Real-time boreholeseismic system

seismicVISION

Applications

■ Place the bit on the seismic map while drilling

■ Predict pore pressure

■ Predict target (hazard) depths

■ Optimize mud weight

■ Select coring and casingpoints

■ Land the well optimally in thereservoir

■ Identify salt proximity in realtime

Benefits

■ Reduces depth uncertainty

■ Saves rig time and cost

■ Reduces casing runs

■ Reduces sidetracks and pilot holes

■ Improves safety

Features

■ Real-time check-shot data

■ Recorded waveforms forlookahead vertical seismicprofiles (VSPs)

■ Rugged LWD technology

■ Tools for hole sizes from 81⁄2to 26 in.

■ Multicomponent measure-ments

■ High flow rate and pressure ratings

■ Combinable with otherSchlumberger LWD tools

Imaging aheadThe Schlumberger seismicVISION* logging-while-drilling (LWD) systemdelivers time depth/velocity informationduring the drilling process to optimizedrilling decisions, reduce costs, andimprove safety. Unlike a conventionalwireline survey, the measurement doesnot normally interfere with drillingoperations or consume rig time. In envi-ronments where both risk and wellcosts are high, the system offers meas-urements that can significantly reducedrilling uncertainty.

Seismic data provided in real timehave a valuable impact on the well con-struction process. Real-time check-shotdata are used to place the bit on the Bit-On-Seismic* software-generated map toaid navigation, select casing points, andprepare for hazards ahead of the bit suchas faults, pore pressure changes, or for-mation variations. The software, pro-vided for all real-time applications, allowseasy visualization, communication, andcooperation, updating the seismic map inboth time and depth in real time. Themap converts complex information into

an easy-to-understand wellbore place-ment path. Real-time seismic velocitiesare used to update pore-pressure pre-dictions and to improve hazard depthpredictions.

Operation of seismicVISION system The seismicVISION tool, which con-tains a processor and memory, receivesseismic energy from a conventionalair gun array located either on the rigor on a source vessel. After acquisi-tion, the seismic signals are stored andprocessed, and checkshot data andquality indicators are transmitteduphole in real time via connection witha PowerPulse* measurements whiledrilling system. The time-depth data areused to position the well on the seismicmap at the wellsite or off site. Wave-forms are recorded in the tool memoryfor VSP processing after a bit trip.

A patented technique enables sourceactivation and data acquisition duringdrilling pauses when the downholeenvironment is quiet. Suitable times to acquire data are during pipe connec-tions while drilling and tripping.

The seismicVISION system reduces well placement uncertainty.

Target depth: 10,214 ft ± 12 ft

Typically, source activation is com-pleted with no interference to opera-tions.

Design features enable theseismicVISION system to work withoutthe limitations of previous real-time seismic systems. The tool has beenproved in a wide range of environ-ments and operating conditions,including

■ all well geometries

■ vertical depths greater than 25,000 ft

■ open hole and cased hole

■ hard and soft formations

■ moored and dynamicallypositioned rigs

■ deep and shallow water

■ zero-offset and verticalincidence VSP

■ in combination with allSchlumberger LWD tools

■ flow rates to 2,000 gal/min

■ pressures to 25,000 psi.

Q-Technology hardware and softwareThe Q-Borehole* integrated boreholeseismic system represents a total-concept approach. Personnel withexpertise in borehole seismic interpretation use Q-Technology* single-sensor seismic hardware andsoftware to deliver optimized and inno-vative solutions. The seismicVISIONtechnology includes the Q-BoreholeWAVE* field processing system and theSWINGS* source positioning system.

WAVE software allows quicklook seis-mic processing at the rig site for basicquality control and simple imagingapplications.

No Drilling SurprisesReal-time, while-drilling seismicVISIONinformation can be easily integratedwith a new Schlumberger solution.

The No Drilling Surprises (NDS)process is fully customizable, frombasic planning through to a continuallyupdating process that helps eliminateproblems by anticipating them and cre-ating contingency plans before they areneeded. The living well plan is continu-ally updated as new informationbecomes available.

The NDS process, with full collabo-ration from Schlumberger and theclient, develops fit-for-purpose pre-andwhile-drilling plans that focus on real-time wellbore pressure management,stability management, and placement.

Integrating seismicVISION data withthe NDS process helps improve casingpoint selection, reduce pore pressureuncertainty, and eliminate pilot holes.Those data can aid in real-time com-parisons of actual and planned results,in hazard anticipation, and in enablingthe real-time decision-making process.

NDS provides a complete frameworkfor increasing drilling efficiency, mini-mizing surprises and, ultimately, reduc-ing drilling cost.

11,000

13,000

15,000

17,000

19,000

2.8 3.2 3.6

Cased Hole

Open Hole

2.4 2.0 1.6

Time (s)

Truevertical depth (ft)

Recorded seismicVISION data. Conceptual drawing of seismicVISION operation.

The seismicVISION tool.

FE_03_001_0 ©Schlumberger

July 2003 *Mark of Schlumberger

www.slb.com/oilfield

Tool Specifications

Nominal OD† (in.) 63⁄4 81⁄4 9Max. OD, with wear bands (in.) 71⁄2 9, 10 10Pressure drop (psi)

Upset type 1 wear band 1 wear band 1 wear bandFishing neck OD‡ (in.) 7.50 9, 10 10Fishing neck length with new collar§ (in.) 71.3 78.9 78.9Nominal length without subs†† (ft) 14 13.84 13.84Length including two crossover subs (ft) 16.39 15.94 na‡‡

Loaded weight (lbm) 1,500 2,000 2,500Top thread connection 51⁄2 FH box 65⁄8 FH box 75⁄8 H90 boxBottom thread connection 51⁄2 FH box 65⁄8 FH box 75⁄8 H90 boxJoint makeup torque (ft-lbf) 25,000 41,000 76,000Joint yield torque (ft-lbf) 42,700 67,000 120,000Average moment of inertia (in.4) 85 191 296Bending strength ratio§§ 2.17 2.37 2.23Equivalent bending stiffness††† (ft) 13.8 14.4 14.8Max. dogleg severity‡‡‡

Rotating (deg/100 ft) 8 7 4Sliding (deg/100 ft) 16 14 12

OperationsMax. weight on bit§§§ 74,000,000 lbf/L2 164,000,000 lbf/L2 261,400,000 lbf/L2

Max. operating torque (lbf-ft) 16,000 23,000 35,000Surface speed (rpm) 200 200 200Stick/slip amplitude ±100% of mean speed ±100% of mean speed ±100% of mean speed

sustained for more than 30 min sustained for more than 30 min sustained for more than 30 minLateral vibrations 30 min at Shock Level 3 30 min at Shock Level 3 30 min at Shock Level 3

(50-g threshold) or 200,000 (50-g threshold) or 200,000 (50-g threshold) or 200,000 shocks above 50 g shocks above 50 g shocks above 50 g

Max. operating pressure (kpsi) 25 23 23Max. differential pressure††††

Internal-external difference (kpsi) 5 5 5External-internal difference (kpsi) 5 5 5

Max. operating temperature (°C [°F]) 150 [302] 150 [302] 150 [302]Max. flow rate (gpm) 1,000 2,000 2,000Max. sand content of mud solids 3% 3% 3%Max. dissolved solids content No limit No limit No limitMax. size LCM‡‡‡‡,§§§§ No limit No limit No limitMax. LCM concentration (ppb) No limit No limit No limitMagnetic sub No No No

† American Petroleum Institute (API) specification‡ See tool drawing in appropriate manual for details.§ Specification assumes new collar. Fishing neck is measured from the face of the uphole box to the start of the first external upset.

†† The sub length is that of the minimum self-contained operating configuration, excluding crossovers, saver subs, pony subs, etc.‡‡ Not applicable§§ Bending strength ratios are determined by the API connection and tool OD at the connection box. Check the bending stress ratio for any particular connection in your string.

††† Equivalent bending stiffness is the length of a standard API collar that would act in an equivalent manner to the bending stiffness of the subject collar. The equivalent bending stiffness is calculated as follows: Lequivalent = L tool × . Here, L means length, and I is the moment of inertia, in.4

‡‡‡ This is the maximum recommended dogleg severity (DLS) to which the tool should be subjected. This is not necessarily the DLS of the borehole.§§§ Maximum allowable weight on bit (WOB) is calculated from the equation given below. The maximum WOB depends on the unsupported length of collar, L, which is the distance between the stabilizers above and

below the sub. I is the moment of inertia, in.4 WOB = 917,000 ׆††† These values represent the maximum safe differential pressure in each direction prior to fluid leakage across the joints. The mechanical integrity of the joints should hold at least up to the maximum tool pressure

rating (23–25 kpsi). However, if the maximum safe differential pressure is exceeded, pressure and fluid can be lost across the metal-to-metal face seal at the tool joint.‡‡‡‡ LCM = lost circulation material.§§§§ These tools should pass any size of commercially available LCM. However, always check tool diagrams for minimum tool bore diameters and annular clearances.

I tool

L2

I API collar

I tool

[mud weight (ppg) × flow rate (gpm)] 217,000

[mud weight (ppg) × flow rate (gpm)] 769,000

[mud weight (ppg ) × flow rate (gpm)] 769,000