from fracture, cm

<Forward modeling of AIT response to inclinedfracture. INFORM forward modeling showed thata fracture dipping at 75° can reproduce theobserved order of the AIT curves.

The installation in RJS-221 demonstratedexcellent longevity compared with dry-completioninstallations, and proved the method for subseause. This encouraged Petrobras to develop thetechnology further for deep water. The deepwatertest site, well RJS-477, in the East Albacora oilreservoir is in 3632-ft [1107-m] deep water. InJune 1998, as a result of the pump installation,RJS-477 began to produce to Albacora field Platform P-25, moored 4 miles [6.4 km] away in1886 ft [575 m] of water (above). The power sys-tem has been developed for a range of 15 miles[24 km], which will allow, for example, Camposbasin wells within the 3775-ft [1150-m] water-depth mark to produce to high-capacity facilitiesmoored or fixed in shallower water.

The electrical submersible pump is the key tothe success of the new method.20 High interven-tion costs in deep water mean that equipmentreliability and longevity are crucial. Integrationof the completion system with electrical sub-mersible pump equipment is fundamental, andshould be addressed in the planning stages ofdeepwater wells. Both of the wells involved inthe test, RJS-221 and the deepwater RJS-477,were drilled to test new reservoirs before elec-trical submersible pumps were considered forthese subsea wells and so were not designed toaccommodate a submersible pump. Restrictionsin the liner and casing size in RJS-477 presentedchallenges to the design of the pump system.

For the deepwater electrical submersiblepump installation, new equipment was devel-oped for the extreme water depth and long-distance power transmission. This included theReda pump; Pirelli subsea power cables; Tronicsubsea power connectors; subsea power trans-former and long-distance power transmission bySiemens; and the deepwater horizontal produc-tion tree by Cameron.

This deepwater prototype has so far com-pleted two years of run-life with no failures.Petrobras considers the system to be proven toits design limits.

Subsea boosting—Statoil, BP Amoco, ExxonMobil and Petrobras have investigated thepossibility of deploying subsea multiphaseboosting pumps as an alternative to subsurfacedownhole pumping. This option becomes attrac-tive when the production from a large number ofwells can be commingled subsea and boostedfrom a production manifold or when the flowingpressure in the reservoir drops below the bub-blepoint. Deploying multiphase pumps on theseafloor, closer to the reservoir than if deployedat the sea surface, permits the efficient additionof pressure head to the flow and allows for ahigh-power system.

The equipment was first deployed in Decem-ber 1997 in the Lufeng field operated by Statoil inthe South China Sea (below). Five multiphaseboosting pumps manufactured by Framo Engi-neering were installed in 330 m [1082 ft] of water

16 Oilfield Review

Mooredproductionplatform

Power cableand flowline

Subseawellhead

Electricalsubmersiblepump

Perforations

> Subsea electrical submersible pump sending production from Well RJS-477 in 3632-ft[1107-m] deep water to Albacora field Platform P-25, four miles away in shallower water.

> Deploying a multiphase boosting pump in theLufeng field, South China Sea.

Spring 2000 17

Deepwater WaveAlong with increases in recovery percentages inexisting fields, deep water is one of the indus-try’s main hopes for balancing supply anddemand from the year 2005 onward. To realizethis hope, technological solutions and projectmanagement methods must result in perfor-mance levels that will allow deepwater projectsto compete economically with other sources ofoil and gas. The industry is making measurableprogress in this direction. In the 1980s producinga barrel of oil from a well in 200 m [656 ft] ofwater cost between $13 and $15 for an averagefield. Now technological advances have reducedthat figure to $5 to $7.21

The way forward into deeper water willcome from many directions. Beyond some depth,all production will be from subsea develop-ments. Advances in subsea flowlines, productiontrees, electrical power distribution systems, fluidseparation and reinjection technology and multi-phase metering and pumping will be necessaryto derive economical production from the10,000-ft [about 3000-m] water depths that soonwill be explored. These advances will allow thesubsea industry to move an increasing amountof activity to the seabed.

Deepwater and other offshore wells thatundergo well testing produce fluids that need tobe transported or otherwise disposed of, raisingenvironmental and operational safety concerns.Schlumberger is participating in a joint industryproject with BP Amoco, Conoco and Norsk Hydroto examine the feasibility of well testing withoutproducing hydrocarbons to the surface. The pro-ject will investigate technology to circulate flu-ids through a downhole testing system. The sys-tem will acquire pressure and flow-rate datadownhole rather than at the surface withouthaving to flare hydrocarbon fluids or transportcollected liquids for remote disposal. The resultwill be improved operational safety and reducedenvironmental impact.

The industry recognizes that deep watershold a key to its future survival and success.Diverse new technologies have brought explo-ration in deep and ultradeep water within thegrasp of oil companies. As we go further anddeeper, we are sure to find new challenges andopportunities. —LS

20. Reda has installed 100% of the world’s subsea electricalsubmersible pumps.

21. Thomas, reference 1.

(above left). Since then, the pumps have liftedmore than 50 million barrels [8 million m3] of liq-uid. Pump operations have been trouble-free. TheFPSO Navion Munin can perform intervention on the subsea pump using its own crane, thusallowing for cost-effective retrieval if needed.

Another deployment of multiphase pumps isunder way in the Topacio field offshore EquatorialGuinea, where ExxonMobil is running two Framopumps in more than 500 m of water to boost pro-duction from a satellite field (above right).

Other subsea developments that producefrom multiple wells may require a subsea multi-phase flowmeter. Framo Engineering has devel-oped a subsea multiphase flowmeter that allowstesting of individual wells. This type of solutionwas selected by BP Amoco for their develop-ment of the Machar field. A separate subseamodule allows the boosting of the multiphaseproduction once the wells water-out.

Application of these solutions to developmentsin deeper water will eventually allow for more cost-effective tie-backs than are currently achievable.

Subsea separation—Several companies areinvestigating concepts in subsea fluid separa-tion. Separating fluids subsea will avoid liftinglarge volumes of water all the way to surface forprocessing and disposal. This can reduce liftingcosts and allow economies in topside water pro-cessing and handling capacities. The savingsmay extend the economic life of deepwater pro-jects and reduce development risks.

Framo subseabooster pumps

> Five subsea multiphase booster pumps in the Statoil development of the Lufeng field.

> The subsea multiphase boosting pump built for the ExxonMobil operation in the Topacio field, offshore EquatorialGuinea.