The Pressures of Drilling and Production

22 Oilfield Review

The Pressures of Drilling and Production

Yves BarriolKaren Sullivan GlaserJulian PopSugar Land, Texas, USA

Bob BartmanDevon EnergyHouston, Texas

Ramona Corbiell New Orleans, Louisiana, USA

Kåre Otto EriksenHarald LaastadStatoilStavanger, Norway

James LaidlawAberdeen, Scotland

Yves ManinClamart, France

Kerr MorrisonBP Exploration and ProductionAberdeen

Colin M. SayersHouston, Texas

Martin Terrazas RomeroPetróleos Mexicanos (PEMEX)Poza Rica, Mexico

Yakov Volokitin Shell E & P AmericasNew Orleans, Louisiana

For help in preparation of this article, thanks to Jeff Corderaand Aaron Jacobson, Clamart, France; Roger Goobie,Houston, Texas; Jose de Jesus Gutierrez, Mexico City,Mexico; Martin Isaacs, Frederik Majkut and Lorne Simmons,Sugar Land, Texas; and Paula Turner, independentconsultant, Houston.adnVISION675, AIT (Array Induction Imager Tool),arcVISION675, CHDT (Cased Hole Dynamics Tester), CQG (Crystal Quartz Gauge), FloWatcher, MDT (ModularFormation Dynamics Tester), Platform Express, PowerDriveXtra, PressureXpress, proVISION675, Sapphire, SmartPretest, StethoScope, TeleScope, USI (UltraSonic Imager),VISION and WellWatcher are marks of Schlumberger.

Pressure measurement is essential to optimized hydrocarbon recovery. Now,

accurate formation pressures can be determined at almost any time in a well’s life

cycle. Whether while drilling, when the well is at total depth, or years after initial

production, accurate, cost-effective pressure data can be acquired to help reduce

risk and improve recovery.

Many everyday pressure effects go unnoticed. Weseldom consider why water flows from a tap orhow an airplane flies. And certainly, while fuel-ing the family automobile, the nature ofgeopressures that drive hydrocarbons to the surface is far from our minds. Our world relieson pressure in many ways, not the least of whichis the production of oil and gas.

The story of geopressure is rooted in theEarth’s beginning. As the molten outer core ofthe Earth cooled, plate-tectonic movementsdriven by convection within the Earth generatedstresses in the crust. Movement, warping andbuckling of these stressed crustal plates caused

mountains and basins to form. Volcanic eruptionsassociated with plate-tectonic forces spewedmaterial from within the Earth, forming theatmosphere and oceans.

As plate-tectonic activity continued toinfluence subsurface pressure conditions, weatherpatterns formed. Cycles of oceanic evaporation,atmospheric saturation, condensation and inlandprecipitation fueled rivers that run to the oceans,carrying with them large amounts of eroded rockand terrigenous and marine organic material. Asthe transport velocity slowed, these materialssettled in depositional basins (below). Later,during continued burial and compaction, these

> The hydrologic cycle. Evaporation of water from the ocean forms clouds. These clouds drift overthe land and produce rain that flows along rivers back to the ocean, carrying with it rock and organicdebris that accumulates in basins. The cycle repeats, depositing massive layers of material.

Evaporation

FlowParticle transport

Sedimentation

OceanLakeSurface runoff

Condensation

Precipitation

Water table

Bedding

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Nowhere

Nothing

materials were transformed by heat, pressure andorganic activity into the many hydrocarboncompounds we know as petroleum.

Thus begins the story of geopressure,hydrocarbons and production. In this article, wefirst review the development of geopressuredsystems, and then discuss the effects offormation pressure on drilling, evaluation,production and recovery of hydrocarbons. Casehistories from the Gulf of Mexico, Mexico and theNorth Sea show how drillers, engineers andgeoscientists are using advanced techniques to

predict, measure and manage pressure, allowingwells to be drilled more safely, boreholes to beplaced more accurately, and reservoir contentsto be evaluated and managed for maximum oiland gas recovery.

Development of Geopressured Systems The Earth’s outer crust hosts a complex system ofstresses and geopressures that constantly seekequilibrium. Although the subsurface comprisesmany geologic features in different pressure andstress regimes, one of the most commonly

studied subsurface pressure distributions occursin relatively shallow sediments, laid down indeltaic depositional environments. Rivers washlarge amounts of sand, silt and clay into offshorebasins where they accumulate, are lithified overmillions of years and form primarily sandstone,siltstone and shale.

Initially, the sediments deposited at themouths of rivers are unconsolidated anduncompacted, with relatively high porosity andpermeability that allow remnant seawater, orconnate water, in the pores to remain in fullhydraulic communication with the ocean above.With time and compaction as more sediment isdeposited, water is squeezed out of pore spacesand grain-to-grain contact supports more andmore of the depositional load. Provided there is aconduit for the water to escape, pressureequilibrium is maintained in the pore spaces.

Once formed, oil and gas migrate upward tozones of lower pressure, possibly reaching thesurface to form seeps if there is no mechanicalblockage along the way. Geological andarcheological evidence shows that hydrocarbonseeps have occurred naturally in various parts ofthe world for thousands of years. In some cases,subsurface pressures drive large volumes ofhydrocarbons to the surface. Along the Californiacoast near Goleta Point, USA, commercialvolumes of natural gas continue to escape fromnatural fractures in the Earth’s crust. Hereengineers designed a unique underwater gas-recovery system, capturing more than4,000 million ft3 [113 million m3] of natural gassince 1982. This is enough natural gas to supplythe annual needs of more than 25,000 typicalCalifornia residential consumers.1

Seeps generally occur where erosion exposeshydrocarbon-bearing rocks at the Earth’s surface,or where a fault or fracture allows pressure-drivenhydrocarbons to migrate to the surface. Historicalrecords indicate that surface seepage led to thediscovery of many petroleum deposits.2 Today,aerial and satellite imagery helps geologistsdetect natural oil and gas seeps migrating fromgreat ocean depths, offering the promise of yetundiscovered hydrocarbon reserves (left).

Fortunately, most subsurface hydrocarbonsdo not leak to the surface. As oil and gas migrateupward, they typically become trapped beneathlow-permeability layers, or seals. These seals mayconsist of many rock types, including shales,calcareous shales, well-cemented sandstone,lithified volcanic ash, anhydrite and salt.

Hydrocarbon traps are frequently groupedaccording to the geologic processes that causethem, such as folding, faulting and structural

24 Oilfield Review

> Seepage identified offshore Angola, West Africa. About 75% of the world’spetroliferous basins contain surface seeps. Knowing where oil and gas seepsare emerging is helpful in locating the sources of subsurface oil and gasaccumulations. Scientists use satellite imagery to help identify potentialhydrocarbon reservoirs. In this image, free-air gravity values derived fromEuropean Remote-Sensing Satellite (ERS) data identify areas of high gravityresulting from sediment emitted from the Congo River, known as the CongoFan. The data are also used to help identify areas of hydrocarbon seepageshown as red-outlined contours. The subsea seep source is typically locatedusing sonar or shallow seismic reflection. The hydrocarbons can then besampled, helping to identify oil type and field maturity and to correlate withother subsea seeps. (Image courtesy of NPA Group; Archive block outlinescourtesy of IHS Energy.)

Congo fanfree-airgravity

Seep clusters

Bathymetrycontours

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changes caused by plate-tectonic activity or theplastic deformation of salts or shales (above).Many hydrocarbon traps involve combinations ofstructural and stratigraphic features, but oncetrapped beneath a seal, reservoir fluids have nohydraulic communication with the surface. Giventime and the right circumstances, pressureincreases in the rock pore space (see “Causes ofAbnormal Pressure,” page 26).

Early Oil and the Uncertainty of PressureSometime before 200 BCE, the Chinese relied ongeopressure to help produce the first gas wells.3

Other records indicate that as early as 1594, nearBaku, Azerbaijan, shallow pits or wells were dugby hand to depths of 35 m [115 ft], making thisarea the first actual oil field.4

In the USA, the history of drilling prior to the19th Century is unclear, although seep-oil use isnoted in numerous early historical accounts. In1821, drillers completed the first well in the USAdesigned specifically to produce natural gas. Thiswell, in Fredonia, New York, USA, reached adepth of 27 ft [8.2 m] and produced enough gas,driven by natural pressure, to light dozens ofburners at a nearby inn. Then, Edwin L. Drakedrilled an exploratory well in 1859 nearTitusville, Pennsylvania, USA, to locate thesource of an oil seep.5 At a depth of 69.5 ft [21 m],drillers pulled their tools from the well. Within

24 hours, geopressure effects forced oil up theborehole. Fortunately for Drake, oil seeps in thearea precluded abnormal pressure buildup.Using a manual pump, drillers produced about25 bbl/d [3.9 m3/d] of oil. Although productionsoon dropped to around 10 bbl/d [1.5 m3/d], thewell is said to have continued producing for ayear or more.6

By the early 1900s, drillers, geoscientists andengineers recognized the importance of geo-pressure in oil and gas production. TheSpindletop discovery, which blew out duringdrilling near a salt dome at 1,020 ft [311 m],produced around 800,000 bbl [127,120 m3] of oilin eight days and provided scientists withinsights into salt dome-related abnormalgeopressure effects.7

As drilling activity increased, explorationreached into new and uncharted territories.Remembering the uncontrolled oil gushers of thepast, drillers were constantly on the lookout forabnormal geopressures. Engineers and scientistsbegan to seek new ways to predict abnormalpressures during the search for oil.

At around the same time that Drake drilledhis first well, seismic instruments were beingdeveloped and used to record and measure Earthmovements during earthquakes. Researchersdeveloped the technologies that form the basis ofreflection seismology. In reflection seismology,

subsurface formations are mapped by measuringthe time it takes for acoustic pulses transmittedinto the Earth to return to the surface after beingreflected by geological formations with varyingphysical properties.8 Over time, seismic tech-nology moved into the oil field, providinggeophysicists, geologists and drilling engineerswith the tools to evaluate reservoirs and pressureregimes long before drilling a well.

Although early geopressure estimations fromseismic image analysis were crude, drillersneeded predrilling pressure estimates for mud-weight selection, casing design and well-costestimation, among other uses. Engineers foundearly pressure estimates too uncertain,especially in complex oil and gas reservoirs. Tomore easily understand and visualize thegeopressure environment, geoscientists now usesophisticated seismic data acquisition andprocessing techniques, mechanical earth modelsand pore-pressure cubes to study, evaluate andvisualize pressure environments within a givenbasin or area.

Engineers use reflection tomography thatyields higher spatial resolution than conven-tional seismic techniques to accurately predictpore pressure from seismic data. This highresolution also helps differentiate variations inpore pressure from variations in lithology andfluid content.9

> Structural traps. The weight of overlying sediments causes salt layers to plastically deform, creating diapirs. As diapirs evolve, sediments onlap theirmargins, forming traps that typically accommodate hydrocarbons (left). Where the strata have deformed to form an anticline (center), oil (green) and gas(red) may become trapped under a seal. Faulting may also trap hydrocarbons (right) by sealing the updip margin of a reservoir.

Gas

Oil

Salt water

1. Natural Oil and Gas Seepage in the Coastal Areas ofCalifornia; U.S. Department of the Interior, MineralsManagement Service. http://www.mms.gov/omm/pacific/enviro/seeps1.htm (accessed October 8, 2005).

2. For more on seeps and oil exploration:http://www.npagroup.co.uk/oilandmineral/offshore/oil_exploration/ (accessed October 8, 2005).

3. Brufatto C, Cochran J, Conn L, Power D, El-ZeghatySZAA, Fraboulet B, Griffin T, James S, Munk T, Justus F,Levine JR, Montgomery C, Murphy D, Pfeiffer J,Pornpoch T and Rishmani L: “From Mud to Cement—

7. For more on the history of the Spindletop oil field:http://www.tsha.utexas.edu/handbook/online/articles/SS/dos3.html (accessed October 8, 2005).

8. For more on the evolution of seismic technology:http://www.spe.org/spe/jsp/basic/0,1104_1714_1004089,00.html (accessed October 8, 2005).

9. Sayers CM, Woodward MJ and Bartman RC: “SeismicPore-Pressure Prediction Using Reflection Tomographyand 4-C Seismic Data,” The Leading Edge 21, no. 2(February 2002): 188–192.

Building Gas Wells,” Oilfield Review 15, no. 3 (Autumn 2003): 62–76.

4. For more on the chronology of oil events: http://www.sjgs.com/history.html#ancient_to_present (accessedOctober 8, 2005).

5. For a chronology of oil- and gas-well drilling inPennsylvania: http://www.dep.state.pa.us/dep/deputate/minres/reclaiMPa/interestingfacts/chronlogyofoilandgas (accessed October 8, 2005).

6. Yergin D: The Prize. New York City: Simon & Schuster, 1992.

(continued on page 28)


Causes of Abnormal Pressure

Normally pressured formations generally have pore pressure that equals the hydrostaticpressure of the pore water. In sedimentarybasins, pore water usually has a density of8.95 lbm/galUS [1,073 kg/m3], whichestablishes a normal pressure gradient of0.465 psi/ft [10.5 kPa/m]. Significant deviationfrom this normal hydrostatic pressure isreferred to as abnormal pressure.

Abnormal geopressures, above or below the normal gradient, are found in manyhydrocarbon-producing reservoirs. While theorigin of these pressures is not understoodcompletely, abnormal pressure developmentis usually attributed to the effects ofcompaction, diagenetic activity, differentialdensity and fluid migration.1 Abnormalpressure involves both physical and chemicalactions within the Earth. Pressures above orbelow the normal gradient may be detrimentalto the drilling process.

Subnormal pressures, or those below thenormal gradient, can cause lost-circulationproblems in wells drilled with liquid drillingmud. Subnormal pressure conditionsfrequently occur when the surface elevationof a well is much higher than the subsurfacewater table or sea level. This is seen whendrilling in hilly or mountainous locations, but it may also occur in arid regions wherethe water table may be more than 1,000 ft [305 m] deep.

Abnormally low pressures are alsofrequently found in depleted reservoirs. Theseare reservoirs whose original pressure hasbeen reduced by production or leakage.Depletion is not unusual in mature reservoirsfrom which significant volumes of oil and gashave been produced without waterflooding orpressure maintenance.

By contrast, abnormally high pressures are typical in most oil-producing regions.Abnormal overpressures always involve aparticular zone becoming sealed or isolated.The amount of overpressure depends on thestructure, the depositional environment andthe processes and rate of deposition.

26 Oilfield Review

> Pressure isolation by fault displacement. In zones of faulting, pressure-bearingzones (brown) can be displaced along a fault plane. If adequately sealed, thedisplaced zone maintains its abnormal pressure. Although the top of an abnormallypressured zone may be defined in a given area or structure, faulting can causesignificant changes in formation depth only a short distance away. For the driller, thisnot only is confusing but also causes an increased drilling risk.

Well 1 Well 2

Pressured sand

Pressured sand

Pressured sand

Well 3 Well 4 Well 5

Pressured sand

1. Bourgoyne AT, Millheim KK, Chenevert ME and Young FS:Applied Drilling Engineering, 1st ed. Richardson, Texas:Society of Petroleum Engineers, 1986.

2. For more on faulting: Cerveny K, Davies R, Dudley G,Fox R, Kaufman P, Knipe R and Krantz B: “ReducingUncertainty with Fault-Seal Analysis,” Oilfield Review16, no. 4 (Winter 2004): 38–51.


Autumn 2005 27

One of the most common mechanismsgenerating abnormally high pressures istrapping of pore water during deposition. If a seal forms before pore water is displaced,grain-to-grain contact between solids is notestablished. Over time and with increases incompaction due to overburden pressure, thewater in the pore space becomes compressed,causing abnormally high pore pressure.

Another cause of abnormally high geopres-sure is geologic uplifting and displacement of a formation, which physically relocates ahigher pressured formation from one depth to another (previous page). When a previouslynormal pressure zone at great depth isdisplaced by tectonic activity to a shallowerdepth with the seals remaining intact, theresulting pressure will be abnormally high.

Undercompaction during deposition isanother mechanism for generating high pore pressure. In the Gulf of Mexico andother depositional basins, compactiondisequilibrium is believed to be the mostimportant cause of overpressure. Forsediment to compact, pore water must beexpelled. However, if sedimentation is rapidcompared to the time required for fluid to be expelled from the pore space, or if sealsthat prevent dewatering and compaction form during burial, the pore fluid becomesoverpressured and supports part of theoverburden load.

Artesian systems are a unique source ofabnormally high pressures. In these systems,the surface elevation of the well is below sea level or the water table, a condition thatmight exist if drilling in a valley betweenmountains (above right).

The same principle also applies tostructural situations in which highly dippingpermeable formations allow pressuretransmission from a higher-pressured deepzone to a shallower depth. Abnormalpressures caused by structural effects arecommon adjacent to salt domes, where therising, migrating salt has uplifted thesurrounding formations, tilting them andsealing the permeable formations.

Overpressures can also occur in shallowsands if higher-pressured fluids migrate fromlower formations as the result of faulting orthrough a seal in a network of microfractures(below right).2 In addition, man-made actionscan charge upper sands. Poorly cementedcasings, lost circulation, hydraulic fracturingand underground blowouts can causeotherwise normally pressured zones to becomeabnormally pressured.

Another cause of overpressure is chemicalactivity. If massive deposition of organicmaterial becomes sealed with time andexposed to higher temperatures, this organicmatter generates methane and otherhydrocarbons that charge the formation.Increasing depth, temperature and pressuremay cause gypsum to convert to anhydrite,releasing water that may charge a formation.Conversely, anhydrite that is exposed to watermay form gypsum, resulting in as much as a40% increase in volume, thereby increasingzonal pressures. Pore pressure may also beincreased by the transformation of smectiteto illite at increasing temperature and depth.As water is expelled from the clay crystallattice, pore pressure increases.

> Artesian pressure system. In these systems, the surface elevation of the well is below sea level orbelow the water table. This commonly occurs when drilling in a valley or basin surrounded by hillsor mountains—locations where a connected water table is charged by water from higherlocations.

Ground level

Artesian well

Well elevation below water tableRain Rain

Seal Permeable sand

> Fracture migration. Fault planes may allowpressure transmission from a zone of higherpressure to a more shallow, lower-pressuredzone. This results in an abnormally pressured,or charged, sand. These effects are commonin tectonically stressed environments andadjacent to salt domes.

Zone of higherpressure

Charged sand


Reflection tomography offers significantadvantages compared with conventional seismicdata. Conventional seismic data processingsmoothes out velocity fluctuations, and velocityinterval picks are often too coarse for accuratepore-pressure prediction. Reflection tomographyreplaces the low-resolution, conventionalvelocity analysis with a completely general ray-trace modeling-based approach. Although aninterpretable image might be obtained using arelatively poor but smooth conventional seismic-velocity field, the resolution is sometimes too low

to accurately predict pore pressure for well-planning purposes. By contrast, the tomograph-ically refined velocity model leads to betterunderstanding of the magnitude and spatialdistribution of pore pressure, reducing theuncertainty of pore-pressure predictions (above).

Reducing UncertaintyIn areas where the geology is unknown andwhere few, if any, wells have been drilled, seismicgeopressure prediction may be the only planningtool available to the engineer. However, data frommultiple sources, especially drilling, can be used

in conjunction with seismic tomography to refinemodels, and reduce risk and cost, whileimproving drilling efficiency.

Once wells have been drilled, drillers andplanning engineers have access to additionaldata, including mud records, mud logginginformation, formation samples, wireline andwhile-drilling logs, and formation test data. Toolssuch as the MDT Modular Formation DynamicsTester sample formation fluids and provideaccurate reservoir pressures.10

Pressures in shale sections above a reservoircan be estimated based on offset-well mudweights. Daily drilling reports of problems such askicks, lost circulation, differential sticking andother drilling problems also may indicate thepresence of abnormal pressures. Planningengineers generally use offset-well data cautiously.Using mud weights to estimate formation pressuremay be misleading, particularly when the datacome from older wells.

Most wells are drilled in an overbalancedcondition, with mud weights that exceed actualformation pressure by 1 lbm/galUS [120 kg/m3] ormore. Drillers frequently increase mud weights tocontrol troublesome, or sloughing, shales.

A more detailed evaluation of geopressurecan be obtained by combining drilling data withoffset-well electric, acoustic and density logs. Topredict pore pressures from wireline or while-drilling logs, analysts often correlate changes inshale porosity with the potential presence ofabnormal pressure. This is possible becauseshales generally compact with increasing depthin a uniform manner. Because of this compaction,the porosity and electrical conductivity decreaseat a uniform rate with increasing depth andoverburden pressure. However, if a seal ispresent, higher than normal levels of conductiveconnate water may be present, increasingconductivity and indicating abnormal pressure(next page, top). Although conductivity is a goodindicator, many variables such as connate-watersalinity, mineralogy, temperature and drilling-mud filtrate may also affect electric log response.

Acoustic velocity derived from sonic logsprovides another tool for determining porepressure that is less affected by wellboreconditions. Acoustic tools measure the time ittakes for sound to travel a specified distance. Asformation characteristics change, so do thevelocity and the interval transit time.

Shales with porosities approaching zero maytransmit sound at velocities on the order of16,000 ft/s [4.88 km/s] and transit times of62.5 µs/ft [205 µs/m].11 Shales with higherporosity have more pore space filled with

28 Oilfield Review

> Seismic tomography. In previous methods, interpreters stacked seismicvelocities to improve resolution; from this they generated a pore-pressurecube representing pore pressures across a given area (top). Now,tomographic techniques dramatically improve pore-pressure resolution,reducing uncertainty and increasing accuracy in well planning (bottom).

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formation water, hydrocarbons, or both. At 30%porosity, the velocity drops to 12,700 ft/s[3.87 km/s], and the interval transit timeincreases to about 103 µs/ft [338 µs/m]. Normallypressured shales exhibit decreasing intervaltransit times with depth. However, as increasedpore pressure is encountered, the trend willreverse (below right).

Density logging tools also help engineerspredict geopressures. The tool irradiates aformation with gamma rays that interact with theelectrons surrounding the borehole. Theintensity of the backscattered gamma rays varieswith bulk density. Since the bulk density ofabnormally pressured shale is less than thedensity of normally pressured shale, engineerscan combine predictions made by density,electric and acoustic measurements with surfaceseismic data to better refine models andreservoir pressure profiles.

Improving Pore-Pressure Predictions in theVeracruz BasinInaccuracies in pore-pressure prediction maylead to well-control problems, exposing anoperator to undue risk and excessive cost.Drilling problems in the Veracruz basin, offshoreMexico, led the operator, Petróleos Mexicanos(PEMEX), to reevaluate pore-pressure predic-tions.12 Engineers at PEMEX and Schlumbergerfound that predicted mud weights in the Cocuitefield were higher than required, resulting in lossof circulation and significant cost overruns. Toimprove drilling efficiency and reduce risk,engineers and geoscientists used previouslyacquired three-dimensional (3D) surface seismicdata along with sonic logs, mud weights,checkshot surveys and pressure tests from offsetwells to improve pore-pressure predictions.13

10. For more on the MDT tool: Crombie A, Halford F,Hashem M, McNeil R, Thomas EC, Melbourne G andMullins OC: “Innovations in Wireline Fluid Sampling,”Oilfield Review 10, no. 3 (Autumn 1998): 26–41.

11. The unit µs means microsecond, or one millionth of a second.

12. Sayers CM, Hooyman PJ, Smirnov N, Fiume G, Prince A,de Leon Mojarro JC, Romero MT and Gonzales OM:“Pore Pressure Prediction for the Cocuite Field, Veracruz Basin,” paper SPE 77360, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, September 29–October 2, 2002.

13. Drillers often perform downhole seismic measurementsto provide data for correlation of surface seismic data toactual downhole conditions. A checkshot measures theseismic traveltime from the surface to a known depth inthe well. Compressional, or P-wave, velocity of the for-mations encountered in a wellbore can be measureddirectly by lowering a geophone to each formation ofinterest, sending out a source of energy from the surfaceof the Earth, and recording the resultant signal. The dataare then correlated to prewell surface seismic data bycorrecting the sonic log and generating a synthetic seis-mogram to confirm or modify seismic interpretations.Mechanical earth models and pore-pressure predictionscan then be updated.

> Electric log analysis to reduce the uncertainty of seismic-based pore-pressure predictions. Innormally compacted sediment, electrical conductivity will decrease with depth as water is squeezedfrom pore spaces. A deflection in conductivity from the normal trend (dashed circle, left and middle)may indicate a change in pore-water concentration, hence the potential for abnormal pressure. Usingboth seismic and electric log data, computer processing refines the data and generates three-dimensional predictive models that help engineers and drillers visualize pore-pressure trends (right).

Top of abnormal pressure

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> Acoustic logs for pore-pressure prediction. Sound waves slow when encountering rock with higherpore-water concentrations. The top of an abnormally pressured zone can be predicted based on thechange in interval transit time (dashed circle, right), then correlated to changes in conductivity (left).Both measurements can then be used to reduce the uncertainty of the seismic pore-pressure cube(center).

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Before pore pressure can be estimated fromseismic velocities, local knowledge of the totalvertical stress must be obtained. In the areacovered by the Cocuite 3D seismic survey, theonly density log available was from Well Cocuite402, covering a depth range of 643 to 7,690 ft [196to 2,344 m]. To estimate the overburden stress tothe required depth of more than 13,000 ft[3,962 m], density data from the Cocuite 402density log were combined with other densityinformation from the Veracruz basin into acomposite density log. This information was thenused to calculate a general overburden stressgradient for the area. Calculated formationvelocities were verified by comparing them tosonic logs upscaled to seismic wavelengths andto seismic interval velocities obtained by invert-ing traveltime depth pairs from checkshots.

Although reasonable agreement was foundover the intervals for which sonic logs andcheckshots were available, variations in the

velocity field from location to location wereobserved (below). Similar variations were seen forthe other wells in the study area. To mitigate thesesmall-scale variations, geoscientists smoothed thevelocities laterally before converting the seismicinterval velocities to pore pressure. Thistechnique results in 3D models with a high datadensity that are less uncertain than thoseacquired with conventional techniques.

Using seismic velocities from the Cocuite 3Dsurvey and a velocity-to-pore-pressure transform,engineers optimized drilling operations byadjusting mud weights. Engineers believe thatfurther refinement in this pore-pressureprediction is possible using reflectiontomography to enhance lateral resolution of theseismic velocities.14

Adjusting Pore-Pressure Predictions While DrillingThe progression from conventional seismic pore-pressure prediction to reflection-tomographictechniques significantly reduced uncertainty and improved the accuracy of pore-pressureestimates. However, drilling deep into the Earthcontinued to be fraught with uncertainty.

During well construction, drillers strive tobalance mud weight and formation pressure,often based solely on indirect measurements orindicators. Real-time drilling parameters areclosely monitored for changes in penetrationrate, gas shows and the condition of cuttingsreturning to the surface, along with signalstransmitted from measurements-while-drilling(MWD) and logging-while-drilling (LWD) tools.

Schlumberger geophysicists developed atechnique for updating uncertainties in thepredicted velocities and pore pressures whiledrilling.15 This technique evaluates uncertaintiesin the predicted pore pressure on the basis of

30 Oilfield Review

> Comparison of P-wave interval velocities. Data (top right) obtained by upscaling the sonic log (green curve) and by inverting traveltime-depth pairs fromthe checkshot (red curve) in Cocuite Well 101 are compared with the seismic interval velocities (blue dots) for all locations surveyed in the Cocuite fieldstudy. From this information, engineers generated a seismic interval velocity 3D cube (left) and a pore-pressure gradient cube (bottom right) showing atransition zone around 3 km [9,843 ft]. This cube helped to define lower and upper formation-pressure limits.

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Autumn 2005 31

borehole-seismic, well-logging and pressuremeasurements acquired while drilling. Thetechnique was evaluated on two wells in the Gulfof Mexico, USA.

The process involved establishing baselineuncertainties in the coefficients of the velocity topore-pressure relationship from compressional-wave velocity and density. When drilling began,uncertainties were completely defined bybaseline values (above).

As drilling progressed on the first evaluationwell, a checkshot survey provided data forvelocity structure calibration, allowing geophysi-cists to refine baseline projections and decreasethe uncertainty in velocity and pore-pressure

predictions. A relatively small decrease invelocity uncertainty resulted, due to the smallsize of the checkshot dataset, which comprisedtraveltime measurements acquired at variableintervals of 50 to 200 m [164 to 656 ft].

After initial logging, engineers incorporatedsonic log data to further refine the pressureprofile. This additional information markedlyreduced velocity uncertainty and gave acorrespondingly more detailed pore-pressureprediction. The improved pore-pressure

14. Sayers et al, reference 12. 15. Malinverno A, Sayers CM, Woodward MJ and

Bartman RC: “Integrating Diverse Measurements to Predict Pore Pressures with Uncertainties WhileDrilling,” paper SPE 90001, presented at the SPE Annual Technical Conference and Exhibition, Houston, September 26–29, 2004.Bryant I, Malinverno A, Prange M, Gonfalini M, Moffat J,Swager D, Theys P and Verga F: “Understanding Uncer-tainty,” Oilfield Review 14, no. 3 (Autumn 2002): 2–15.

> Reducing uncertainty. The degree of uncertainty in a pore-pressure gradient is exemplified by the width and low resolution of the compressional-velocity(Vp) and pore-pressure gradient curves (1). Vp data from sonic logs are added to the model, somewhat reducing pore-pressure uncertainty (2). Adding mudweights from drilling reports (3) and physical pore-pressure measurements (4) refines estimates and dramatically improves pore-pressure resolution.

500

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prediction continued to have a level of uncertaintythat could be reduced only by incorporatingmeasured pore-pressure data. In the absence ofdirect pore-pressure measurements, mud weightwas used to represent pore-pressure boundaries.

On the second test well, relatively lowvelocities were inferred from surface seismicdata below 1,500 to 2,000 m [4,921 to 6,562 ft],corresponding to predicted overpressure.Geophysicists incorporated sonic log data toreduce uncertainty. Although pore-pressurepredictions improved, the inclusion of mudweights and direct pore-pressure measurementscalibrated the coefficients in the velocity to pore-pressure relationship and placed an upperboundary on the predicted pore pressures.

Initially, the pore-pressure gradient from1,500 to 2,000 m was estimated to be above13 lbm/galUS [1,560 kg/m3], using pore-pressure predictions based solely on surfaceseismic data, checkshot values and sonic logs.With the inclusion of MDT pore-pressuremeasurements, the calibrated pore-pressureprediction constrained the equivalent pore

pressure to less than 13 lbm/galUS. Uncertaintywas reduced, allowing drillers to better controlmud weights, define casing points and improveoverall drilling efficiency.

Measuring Reservoir PressuresAfter drilling, concerns regarding pressureusually switch to reservoir management andproduction operations. Understanding pressuresin the reservoir ultimately impacts productionand payout, and today may even provide guidanceto place additional wellbores for optimizedproduction. Operational demands dictate howand when pressure measurements areperformed, with many methods and tools beingavailable to measure and monitor reservoirpressures at almost any time during a well’s lifecycle. As described above, the understanding ofpressure begins with predrill estimates fromseismic data and offset wells, and is furtherrefined during drilling. Reservoir and productionengineers make additional measurements usinglogging tools or permanent sensors in the well orat surface.

Some of the many ways reservoir engineersuse precise pressure measurements are for fluididentification and typing, defining fluid contactsand assessing reservoir continuity. Obtaining therequired measurement precision involves use of services such as the MDT tool, thePressureXpress reservoir pressure while loggingservice or while-drilling formation-pressuretools. In these services, high quality data areobtained by allowing time for pressurestabilization before the measurement, byallowing sufficient time for the pressure withinthe tool to equilibrate with the pressure in theformation and by obtaining a large number ofpretests to establish fluid gradients.

Later, in mature reservoir environmentswhere substantial production has taken place,formation-pressure measurements are used toquantify depletion, to assess pressure support orto further analyze reservoir continuity. Eventhough the accuracy requirements of pressuremeasurements may not be as strict in maturereservoirs, the ability to measure pressures overa wide range of formation permeabilities may becritical for increasing hydrocarbon recovery.

While-Drilling Pressure Measurement in NorwayAlthough borehole seismic techniques havebrought the driller closer to understanding andpredicting pore pressures in real time, scientistsand engineers continue to develop tools forobtaining direct pressure measurements whiledrilling. As LWD technology advanced, engineersadapted the CQG Crystal Quartz Gauge andstrain-gauge pressure sensor technologies usedin other pressure tools, such as the MDT system,to real-time, while-drilling, pressure-sensingtools (see “Quartz Pressure Sensors,” next page].

Engineers at Statoil and Schlumberger fieldtested the new StethoScope formation pressure-while-drilling service in 2004 in several fieldslocated offshore Norway.16 The goal of fieldtesting was to establish whether a while-drillingformation-pressure measurement could be ofcomparable quality to wireline MDT testermeasurements given the range of permeablities,well conditions and mud properties encounteredin these fields.

All formation tester tools measure porepressure at the interface between the externalfiltercake and the wellbore wall, or sandface.Whether or not the pressure at the sandface is agood estimate of the true, far-field formationpressure depends not only on the properties ofthe mud, the filtercake and the formation, butalso on the drilling-fluid circulation-rate history.

32 Oilfield Review

> The StethoScope 675 tool. The tool is 31-ft [9.1-m] long; it has a 6.75-in. collar with an 8.25-in. stabilizeror optional 9.25-in. stabilizer. The stabilizer is made up of a four-blade spiral section at the bottom andtwo straight blades at the top. The packer and probe are mounted in the blade of the stabilizer(black). The stabilizer blade rests, or is pressed, against the formation by gravity or by force appliedby the drillable setting piston (not shown), negating the need to orient in holes up to 10.5 in. for the8.25-in. stabilizer tool. The probe can extend out of the blade by 3⁄4 in., but normally only moves outlevel with the surface of the blade and is compressed against the formation to make the seal. Theprobe is then opened to the formation to take a pressure measurement. The retainer ring (Q-shapedpiece around black packer) minimizes deformation of the packer during a test, helping to maintain aneffective seal (inset).

16. Pop J, Laastad H, Eriksen KO, O’Keefe M, Follini J-M andDahle T: “Operational Aspects of Formation PressureMeasurements While Drilling,” paper SPE/IADC 92494,presented at the SPE/IADC Drilling Conference, Amsterdam, February 23–25, 2005.


Autumn 2005 33

If the filtercake is totally ineffective insealing between the formation and test probe,then wellbore pressure will be measured; if thefiltercake provides a perfect seal, given sufficienttime, the tester should measure the trueformation pressure.

In most drilling situations, filtercakes areneither perfect nor uniform in composition.During the course of normal drilling operations,the filtercake is eroded by mud circulation,scraped away during trips, and then rebuilt atthe borehole face. Laboratory experiments withboth water-base and oil-base muds indicate thatdynamic wellbore conditions influence the mud-filtration rate into the formation and, byimplication, the pressure measured at thesandface. A leaking filtercake is frequently aproblem and may result in significant differencesbetween measured and true formation pressures.When the difference between the measuredsandface pressure and the true formationpressure is significant, the formation is usuallysaid to be supercharged. This situation mayoccur in both while-drilling and conventionalwireline-conveyed methods of measurement, butmay be more common in a while-drilling methoddue to the dynamic environment.

To improve confidence in pressuremeasurements, the StethoScope tool wasdesigned with a pressure-measurement probeembedded in a stabilizer blade surrounded by anelastomeric sealing element, or packer (previouspage). The stabilizer design maximizes the flowarea at the cross section of the probe, diverts theflow away from the probe-to-formation interface,and minimizes the mud velocity in the vicinity ofthe probe, thereby helping to reduce filtercakeerosion and filtrate leakage into the formationwhile testing. A drillable setting piston isemployed to push the stabilizer containing theprobe against the formation face.

The tool draws power from a downhole MWDturbine. Additional power is provided by abattery, capable of fully operating the formation-pressure-while-drilling tool, for example duringtests, when the pumps are off. Sandfacepressures are measured by two drilling-qualifiedpressure gauges: a proprietary, ruggedized CQGpressure sensor and a strain-gauge sensor. Asecond strain-gauge pressure sensor, locatednear the probe, measures wellbore pressurecontinuously. All data acquired during formationtests are stored in tool memory, includingpressures, temperatures, actual pretest volumesand drawdown rates, and tool-related state and

Quartz is one of several minerals that displaypiezoelectric properties. When pressure isapplied to a quartz crystal, a positiveelectrical charge is created at one end of thecrystal and a negative charge at the other.Quartz crystals are also strongly pyroelectric;temperature changes cause the developmentof positive and negative charges within the crystal.

A correctly cut quartz crystal has aresonant frequency of vibration, similar to atuning fork. As the quartz vibrates, there is adetectable sinusoidal variation in electricalcharge on its surface. Pressure-inducedstress applied to the crystal causes the sine-wave frequency to vary in a predictable andprecise manner. These properties makequartz valuable in many electronics andsensing applications, including oilfieldpressure sensors.

Researchers at Schlumberger-DollResearch in Ridgefield, Connecticut, USA,began work on a highly sensitive pressuregauge based on the unique properties ofquartz crystals in 1980, and proposed thedual-mode oscillation concept that becamefundamental to the development of the CQGCrystal Quartz Gauge sensor (above right).1

The project was transferred to Schlumberger-Flopetrol, Melun, France, in 1982. Thedevelopment team was supported byresearchers at Ecole Nationale Supérieurede Mécanique et des Microtechniques,Besançon, France.

Pressure sensors are sensitive totemperature and pressure variations, andmust be corrected for temperaturefluctuations. The CQG gauge improved on

previous crystal pressure transducers byproviding both temperature and pressuremeasurements from a single sensitiveelement, eliminating problems associatedwith thermal lag between separate pressureand temperature sensors. This sensorproduces a small peak error induced bytransient conditions. Transient errors arefurther minimized by a dynamic temperaturecompensation algorithm based on a simplemodel of the sensor. CQG sensors operateefficiently at pressures ranging from 14.5 to15,000 psi [0.1 to 103.4 MPa] and in a temp-erature range of 77 to 300°F [25 to 150°C].

In 1989, the CQG sensor was optimized forcommercial fabrication and applied tonumerous oilfield pressure-sensing applica-tions, including the MDT tool. More recently,the CQG sensor was ruggedized for LWD andMWD applications, and today it is the primarypressure sensor in both the StethoScopetester and the PressureXpress tool.

Quartz Pressure Sensors

1. Two mechanical oscillation modes are excited andmaintained by the electronics in the CQG resonatorplate. One is more sensitive to lateral stressescaused by pressure applied on the sensor; the other is more sensitive to temperature variations.These two resonance frequencies providesimultaneous information on pressure andtemperature and allow computation of a temperature-corrected pressure measurement.

> Sensor for making temperature-compensated pressure measurements. Thecrystal blade CQG sensor (gold) is a dual-mode resonator with one mode dependent onapplied pressure and a second dependent onthe applied temperature. The pressure andtemperature measurements are taken atexactly the same time.


operating information. The tools have sufficientmemory to store more than 80 five-minutepressure tests.

When acquiring formation pressures and fluidmobilities, engineers may choose between twodifferent modes of operating the pretest: anoptimized pretest sequence or fixed-modepretest sequence.17 An optimized, or time-limited, pretest consists of a small initial pretestduring which the formation is tested todetermine its dynamic properties, followed byone or more, preferably larger-volume, optimizedpretests. The optimized pretests are designeddownhole by the tool’s logic systems usinginformation obtained from previous tests so thatat the end of a prescribed test time, multiplestabilized sandface pressures have beenachieved. Only as many tests are performed aswill deliver stabilized pressures in the prescribedtime; for formations with low mobilities, this mayresult in a single drawdown.

In the field-testing stage, offshore Norway,fixed-mode pretests were employed. Four fixed-mode pretest sequences that utilize differentpreset test parameters are available in theStethoScope tool (left). Each fixed-mode pretestsequence comprises two drawdown and builduppairs designed to deliver two stabilized sandfacepressures within a specified time frame,generally 5 minutes. When consistent, these twoindependent pressure measurements per testlocation, or station, together with an estimate ofthe formation fluid mobility, give confidence inthe final pressure result. Comparison of the twopressures obtained in conjunction with thecomputed mobility can reveal the effects of astatic or dynamic pressure environment. Anorder of magnitude estimate of the formationfluid mobility is helpful in deciding whichparticular fixed-mode sequence to employ in anygiven situation, but there is sufficient overlap intheir ranges of application that this decision isnot critical.

Communication to and from the tool is bymeans of the TeleScope high-speed telemetry-while-drilling service, specifically designed toprovide increased data rate and bandwidth fordata delivery. A special telemetry protocol for usewith the Telescope telemetry system allows asingle device, such as the StethoScope tool, tomonopolize data transmission when it has a largeamount of data to transmit over a short timeinterval. The combination of the TeleScopesystem and on-demand data transmission allowsStethoScope data to be visualized at surface inreal time (left).

34 Oilfield Review

> Fixed-mode pretests, A through D, with two drawdown-buildup pairs.Parameters are chosen to cover a wide formation-fluid mobility range (top).The parameters specify the volumes employed and the duration of thebuildups for Pretest 1 (the “investigation” pretest) and Pretest 2 (the“measurement” pretest). The graph (bottom) demonstrates the StethoScopetool response when testing a 1.5-mD/cP limestone formation using a pretestsequence similar to that of fixed-mode Type B. During this test, the secondbuildup was extended, allowing engineers to observe the pressurestabilization time across a longer than normal test sequence. There is avariance in the sandface pressure measurement when performing themeasurement with pumps on (red) at a rate of 1,363 L/min [360 galUS/min],and with pumps off (blue).

Pretest 1

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> Pressure data in real time. In this field-test example, pressure data, presentedas open triangles, are displayed in real time at surface during a 5-minutetime-limited pretest performed with the mud pumps on, circulating at a rateof approximately 600 galUS/min [2,271 L/min]. The telemetry rate for this testwas 6 bits/s. The colored circles represent the principal event markersidentified as the data are acquired. The first event marker (1) identifies thewell pressure prior to the test; the second marker (2) indicates the beginningof buildup for the investigation phase; the third marker (3) shows theinvestigation-phase, sandface-pressure estimate; the fourth marker (4)identifies the beginning of buildup for the measurement phase; and the fifthmarker (5) represents the sandface pressure as determined during themeasurement phase. The formation fluid mobility was determined to beapproximately 1.4 mD/cP.

2,000

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Autumn 2005 35

During field testing, the performance of thetool in both low-mobility (less than 0.2 mD/cP)and high-mobility (more than 350 mD/cP)formations was evaluated, with most dataacquired being compared with wireline MDTpressure data and cores. Tests were conducted ina vertical well, highly deviated wells (up to 75°)and a horizontal well, with circulation ratesranging from pumps off to 2,300 L/min[600 galUS/min]. To assess the effects of timeelapsed since drilling, pressure measurementswere taken from one hour to 43 hours after thebit penetrated the test depth. While-drillingpressures were compared with those obtainedwith a MDT tester up to 24 days after the while-drilling measurements.

Field tests in Norway established that real-time pressure measurements made by theStethoScope tool are comparable to those madeby wireline MDT testers under similarpermeability, mud type and borehole conditions.In general, the most accurate pressuremeasurements were obtained in formations withthe highest mobility, with pumps off, or whenusing a circulation rate that was as low and asconstant as possible, and while tripping out ofhole (right). Measurements made during thedrilling process should be repeated at selectedstations while tripping out to confirm thepressure values obtained, especially ifsupercharging is suspected.

Engineers determined that for formationshaving fluid mobilities below 5 mD/cP, there is adistinct advantage to acquiring sandfacepressures with pumps off. The degree ofsupercharging as a function of circulation ratedepends directly on the amount of time since thefiltercake was mechanically disturbed. Highcirculation rates can promote the erosion of anestablished filtercake, yielding superchargedsandface pressures even after a lengthy periodbetween drilling and the pressure test. It is notalways safe to assume that the superchargingeffect decreases with time after drilling. Time-lapse data are important in identifying dynamicsupercharging in formations with low mobilities.

The field test conducted by Statoil andSchlumberger in the North Sea yielded positiveresults. The StethoScope tool demonstrated itsability to accurately measure formation pressuresin real time without needing to orient the tool orincurring excessive nonproductive time. Informations where the mobility is sufficiently high,5 mD/cP or more, the StethoScope measurementsare of the same quality as those acquired with theMDT tool. Today, both tools are helping engineers,

geologists and drillers quickly make decisions,reduce drilling uncertainty and save time and money.

While-Drilling Reservoir Pressure in the Gulf of MexicoIn deepwater drilling and production environ-ments, operators strive to reduce risk, uncertaintyand cost. An example is the Ram PowellProduction Unit, operated by Shell Offshore.Covering eight blocks in the Viosca Knoll area,eastern Gulf of Mexico, USA, wells are located in

2,000- to 4,000-ft [609- to 1,219-m] water depths,about 125 miles [200 km] east-southeast of NewOrleans. Production began in September 1997,making it one of the most mature deepwater oilfields in the Gulf of Mexico.18

17. Pop J, Follini J-M and Chang Y: “Optimized TestSequences for Formation Tester Operations,” paper SPE 97283, presented at Offshore Europe 2005, Aberdeen, September 6–9, 2005.

18. Volokitin Y, Stachowiak J and Bourgeois T: “Value ofSpecialized While Drilling Measurements: RecentExperience in Ram/Powell, GOM,” Transactions of theSPWLA 46th Annual Logging Symposium, New Orleans,June 26–29, 2005, paper C.

> Measuring pressure in a low-mobility formation. Three StethoScope test sequences (top) wereconducted at the same depth under different mud-circulation rates in a 3-mD/cP formation: a rate of2,262 L/min [597 galUS/min] (Test 5); a changing rate from 1,850 to 2,250 L/min [489 to 594 galUS/min](Test 6); and a test with pumps off (Test 7). All of the while-drilling tests are of pretest Type C. Forcomparison, a single-pretest MDT tester conducted some 24 days after the StethoScope tests isdisplayed. The graph (bottom) shows details of the final buildup. Here the effects of the dynamicwellbore can be clearly seen by comparing the while-drilling tests with pumps on and pumps off withthe MDT tool test, in which the filtercake should have reached maximum resistance.

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MDT test


Five commercial sands between 5,500- and13,500-ft [1,676- and 4,114-m] subsea truevertical depth (TVD) are responsible for most ofthe Ram Powell production. Geologists andengineers reevaluated the field between 2001and 2003, including time-lapse seismic surveys that identified potentially undrainedinfill-drilling opportunities.

In January 2004, Shell initiated redevel-opment activities. Engineers found a high degreeof risk and uncertainty in the new drillingprojects. New well targets required drillingcomplicated directional wells. Production hadalso depleted several pay sands, rendering themunstable and difficult to drill. Although thesecircumstances made formation evaluation moredifficult, the added uncertainty increased theneed for formation evaluation while drilling.

To reduce cost and improve efficiency, Shelland Schlumberger engineers planned to use LWDand MWD technologies to evaluate the reservoirand drilling environment in real time on Well 2 ofthe redevelopment campaign. Engineers selecteda bottomhole assembly (BHA) consisting of aPowerDrive Xtra rotary steerable system, a suiteof 6.75-in. VISION Formation Evaluation andImaging While Drilling tools, and the StethoScopetool components—all positioned below a holeopener. The VISION suite included anarcVISION675 63⁄4-in. drill collar resistivity tool,an adnVISION675 6.75-in. Azimuthal DensityNeutron tool and a proVISION675 6.75-in.nuclear magnetic resonance (NMR) tool. TheTeleScope telemetry service provided real-timedata transmission and control.

Engineers planned to use the pressure dataacquired by the StethoScope tool for completiondesign and to verify dynamic reservoir models.Obtaining formation pressure measurementswhile drilling reduced both rig cost and boreholeexposure times, and allowed reservoir engineersand geologists to make timely well-placement decisions.

After the driller set 11 3⁄4-in. casing at 10,474-ft[3,192-m] measured depth (MD), the initial 10 5⁄8-in. hole section was drilled at an inclinationof about 45° from 10,514- to 15,688-ft [3,205- to4,782-m] MD. Shell’s petrophysicist selected theformation pressure-measurement points usingdata from the density neutron tool to determinethe location of target sands. When on station, the StethoScope tool automatically began adrawdown-wait-retract sequence. After eachpressure measurement, the probe was retractedand the tool was moved to the next station. On-station time averaged 10 minutes or less per measurement.

contact. Using this real-time data, Shell engineersdecided to sidetrack the well. The new hole wasplaced higher in the reservoir by drilling updipfrom 11,501- to 16,952-ft [3,506- to 5,167-m] MDat 58° inclination. The pressure measurements

36 Oilfield Review

> Using adnVISION data to help pick pressure stations. Density data from the adnVISION675 loggingtool (Tracks 3 and 4 - red) helped select locations, or pressure stations, to be tested with theStethoScope pressure tool. Tracks 1 and 2 show formation and hydrostatic pressures, respectively,from the original hole (red circles) and the sidetrack (green circles). Zones with lower density havehigher porosity and fluid mobility.

Neutron Porosity

% 00.6

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Real-time formation pressure measurementsshowed good pressure support within thereservoir and confirmed that the low-resistivityzone at the bottom of the target sand was sweptoil, indicating a higher than expected oil/water

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Autumn 2005 37

confirmed good connectivity within the reservoir,so casing was run to total depth.

The proVISION675 NMR data helped engineerscalibrate net-sand calculations and improve thepetrophysical evaluation of laminated sands.Combining while-drilling data from NMR with datafrom other LWD tools provided importantinformation on rock texture, permeability, grainsize and net sand. NMR fluid-property data wereused with formation pressure and fluid mobilitiesto estimate formation permeability.

In total, 26 pressure measurements weremade—13 while drilling the initial section and13 while drilling the sidetrack. Pressuremeasurements provided critical information formaking sidetrack and completion-design decisions.Pressures were successfully acquired in bothmassive and laminated sands (previous page).

Advances in MWD technologies now providepressure and fluid-mobility measurements thatwere previously available only with wireline logs.Engineers can perform complex evaluationsbased on MWD data alone, significantly reducingthe risk, cost and uncertainty of drillingdeepwater development wells.

Engineers estimate that formation pressurewhile drilling and associated measurementssaved more than US$1 million by eliminating the

need for two conventional drillpipe-conveyedpressure-measurement runs. In addition, while-drilling NMR data provided importantinformation regarding fluid viscosity and rocktexture for net-sand calculation as well aspermeability and grain-size estimations, whichwere used in the completion design. Shell plansto continue using pressure-while-drilling andother real-time technologies to improveefficiency and reduce risk, particularly onchallenging deepwater projects.

Quick and Precise Reservoir PressuresWireline-conveyed formation-testing measure-ments have long been recognized as key tocollecting essential information to help identifyfluids in place, pressure regimes and dynamicproperties of a reservoir. Although they measuredformation pressures accurately, previoustechniques required that a wireline tool bestationary for relatively long periods of timewhile testing the formation. This is particularlytrue in low-mobility zones where longerevaluation times increase the cost and risk oftool sticking.19 Now, reservoir engineers haveoptions that provide fast and accurate pressuremeasurements. Tools such as the PressureXpress

service quickly make multiple, highly accuratepressure measurements.

Engineers at the Schlumberger RiboudProduct Center in Clamart, France, integratedadvanced versions of the CQG gauge and theSapphire pressure gauge into the PressureXpresstool. These pressure sensors provide high-resolution pressure measurements, dynamicallycompensated for temperature (above).

Earlier formation testing tools relied onhydraulically driven pretest systems that weremonitored and controlled from surface. The lagtime between surface commands and changes inthe downhole hydraulic-sampling actuatorlimited pretest volume control. The system wasredesigned, replacing the hydraulic system withan electromechanical motor coupled to aplanetary roller-screw mechanism and high-reduction gearbox, greatly enhancing thestability and accuracy of both the pretest rateand volume. Transferring the controls andcommands from the surface to the downholeelectronic cartridge improved the response time,making it possible to achieve pretest volumes aslow as 0.1 cm3 [0.006 in.3].

19. Manin Y, Jacobson A and Cordera J: “A New Generationof Wireline Formation Tester,” Transactions of theSPWLA 46th Annual Logging Symposium, New Orleans,June 26–29, 2005, paper M.

>Wireline pressure-measurement tool. The PressureXpress tool diameter and profile are designed to reduce the riskof sticking. Shown are the sampling seal system (black) and the backup anchoring pistons (top image – lower side)used to push and hold the tool in position at the formation face.


Formation testers have traditionally been runalone or on the bottom of a wireline toolstring,because of their inability to pass the telemetry ofother wireline tools. Implementation of newthrough-wiring hardware and a new softwaretelemetry system now permits combinations withall other wireline tools, which can be runanywhere above or below the new tool.

Through 2004, the PressureXpress servicewas field-tested on a total of 57 jobs, and morethan 1,300 pretests were performed, in a widevariety of environments, including sandstone andcarbonate formations (left). These involvedformation fluids varying from gas to heavy oilunder steam recovery. Bottomhole temperaturesranged from approximately 100 to 310°F [38 to154°C], at hydrostatic pressures of 0 to 13,000 psi[0 to 90 MPa].

Engineers incorporated the Smart Pretestdynamically controlled intelligent pressuretesting system to automatically find the bestpossible compromise between the formation-produced volume and the pressure-buildup time.In formations with fluid mobilities greater thanabout 1 mD/cP, the new tool can perform apressure and mobility test in less than oneminute: this represents an improvement of asmuch as four to five minutes over other testers.In tight formations, the pretest system can selectfluid volumes as low as 0.1 cm3, allowing minimaltest times (next page, top).

In some areas of Texas, tight gas-bearingsandstone reservoirs may have permeabilitiesranging from a few microdarcies to tens ofmillidarcies. In these fields, gas production relieson hydraulic fracturing to provide the conduit forreservoir flow. Many of these areas are matureand partially depleted, resulting in largepressure differences between reservoir layers.Determining these pressures accurately is key tooptimizing hydraulic-fracturing programs.

Failed attempts to measure pressures withconventional tools led to fracturing the entirereservoir thickness, including depleted zones,resulting in unnecessary completion expensesand lost production. For one well, Schlumbergerengineers used the PressureXpress service; 58pretests were attempted and 56 formationpressures were measured in less than sevenhours. Data obtained from the testing programidentified zones in the mid-reservoir sectiondepleted by as much as 4,000 psi [27.6 MPa],while the last 500 ft [152 m] of pay was still at a

38 Oilfield Review

> Locating pressure-test stations while logging. During the running of the combinationPlatformExpress integrated wireline logging tool and the PressureXpress tool, a real-time estimate offormation fluid mobility is output using the k-lambda correlation, a permeability estimator forsiliciclastics. Engineers use this information to help select zones for pressure testing (Track 5). Thedata output also helps select an appropriate pretest flow rate and volume that minimize time onstation during the subsequent formation pressure-test operations.

AIT HWater

Saturation

ComputedMicro InverseGamma Ray

gAPI 1500

Caliper

in. 200

ohm.m 100

ComputedMicro Normal

Permeability

Test is Not Recommended

Slow Pretest Gas Effect From DPHZ to TNPH

Tight

Normal Pretest

Fast Pretest

ohm.m 100

Volume of Clay

— 10

AIT H 90-in. Investigation

ohm.m 2,0000.2


ohm.m 2,0000.2

Std. Res. Density Porosity (DPHZ)

% 00.6

Env. Corr. Thermal Neutron Porosity (TNPH)

% 00.6


ohm.m 2,0000.2


ohm.m 2,0000.2


ohm.m 2,0000.2

20. For more on time-lapse seismic monitoring: 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; andAronsen HA, Osdal B, Dahl T, Eiken O, Goto R,

Khazanehdari J, Pickering S and Smith P: “Time Will Tell:New Insights from Time-Lapse Seismic Data,” OilfieldReview 16, no. 2 (Summer 2004): 6–15.

21. Burgess K, Fields T, Harrigan E, Golich GM,MacDougall T, Reeves R, Smith S, Thornsberry K,Ritchie B, Rivero R and Siegfried R: “Formation Testingand Sampling Through Casing,” Oilfield Review 14, no. 1(Spring 2002): 46–57.


Autumn 2005 39

relatively high pressure (below right). Engineersdesigned a four-stage hydraulic-fracturingstimulation procedure. Six fewer stages werepumped than on previous wells, yet productionincreased by more than 50%, saving the operatormore than US$ 400,000 in fracturing costs.

Managing Reservoir PressuresGeopressures drive oil from a reservoir to aproducing wellbore. As production starts, apressure drop in the formation around thewellbore causes oil to flow through pore networksin the reservoir toward the point of withdrawal.With oil withdrawal and subsequent pressure dropin the reservoir, the oil, water and rock expand.Changes in pressure, expansion and movement ofall these materials influence oil production.

Once a reservoir is producing, engineers andgeophysicists use various techniques to monitorthe movement of fluids and changes in pressure.Recent advances in seismic imaging allowacquisition of 3D surveys over time, known astime-lapse or four-dimensional (4D) seismicsurveys.20 Understanding the movement of fluidsand changes in reservoir pressures allowsengineers to better model reservoir behavior andimprove recovery efficiency.

From a purely mechanical point of view,geopressure data are relatively simple to obtainduring or shortly after drilling. As discussedearlier, real-time, while-drilling pressure tools,such as the StethoScope system, are providingengineers with valuable geosteering and reservoirdata for completion design, while wireline-conveyed tools, such as the PressureXpressservice, provide accurate pressure and mobilitydata shortly after the well is drilled. But, there isa problem: once casing is run into the well, thesetools cannot access the formation where thereare no perforations. Thus with time, knownpressures become unknown, and productiondecisions become more uncertain.

Using sensors similar to those mounted in while-drilling and wireline pressure tools,Schlumberger engineers designed the CHDTCased Hole Dynamics Tester, capable ofmeasuring pressure and extracting fluid samplesfrom behind a cased wellbore.21

> An electromechanical pretest system to reduce time on station. At time 0 s, the PressureXpress toolis on station and because it is not yet set, the flowline pressure is reading the wellbore mud pressure,approximately 4,430 psi [30.5 MPa] (black square, left). The tool is then hydraulically set,corresponding to an increase in the hydraulic pump velocity (green). The pressure curve (black)measures a pretest drawdown in a 0.01-mD/cP formation at about 45 s, followed by a gradualpressure buildup. After about 200 s, the tool initiated a second pressure drawdown (red triangles),extracting a volume of 0.1 cm3 of fluid from the formation. From 280 s to 680 s, reservoir pressurestabilized, then the tool was hydraulically retracted from the formation (green curve), and the flowlinepressure increased to the wellbore mud pressure. By using an electromechanical motor, thepressure-testing tool accurately controls the pretest volume and rate at low values (0.1 cm3),effectively reducing buildup duration and time on station.

Pres

sure

, psi

3,2000 100 200 300 400

Time, s500 600 700 800

3,400

3,600

3,800

4,000

4,200

4,400

4,600

Mud pressure before test, psi:Mud pressure after test, psi:Last buildup pressure, psi:Drawdown mobility, mD/cP:

4,436.224,428.863,809.330.01

> Identifying depleted zones. Formation pressures (red) are compared withthe mud gradient (green), identifying zones depleted by as much as 4,000 psi[27.5 MPa] in the middle part of the reservoir, while the last 500 ft of pay isstill at a relatively high pressure.

9,000

8,500

10,000

Dept

h, ft

0 2,000Pressure, psi

Mud gradient, 0.493 psi/ft

4,000 6,000

9,500

11,000

10,500


The CHDT tool can drill through casing andcement and then into the formation, takemultiple pressure measurements, recover fluidsamples and plug the holes made in the casing,all in a single descent (above). The ability toreseal the drilled holes makes the testeruniquely suitable for several reservoir andproduction applications: for example, locatingbypassed hydrocarbons, evaluating unknown payzones, producing or injecting through a fewholes, and determining formation-evaluationparameters when no openhole logs are available.Engineers can then optimize recompletion plans,enhance old or incomplete log data, assessunknown pay zones and evaluate wells foreconomic potential. The tool reduces rig cost byeliminating the costs of conventional plug-setting and cement-squeeze operations.

An operator in south Texas requested anevaluation of a well drilled in 1941. Cased-holelogging tools identified multiple zones withpotential hydrocarbons. Engineers used a USIUltraSonic Imager device to evaluate casing

condition and cement quality, and then theCHDT tool to measure reservoir pressure andconfirm fluid type.

During the test, seven formation pressureswere acquired. Four samples confirmedhydrocarbons. The CHDT tool successfullyplugged all holes. Based on test data, theoperator was able to plan a recovery program forthe bypassed hydrocarbons.

Even though engineers can evaluate reservoirpressures behind casing long after productionhas begun, running tools in the hole is a costly,invasive procedure. Well problems are addressedmost efficiently when acted on quickly.Developments in downhole telemetry, pressuresensors and advanced completion systems offerthe reservoir engineer the flexibility to makeproduction decisions in real time.

Permanent downhole pressure sensors andmonitoring tools, such as the WellWatcher real-time production monitoring and surveillancesystem, provide a continuous source of downhole

pressure measurement throughout the life of awell.22 Most often placed in the wellbore alongwith completion hardware, permanentlyinstalled sensors constantly monitor productionpressures (next page). When these sensors are usedwith other real-time monitoring hardware suchas fiber-optic temperature sensors, engineerscan constantly update reservoir models andoptimize the complete reservoir system.

Before the introduction of these systems,data acquired through well intervention providedonly a snapshot of well performance at the timethe parameters were measured. Now, highlyreliable downhole monitoring systems aresustainable in most downhole environments.

The WellWatcher system has been in place on15 BP North Sea assets for more than eightyears.23 From 1995 through 2003, BP installed 75of the monitoring systems in platform and subseaprojects, all based on permanent pressuresensors. BP reports that during this period, onlyfour of the systems have failed, translating to asuccess rate of 95%.24

40 Oilfield Review

> Cased-hole sampling tool. Engineers use the CHDT tool to make multiple pressure measurements and collect fluid samples from behind a casedwellbore. Powered by a wireline cable, the backpressure pads (lower side of tool) push the tool into an eccentric position (tool shown eccentered againstblue casing frame), the probe (shown tool top side) seals against the casing, and then drills a hole and measures pressure, samples fluids and plugs thehole. As the drill bit penetrates the target, the onboard integrated instrument package monitors pressure, fluid resistivity and drilling parameters.


Autumn 2005 41

In the BP Madoes field, a satellite of theEastern Trough Area Project (ETAP) in thecentral North Sea, three producing wells are tiedback 12.5 miles [20 km] to the primary platform.During completion, field specialists installed aFloWatcher integrated permanent productionmonitor system in each well to monitor pressure,temperature, absolute flow rate and fluid densityin oil-water flows. Real-time data from themonitoring system allowed BP productionengineers to quickly react, slowing waterproduction by reducing production rate. If theyhad relied only on surface measurements, theproblem would have been much worse.

Engineers involved in the Foinaven deep-water subsea development, West of Shetlands,North Sea, are using real-time pressure sensorsto better understand reservoir flow dynamics,adjust gas lift rates and maximize production.Prior to real-time downhole pressure measure-

ments, engineers relied on modeling software tohelp optimize gas lift rates and hence, overallproduction rate. These models required datafrom costly and time-consuming well tests andgenerally provided results with limited accuracy.Real-time downhole pressure monitoring systemsnow allow BP engineers to adjust gas lift rates toachieve minimum flowing bottomhole pressure,and hence maximum production rates.

Additional value is derived from the ability totrack well performance based on establishingbaseline parameters early in well life and thentaking periodic time-lapse measurements ofpermeability height and skin factors fromanalysis of buildup pressure transients. This hasprovided early identification of well-performanceproblems, allowed more detailed evaluation andpermitted intervention approaches to beoptimized, with associated time and cost savings.

The Foinaven team has also used the datafrom permanent downhole sensors tosignificantly improve understanding of reservoirconnectivity, and then optimize various waterinjection and associated voidage replacementstrategies. Engineers involved in the projectestimate that over a three-year period, beginningin 2000, the combined benefit of thesemonitoring systems accounted for 1 to 3% ofincremental production.

Data from continuous real-time sensorsprovide engineers with the necessary informationto optimize reservoir performance and recoveryby detecting problems early and defining timely,preemptive reservoir-management solutions.

Managing the Pressure SystemMaintaining reservoir pressure and optimizingrecovery of oil and gas have become parts of aglobal challenge. The measurement of pressurethroughout a reservoir’s life cycle is key toreservoir management. Accurate and efficientpressure measurement helps engineers andgeophysicists manage subsidence, improvesweep efficiency in secondary-recoveryoperations and improve asset performance.

Case histories demonstrate that engineerscan refine predrilling seismic pore-pressuremodels using downhole data, then adjust modelswith real-time data allowing wells to be drilledmore quickly with reduced cost, improvedborehole placement and better management ofthe reservoir. As efforts continue to define thenext energy revolution, reservoir engineers,geologists and geophysicists are combining thecurrent developments in pressure-measurementtools with advances in seismic interpretation andmodeling to optimize recovery and extend thelife of known hydrocarbon reserves. — DW

> Highly complex sensor and control installation. As downhole control-system technology evolves, the complexity of completion, monitoring and control systems continues to increase. Multizonecompletion systems comprising packers, sand-control screens, flow-control valves (WRFC-E) andsensor packages for temperature, pressure, resistivity and more are not uncommon.

Centralizers and electrodes Gravel pack

Sand screens Resistivity cable Hydraulic line to ECP

Sand screens

Water

Oil

Productionpacker

Zone 1 Zone 2 Zone 3

ECPECP

Shrouded valve(WRFC-E)

Electrical lineto valves

External casingpacker (ECP)

22. For more on permanent downhole pressure sensors:Bates R, Cosad C, Fielder L, Kosmala A, Hudson S,Romero G and Shanmugam V: “Taking the Pulse ofProducing Wells—ESP Surveillance,” Oilfield Review 16,no. 2 (Summer 2004): 16–25.

23. “Keeping Watch on Production, Deepwater,” ASupplement to Hart’s E&P, Hart Energy Publishing,August 2004.

24. For more on pressure gauges and downhole monitoring: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.


Documents

The Pressures of Drilling and Production