44 Oileld Review

Logging Through the Bit

Increasing use of horizontal drilling has spurred E&P companies to look for more

cost-effective ways to log their wells. To meet this need, an innovative logging

service has been developed. Operators are now capitalizing on a unique conveyance

method that uses small-diameter tools to obtain formation evaluation data in highly

deviated or extended-reach wells.

James AivalisTony MeszarosRobert PorterRick ReischmanRobin RidleyPeter WellsThruBit LLCHouston, Texas, USA

Benjamin W. CrouchOsage Resources, LLCHutchinson, Kansas, USA

Taylor L. ReidOasis Petroleum, Inc.Houston, Texas

Gary A. SimpsonForest Oil CorporationHouston, Texas

Oileld Review Summer 2012: 24, no. 2.Copyright 2012 Schlumberger.For help in preparation of this article, thanks to Martin Isaacs and Rick von Flatern, Houston; and Tony Smithson, Northport, Alabama, USA.Geo-Frac, Mangrove, Portal, SureLog and ThruBit are marksof Schlumberger.

Advances in drilling and completion technology are helping E&P companies open and develop new plays previously deemed uneconomic. In many of these plays, operators are turning to horizontal drilling and hydraulic stimulation to increase wellbore exposure to productive forma-tions. However, horizontal or high-angle wells can be difcult to evaluate. Often, these wells cannot be logged on wireline without specialized convey-ance equipment, which frequently results in added expense and operational delays. An unfor-tunate consequence is that some operators forgo the acquisition of petrophysical data entirely.

In high-angle wells, the combined effects of borehole trajectory and geology hamper an oper-ators ability to acquire the data needed to assess a reservoir and develop a stimulation program to enhance payout. To meet the challenges of high-angle wells, the industry has steadily rened technology for acquiring openhole logs. Logging while drilling (LWD), tractor conveyance and various pipe-conveyed logging techniques are just a few of the options currently available.1

Nevertheless, there are costsin the form of tool rentals or rig timeassociated with these alter-native methods.

In the unconventional plays of North America, such costs may adversely impact development strategies. A major factor in eld development economics is the cost of drilling and completing each horizontal well. It is therefore common in some unconventional plays for operators to limit use of logging suites.2

Often, gamma ray logs obtained by measure-ment-while-drilling (MWD) tools are used during geosteering to determine stratigraphic position. For some wells, the MWD gamma ray log may pro-vide the sole petrophysical input for designing perforating and formation fracturing programs. Although the gamma ray log may help geologists identify target zones through correlations with offset well logs, gamma ray measurements alone are not sufcient to characterize reservoir prop-erties that impact production. Measuring lateral and vertical variations in lithology, mineralogy, grain size, porosity, permeability and uid content in complex unconventional reservoirs requires a suite of logging tools.

The capability to identify changes in reser-voir rock, which petrophysical logs provide, can signicantly affect a wells completion program and its economics. This is particularly relevant for unconventional plays or other tight forma-tions, in which fracture treatments must be divided into several stages to stimulate a pay zone that extends thousands of feet along a hori-zontal wellbore. By excluding some zones, while selectively perforating and stimulating the inter-vals most likely to be productive, operators may reduce the number of stages required to opti-mally fracture a reservoir. Decreasing the num-ber and length of stages conserves water, sand and other resources, thereby reducing expenses and the overall impact of well stimulation.

1. Billingham M, El-Toukhy AM, Hashem MK, Hassaan M, Lorente M, Sheiretov T and Loth M: Conveyance Down and Out in the Oil Field, Oileld Review 23, no. 2 (Summer 2011): 1831.

2. Pitcher J and Buller D: Shale Assets: Applying the Right Technology for Improving Results, Search and Discovery Article 40883, adapted from an oral presentation at AAPG International Conference and Exhibition, Milan, Italy, October 2326, 2011.

Summer 2012 45Summer 2012 45

46 Oileld Review

A unique, cost-effective logging system has been developed to help operators obtain valuable formation data in high-angle wellbores. The sys-tem, developed by ThruBit LLC, uses mud pump pressure to deliver small-diameter logging tools down the center of the drillstring and out through a specialized bit to log the open borehole beyond. Traveling through this drillpipe conduit to TD, the tools are pumped through the bit opening where they can survey the formation as the drill-pipe is tripped out of the hole. Schlumberger acquired ThruBit LLC in 2011.

This article provides an overview of the equip-ment and deployment system that make the ThruBit logging technique possible. Datasets obtained with this system help demonstrate its quality and usefulness.

Logging EssentialsThe concept of logging through the bit centers on two requirements: logging tools that are small enough to pass through the drillstring and a bit designed to permit their passage into the open borehole. The ThruBit logging system uses spe-cially designed logging tools that combine small diameters with high-pressure, high-temperature capabilities. At 21/8-in. diameter, all tools in the SureLog suite are small enough to pass through the center of most drillpipe, jars, collars and bits (above). Each tool can withstand temperatures to 300F [150C] and pressures up to 15,000 psi [103 MPa]. These tools can be run in combination

to obtain a full suite of measurements during a single logging run.

The SureLog telemetry, memory and gamma ray device is run as the topmost logging tool to provide communications and memory functional-ity for the entire logging string. The gamma ray detector measures naturally occurring gamma rays in the formation to provide a qualitative evaluation of clay content. A multiaxis acceler-ometer in the tool monitors downhole tool orien-tation, motion and vibration. The tool also measures borehole inclination and temperature.

The array induction tool has ve median depths of investigation and three vertical resolu-tions. In some congurations, a combinable spon-taneous potential (SP) tool is run immediately below the induction tool. The SP measurement gives a qualitative indication of formation shali-ness and permeability and can be used to deter-mine equivalent formation water resistivity. A mud resistivity sensor is built in for array induc-tion corrections and analysis of borehole uids.

The SureLog neutron tool operates in both openhole and cased hole environments. It uses a californium [Cf] source to obtain thermal neu-tron porosity measurements. In addition to bore-hole temperature and pressure corrections, the neutron porosity measurement may be corrected for environmental factors such as hole size, mud type, mud weight, mudcake thickness, salinity and tool standoff.

The density tool measures formation bulk den-sity (b), photoelectric factor (Pe) and borehole size. The raw measurement processing includes a correction algorithm that preserves overall den-sity accuracy across a wide range of borehole sizes, mud types and mud weights. The tools scin-tillation detectors are housed in an articulated pad for better contact with the formation to improve overall measurement quality in deviated and rugose holes (next page, top left). The density tool uses a single-arm caliper to measure hole size and to press the tool against the formation.

The SureLog waveform sonic tool has a mono-pole transmitter and a six-receiver array. Waveforms recorded at each of the six receivers are subsequently processed using a slowness-time coherence technique to obtain compres-sional (Vp) and shear (Vs) velocities. Monopole shear velocity can be determined from the sonic measurement in formations whose compres-sional and shear velocities are faster than the acoustic velocity in mud (Vmud).

The Portal PDC bit is designed to allow log-ging tools to pass through the end of the drill-string without requiring removal of the bit. This bit is hollow at the center, with a 21/2-in. [63.5-mm] opening at its crownthe center of the bit face (next page, top right). The bit design is adaptable to almost any PDC bit model rang-ing in size from 57/8 in. to 121/4 in. in diameter. The bits are manufactured in a variety of blade and cutter congurations to accommodate drilling and lithology requirements.

> SureLog tool specications. Any of these tools may be combined to permit operators to run a triple- or quad-combo logging string. All tool diameters are small enough to run in 4-in. holes.

Measurements

Diameter

Length

Temperature

Pressure

Logging Speed

Vertical Resolution

Depth of Investigation

Hole Size

Gamma ray,borehole temperature,tool acceleration

2 1/8 in.

74 in. [188 cm]

300F [150C]

15,000 psi [103 MPa]

1,800 ft/h [550 m/h]

12 in. to 24 in.[30 cm to 61 cm]

12 in. [30 cm]

4 in. to 14 in.

Induction resistivity,spontaneous potential,mud resistivity

2 1/8 in.

185 in. [470 cm]

300F [150C]

15,000 psi [103 MPa]

3,600 ft/h [1,100 m/h]

1 in., 2 in. and 4 in.[3 cm, 5 cm and 10 cm]

10 in., 20 in., 30 in., 60 in. and 90 in.[25 cm, 51 cm, 76 cm, 152 cm and 228 cm]

4 in. to 14 in.

Bulk density,photoelectric factor,hole size

2 1/8 in.

128 in. [325 cm]

300F [150C]

15,000 psi [103 MPa]

1,800 ft/h [550 m/h]

9 in. to 12 in.[23 cm to 30 cm]

12 in. [30 cm]

4 in. to 16 in.

Shear and compressionalvelocity

2 1/8 in.

144 in. [366 cm]

300F [150C]

15,000 psi [103 MPa]

3,600 ft/h [1,100 m/h]

6 in. to 24 in.[15 cm to 61 cm]

3 in. [7 cm]

4 in. to 14 in.

Neutron porosity

2 1/8 in.

74 in. [188 cm]

300F [150C]

15,000 psi [103 MPa]

1,800 ft/h [550 m/h]

12 in. to 15 in.[30 cm to 38 cm]

10 in. [25 cm]

4 in. to 16 in.

Telemetry, Memory,Gamma Ray Tool

Induction Tool Neutron Tool Density Tool Sonic Tool

Summer 2012 47

A hangoff sub, positioned above the Portal bit, enables the logging sensors to extend immedi-ately beneath the bit when logging in memory mode. In this mode, the wireline is detached from the toolstring and retrieved to the surface. Batteries power the tools, and the log data are stored in onboard memory. The hangoff sub pre-cisely positions the logging tools as they extend through the opening in the bit. This sub restricts

the movement of a no-go collar located near the top of the logging toolstring. The sub prevents the no-go collar from traveling farther downhole while permitting the logging sensors to protrude into open hole, just beyond the bit face.

ThruBit surface pressure equipment is designed to control the well in the event of an unexpected surge in pressure. This equipment allows the driller to rotate and reciprocate the drillstring and to circulate while deploying log-ging tools.3 A float valve may also be installed in the bottomhole assembly (BHA) to provide an added measure of well control. This flapper-style float valve allows logging tools and ancil-lary equipment to pass through the valve in both directions.4

Downhole DeploymentThe ThruBit deployment system uses the Portal bit to ream and condition the wellbore in prepa-ration for logging. Once the BHA has reached log-ging depth, the drilling crew trips the BHA out of the hole to install a Portal bit and hangoff sub. As the Portal bit and hangoff sub are tripped back into the hole, the driller uses the Portal bit to ream past ledges and tight spots encountered on the way to TD. Once the wellbore is conditioned for logging, the driller positions the bit just above the base of the lowest interval to be logged,

leaving only enough open hole for the logging sensors to extend beyond the bit.

With the Portal bit at target depth, the logging crew inserts the SureLog toolstring into the drill-pipe, installs pressure control equipment and low-ers the SureLog suite of tools on wireline. The wireline connection allows the ThruBit logging engineer to create a downlog and monitor tool-string functionality from the moment the logging tools leave the surface until they are switched to memory mode. The drillpipe protects the logging tools and wireline as they are lowered downhole.

At the point where wellbore inclination pre-vents gravitational descent, the rigs mud pumps are engaged to pump the tools to the end of the drillstring. The drillpipe provides a smooth bore to ensure that the small-diameter tools deploy to the bit face. Pump pressure and mud ow force the logging sensors out through the opening in the Portal bit. The tools stop once the no-go

3. In some wells, the ability to circulate during logging may prove helpful in reducing borehole temperature when the bottomhole temperature approaches the tools temperature rating.

4. Reischman RL and Porter RC: An Innovative New System for Obtaining Open Hole Logs in Difcult Wells, paper AADE-11-NTCE-67, presented at the AADE National Technical Conference and Exhibition, Houston, April 1214, 2011.

> SureLog density tool. Scintillation detectors, housed in a pad that articulates from the main tool, measure both formation bulk density and photoelectric factor. The tool uses a single-arm caliper to increase overall pad contact with the formation while it measures borehole size.

Caliper

Densitypad

> Portal bit. This specialized bit is engineered to meet drilling requirements for a variety of rock types. The main feature of this PDC bit (side view, left) is a central hole (top view, right) to permit passage of the slim-diameter logging string. (Figure courtesy of Smith Bits, a Schlumberger company.)

48 Oileld Review

device near the top of the toolstring reaches the hangoff sub.

The logging engineer performs a nal check of toolstring functionality before opening the caliper on the density tool. Accelerometers inside the tool verify that the density skid is oriented against the low side of the hole. The logging engi-neer then signals the toolstring to release the wireline. The wireline and the upper part of a

dropoff and retrieval assembly are reeled back to the surface and removed from the drillstring. This leaves a shing neck exposed at the upper end of the logging tools to permit ready retrieval of the tools and the density and neutron sources through the drillpipe at any timeeliminating the need to trip pipe.

Operating in memory mode, the logging tools survey the formation and record the data as the

drillpipe is tripped out of the well. After the zone of interest has been logged, the logging crew can lower a retrieval tool on wireline to retract the logging tools back through the Portal bit and drillpipe. With the toolstring retrieved to the surface, the driller is free to resume normal oper-ations in preparation for the next phase of well activity (above). Alternatively, the tools can simply be tripped to the surface with the pipe.

> ThruBit logging sequence. A Portal bit is used to ream to TD to prepare the hole for logging (1). The driller pulls the bit off bottom, leaving enough room to accommodate the SureLog suite of logging tools. The logging toolstring is pumped through the drillpipe (2). With tools positioned beneath the bit, the ThruBit logging engineer veries tool function, then disconnects the wireline and draws the cable back to the surface (3). As the drilling crew trips pipe out of the hole, the logging tools survey and record formation data (4). Logging is complete when the tools are pulled up into the casing (5). With the bit and tools inside the casing, the logging crew lowers the retrieval tool on wireline, latches the tools and retrieves them to the surface (6). Once the logging tools are recovered from the drillstring, the driller is free to ream to the bottom or resume other operations in preparation for the next phase of drilling (7).

1

2

3

4

5

6

7

Summer 2012 49

However, early retrieval permits the data to be downloaded, veried and transmitted while the pipe is still being pulled out of the hole providing more time for the operator to plan com-pletion operations.

This deployment system can positively impact a logging operation. The rig time spent on acquiring logs is reduced because deploy-ment and acquisition can take place during the conditioning trip. Because they are not deployed until the bit is in position near TD, the tools receive less exposure to shocks, vibrations and high temperatures. Risk is minimized because the tools are retrievable and the system provides the driller with full well control capability. Thus,

if well conditions deteriorate, and the drillpipe becomes stuck, the logging tools and the density and neutron sources can be retrieved prior to activating jars or implementing other stuck pipe procedures. With the logging string laid out on the catwalk, the driller may jar the drillstring without fear of damaging the tools.

The exibility of this system is opening the way for its use in other challenging logging situations.

Field ApplicationsThe geometry of extended-reach wells makes them inherently difficult to log. Unconventional plays, commonly exploited through horizontal wells, have created a demand for specialized

conveyance techniques. As the number of plays proliferated across the US, they provided a proving ground for ThruBit logging technology. The use of this technology has since expanded to other unconventional plays where high-angle wells make logs difficult to obtain.

In North Dakota, USA, Oasis Petroleum, Inc. utilized the ThruBit logging system to evaluate a Bakken Shale well drilled to 20,766 ft [6,330 m] MD with a 10,000-ft [3,050-m] lateral section. The well had a 29.5/100-ft [29.5/30-m] radius of curvature and was deviated up to 91 from the vertical (below). Oasis used a Portal bit during the reaming run to prepare the hole for log-ging prior to running production liner. The

> Logging an extended-reach well. Oasis Petroleum used the ThruBit system to log a well drilled in the Bakken formation. The 20,766-ft well, with a 10,000-ft lateral section, was deviated up to 91. The hangoff assembly, battery and retrieval tool (inset) enable logs to be recorded in memory mode as pipe was tripped from the well. The tools can be retrieved at any time after the wireline is released. (Adapted from Reischman and Porter, reference 4.)

Drillstring

Intermediate casing

Drilled radius,29.5/100 ft

BHA SureLog logging string

Wired dropoffand retrieval tool

No-go collar Induction arraytool

Telemetry, memory,gamma ray tool

Densitytool

Caliper

Drillpipe Hangoff sub Portal bit

Batteries Neutrontool

Total length: 63.7 ft [19.4 m]

50 Oileld Review

ThruBit system enabled the driller to maintain circulation as logging tools were deployed around the curve and through the extended lateral sec-tion. The SureLog suite of logging tools safely passed through the drillpipe and out the bit to acquire formation evaluation data as the pipe was tripped out of the well. In a single logging run, Oasis geoscientists obtained the petrophysical data they needed to evaluate the Bakken section.

In Barber County, Kansas, USA, Osage Resources, LLC sought to optimize perforation placement and length of fracture stages in a horizontal well drilled in the Mississippi Lime play. This play, initially discovered and exploited through vertical drilling, is being revitalized through horizontal wells and multistage frac-ture stimulation treatments. The Mississippi Lime is highly variable, consisting of limestone, dolomite and siliceous deposits of tripolite, chert and spiculite. To properly evaluate the well, Osage needed more than an MWD gamma ray log.

The ThruBit logging crew made up a SureLog quad-combo toolstring, consisting of gamma ray, caliper, resistivity, neutron, density and sonic tools. This toolstring was pumped down through 4-in. drillpipe, and the logs were recorded in memory mode as drillpipe was tripped out of the hole. Once the logging tools reached casing, they were retrieved to the surface by wireline. With the 61/8-in. Portal bit still downhole, the driller was able to ream back to TD for a nal cleanup trip in preparation for a subsequent casing run.

The log data revealed signicant lithological changes along the length of the lateral wellbore (next page). This information prompted Osage engineers to reassess their initial stimulation strategy and shift focus toward treating the toe of the wellbore, where better reservoir condi-tions were found. Sonic data were used to com-pute a brittleness curve. This curve provided a basis for dividing the stimulation into separate intervals according to rock type, which helped the operator optimize stage lengths, pad sizes and perforation clusters. Sonic waveform data indicated where the formation was naturally fractured along the wellbore, which helped Osage engineers design a hydraulic fracturing program that minimized the risk of early screen-out during stimulation. They added another frac-turing stage to the plan and successfully completed the revised stimulation program. The well is producing signicantly better than other Mississippi Lime wells in the area.

South Texas, USA, has seen a resurgence in drilling as oil and gas companies pursue new unconventional plays. In Gonzales County, Forest Oil Corporation has drilled several wells to develop the Cretaceous Eagle Ford play. To exploit a rather narrow oil window, the company drills high-angle wells that target a 20 ft [6 m] thick sweet spot within an 80- to 110-ft [24- to 34-m] reservoir section. These wells are typically drilled to around 12,000 ft [3,660 m] MD, and are deviated between 87 and 92 with lateral sec-tions of about 5,500 ft [1,675 m] through the Eagle Ford.

Working from 3D seismic data obtained over the lease area, Forest geoscientists have identied a number of locations within the Eagle Ford to develop further. These locations were drilled with input from an MWD gamma ray tool for geosteering. Once drilled, early wells were stimu-lated using a geometric approach: divide the lateral section into 300-ft [90-m] stages, then per-forate and fracture, pumping 240,000 lbm [109,000 kg] of sand into each stage. To execute this strat-egy, Forest engineers used the plug and perf method, in which a bridge plug is set between frac-ture stages to isolate perforation clusters.

After completing several of these wells, Forest petrophysicists and engineers had acquired enough data to evaluate production in the Eagle Ford. The engineers noted that, although several wells had been drilled and com-pleted in a similar manner, production varied widely once the wells were brought on stream. Some wells were producing signicant volumes of high-salinity water, not common to either the Eagle Ford or the adjacent Austin Chalk forma-tion above. This water was attributed to the Buda or the Edwards Limestone and indicated that the hydraulic fractures had penetrated below the Eagle Ford, providing a water migration pathway to underlying formations.

Forest Oil engineers and geoscientists mounted a study to determine why some wells stood outeither as good or bad producersand to ne-tune their drilling and completion strategies in this formation. Their investigations sought to achieve the following outcomes:sOPTIMIZETHELANDINGSECTIONINFUTUREHORIZON-

tal wellssIMPROVEFRACTURECLUSTEREFlCIENCIESANDFRAC-

ture initiationsPREVENT WATER PRODUCTION FROM UNDERLYING

formationssREDUCESTIMULATIONANDCOMPLETIONCOSTS

Central to their study was the capability to acquire and analyze log data from the horizontal wellbores; thus, they carefully weighed the con-veyance options. Forest had concerns with slick-line retrievability of MWD components, needed for geosteering, in the event that LWD tools were used to evaluate the formation; other pipe- conveyed methods for logging consumed extra rig time. Needing to evaluate the producing zones, Forest used ThruBit logging to obtain a suite of logs in horizontal wells slated for an upcoming drilling campaign.

As these wells were drilled, the driller made a series of short trips to clean out cuttings beds from the horizontal section. Once the hole was conditioned, the driller tripped the directional BHA out of the well and ran back in the hole with a Portal bit and hangoff sub, reaming past any tight spots on the way to TD. The SureLog quad-combo logging suite was then pumped through the drillpipe to TD on wireline. The logging tools were pumped out through the Portal bit. Once the logging engineer veried toolstring operabil-ity, the tools were released from the wireline, which was reeled back to the surface. The logging tools recorded formation data in memory mode as the drillpipe was pulled out of the hole. After it reached the casing shoe, the toolstring was retrieved on wireline and the data were down-loaded. If needed, the driller could then make another conditioning trip back to TD before lay-ing down pipe for a casing run. By combining the logging run with a conditioning trip, the operator saved more than 24 hours of rig time when com-pared with the time needed for conventional pipe-conveyed methods.

Forest Oil petrophysicists used sonic and den-sity data to derive rock properties such as Youngs modulus and Poissons ratio. Shear-wave anisot-ropy from the SureLog sonic tool enabled Forest geophysicists to compare attributes of natural fractures in the wellbore with those seen in 3D seismic data. This information was instrumental in mapping new exploration targets and provid-ing a better understanding of the seismic attri-butes needed to evaluate their extensive acreage position for future drillsite selection.

Forest was able to capitalize on a more selective approach to fracturing. The mechani-cal properties data processed from the SureLog suite proved crucial for grouping hydraulic fracturing stages by highlighting rock of similar

Summer 2012 51

> Evaluating a lateral wellbore in the Mississippi Lime Formation. After running a SureLog quad-combo logging string in a horizontal well, Osage Resources engineers determined that formation properties varied considerably throughout the length of this horizontal interval. Porosity (Track 3) varies from 4% to 16%. The sonic waveform and shear semblance curves indicate natural fractures (Track 4, yellow) through some intervals. A brittleness calculation (Track 5), which is used to produce a quicklook curve related to the stress prole, also shows contrasts in brittleness. Based on these curves, along with elevated resistivities (Track 2), Osage Resources was able to select optimal zones for hydraulic stimulation (Track 4, yellow).

Caliper

in.

Depth,

ft166

10-in. Induction

ohm.m 2,0000.2

Crossover

Gamma Ray

Correlation Depth Resistivity Porosity Sonic Data Brittleness

gAPI 2000

Shear Wave Semblance

11

highlow

Brittleness

1000

20-in. Induction

ohm.m %2,0000.2

Photoelectric Factor

200

30-in. Induction

ohm.m 2,0000.2

Density PorositySonic Waveform Amplitude

% 1030

60-in. Induction

ohm.m 2,0000.2

Neutron Porosity

% 1030

90-in. Induction

ohm.m 2,0000.2

Density Correction

g/cm3 0.25 0.75

Possible Fractures More Brittle

X,050

X,100

X,150

52 Oileld Review

> Forest Oil log montage. This Eagle Ford formation evaluation interpretation combines ThruBit data with cuttings analysis and computed rock properties to determine the optimal placement of fracture stages in a South Texas well. Although gas spikes (Track 5, green) are seen throughout this interval, the sweet spot in this horizontal well extends from about W,700 to Z,400 ft measured depth. Onsite geochemical analysis of wellbore cuttings obtained through this interval shows a marked increase in total organic carbon, or TOC, (Track 2, black dots) and S2hydrocarbons generated by thermal breakdown of kerogens (Track 2, purple curve), key indicators of source rock quality. Sonic data (Track 7) show a clear change in the elastic properties of the formation in this zone. While the P-wave maintains a constant slowness (solid black) throughout the interval, the S-wave splits into two distinct arrivals. The spread between the fast (dashed black curve) and slow (black dotted) S-wave slownesses is an indicator of anisotropy, possibly attributed to fractures. Using all of the data together, Forest Oil elected to divide the stimulation program into 19 stages. After the stimulation treatment, tracer logs (Track 6) helped verify that modications to the stimulation program created more complex fractures throughout each stage, opening more rock face to production. This optimized completion strategy resulted in increases in production relative to surrounding wells that had used simple geometric fracture treatments.

Stage 1

Stage 3

Stage 4

Stage 6

Stage 7

Stage 9

Stage 12

Stage 13

Stage 15

Stage 16

Stage 18

Stage 19

Stage 10

Stage 2

Stage 5

Stage 8

Stage 11

Stage 14

Stage 17

U,000

V,000

W,000

X,000

Y,000

Z,000

MeasuredDepth,

ftTVD

Stagesft U,200V,200

Shear Slownesss/ft 40440

Compressional Slownesss/ft 40140

Neutron Porosity% 1545

TVDft U,200V,200

highlow

Mud Log Total Gas 5000

Shear Wave Semblance 0.51

TVDft U,200V,200

highlow

Strontium TracergAPI 2,0000

Scandium TracergAPI 2,0000

Iridium Tracer

Fast Shear Slowness

Compressional SlownessgAPI 2,0000

Sonic Waveform Amplitude

Slow Shear Slownesss/ft %24040

s/ft 24040TVD

Brittleness 1000

ft U,200V,200

s/ft 24040

Semblance

TVD

Cuttings Lithology Depth Fracture Sonic Data Sonic Waveform Mechanical PropertiesTracersResistivity, S2, TOC Density, Neutron, Sonic

ft U,200V,200

Cuttings: S2mg/g 250

Total Organic Carbon 100

Total Organic Carbon 100

S2mg/g

%

%

250

TVDft U,200V,200

Bulk Densityg/cm3 2.951.95

10-in. Inductionohm.m 2,0000.2

30-in. Inductionohm.m 2,0000.2

90-in. Inductionohm.m 2,0000.2

Porosity

Total Organic Carbon

Pyrite

Carbonate

Quartz

Total Clays

Summer 2012 53

properties (previous page). This information was used in 3D fracture design programs to opti-mize and conne the fractures to the Eagle Ford and overlying productive Austin Chalk forma-tions. Based on these log data, the company now plans 220-ft [67-m] fracture stages and has saved on stimulation costs by reducing the vol-ume of sand pumped into each stage by one-third. Wells stimulated in this manner are producing signicantly better than those frac-tured using the previous geometric approach, and none have produced the high-salinity water associated with deeper formations. Overall, Forest Oil has reduced completion cost per stage by about 60% while increasing the number of stages per lateral section. Also, oil production averaged over a 30-day period has doubled in comparison with the output of earlier wells.

Evaluation ToolsTo increase wellbore exposure to unconventional reservoirs, operators usually need to drill horizon-tal wells. These formations generally exhibit high natural gamma ray activity, so gamma ray logs are useful for distinguishing lithologies. Although effective as correlation tools, gamma ray measure-ments are not sufcient for distinguishing produc-tive from nonproductive zones, much less for designing stimulation programs.5

Rather than relying on a geometric approach to developing these wells, operators who run a comprehensive suite of logs across the target

zone can base their completion programs on res-ervoir quality and geomechanical properties. With this information, operators can selectively target the best zones to stimulate, while elimi-nating unproductive zones from their completion program. Compressional and shear velocity mea-surements from the SureLog multireceiver mono-pole sonic tool provide input for the ThruBit Geo-Frac analysis program to compute rock prop-erties, Poissons ratio, static Youngs modulus and minimum horizontal stress gradient. The stress data and indicators of reservoir quality, such as clay content and porosity, are useful in selecting optimal completion zones for hydraulic stimula-tion. Using the Geo-Frac analysis, the operator can identify zones along the lateral that are most likely to be productive (above).

Data from the Geo-Frac program may also be imported into Mangrove stimulation modeling software, which was developed by Schlumberger to address unconventional hydraulic fracture design. The Mangrove system generates a score based on reservoir quality and completion quality to rank the intervals of similar rock properties along a wellbore. Those intervals that score high in reservoir quality and completion quality are prime candidates for hydraulic fracture stimula-tion. This evaluation facilitates selection of loca-tions for optimal completion stages and perforation clusters.

Portal of OpportunityHigh-angle and extended-reach wells have been central to the development of new plays in tight res-ervoirs and organic-rich source rocks. To increase wellbore exposure to productive zones in these

plays, many operators drill horizontal wells; but drilling is only part of the storywell stimulation is another key to unlocking resources from formations previously deemed unproducible. Hydraulic frac-turing is typically required to stimulate these tight formations, and a number of advanced programs have been developed to help operators optimize the fracturing process for each well. All of these pro-grams rely on petrophysical data.

Well logs are vital for identifying intervals likely to benet most from stimulation. Operators who use this data-driven approach to selecting fracture intervals are able to reduce the amount of sand, water and horsepower expended. Without log data, they might be left with no choice but to stimulate the entire length of horizontal sectionwith little regard to reservoir and completion quality.

The ThruBit conveyance system helps E&P companies obtain valuable formation data along the entire length of the wellbore. It provides a cost-effective and operationally efcient alterna-tive to standard wireline conveyance or LWD log-ging while saving trip time. With a Portal bit conditioning the hole before the slim-diameter logging tools are run, the ThruBit system can acquire petrophysical data in the challenging, high-deviation and extended-reach wellbores that are common to unconventional plays. Using the drillstring as a protective conduit for the logging tools and wireline, this system reduces tool expo-sure to the openhole environment. ThruBit logging increases the likelihood of acquiring quality reser-voir log data on the rst attempt, particularly when hole conditions threaten the success of con-ventional conveyance methods. If the bit can reach the target, so can the logging tools. MV

> Geo-Frac evaluation of a horizontal well in the Bakken formation. SureLog compressional and shear sonic data (Tracks 4 and 5) are used to compute Poissons ratio (Track 6, red). Youngs modulus (Track 6, green), is derived from sonic and bulk density data. The brittleness curve (Track 7), which is estimated from Youngs modulus and Poissons ratio, indicates how easily the rock will fracture under hydraulic pressure. The fracture gradient (Track 8) may be used as an indicator of stress, showing contrasts along the length of the lateral with lower stresses (red and white) and higher stresses (blue). Used in conjunction with the other data presented, the brittleness and fracture gradient curves help operators determine intervals best suited for initiating fractures (Track 7, red).

Caliperin.

Depth,ft155

Gamma RaygAPI 1500

Brittleness 1000 %

Fracture Gradient 10 psi/ft

60-in. Induction ResistivityCompressional

Slowness

CompressionalSemblance

ohm.m s/ft200 2400.2 0

highlow90-in. Induction Resistivityohm.m 2000.2

Static Youngs Modulus 100

Poissons Ratio 10

psi 106

Photoelectric Factor

200

Density Porosity% 1030

Neutron Porosity% 1030

Density Correctiong/cm3 0.25 0.75

Shear Slowness

ShearSemblance

s/ft 2400

highlow

More Brittle Fracture Gradient

X,250

5. Kok J, Moon B, Han SY, Tollefsen E, Baihly J and Malpani R: The Signicance of Accurate Well Placement in the Shale Gas Plays, paper SPE 138438, presented at the SPE Tight Gas Completions Conference, San Antonio, Texas, USA, November 23, 2010.