Oilfield Review ( SCHLUMBERGER)

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Spring 2012 Quadrupole Sonic Logging While Drilling Jar Optimization The Future of Mud Logging Offshore Decommissioning Oilfield Review

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Transcript of Oilfield Review ( SCHLUMBERGER)

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Spring 2012

Quadrupole Sonic Logging While Drilling

Jar Optimization

The Future of Mud Logging

Offshore Decommissioning

Oilfield Review

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In September 2010, to hasten the removal of idle infra-structure on the outer Continental Shelf of the Gulf of Mexico, the US Department of the Interior issued decom-missioning guidance to operators and pipeline right-of-way holders. The intent of the notice to lessees (NTL) was to spur compliance with regulations issued in 2002 by the US Minerals Management Service regarding requirements for plugging wells, decommissioning platforms and pipelines and clearing sites.

The NTL was issued jointly by Interior Secretary Ken Salazar and Bureau of Ocean Energy Management, Regulation and Enforcement Director Michael R. Bromwich. According to the accompanying press release, the notice was issued to clarify earlier federal mandates that any well not used during the previous five years for exploration or production had to be plugged. Production platforms and pipelines associated with those wells and not involved with exploration and production activities also had to be decom-missioned. The result of the 2010 NTL directive is that operators must immediately begin the process of plugging and abandoning nearly 3,500 nonproducing wells and dismantling and removing about 650 platforms in the Gulf of Mexico.

There is little argument with the department’s intent. In recent years, hurricanes Ivan, Katrina and Rita have made clear the potential danger when idle iron, weakened by years of neglect and decay, is torn loose and pushed about the gulf during a storm. Likewise, as some unfortunate offshore operators can attest, it is significantly less costly to dismantle and remove stable structures than those that have been scattered about the ocean floor, floated miles from their original locations or tilted at precarious angles by hurricane force winds and seas.

For these reasons, and in keeping with their role of envi-ronmental stewards anxious to prevent leaks or other forms of pollution entering the gulf waters from disinte-grating infrastructure, operators should share the desire of the US Department of the Interior to rid the gulf of much of this idle iron. And just as it is in the industry’s best interest to embrace this effort, it is hoped that the admin-istration will see that it is in the interest of the US to tem-per enforcement of the mandate with reason.

Regulators should make decommissioning decisions not according to some arbitrary timetable, but by using a risk-based approach that will prevent premature removal of infrastructure. Regulators should consider, for instance, whether some platforms, pipelines and well-heads are idle because there is no oil or gas in or near the reservoirs they once served, or because the remaining resources cannot be brought to the surface economically

Offshore Idle Iron: Remains of the Past or Infrastructure of the Future

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using currently available technology. The distinction is important because, owing to the petroleum industry’s remarkable ability to innovate, resources not seen or accessible today may very well be both visible and acces-sible within the next few years.

The industry has long held this position to justify post-poning plugging operations until within one year after the lease runs out—the absolute regulatory deadline for decommissioning. The new mandate seems to cast aside the industry reasoning, which is a mistake.

It may be particularly instructive for regulators to consider the example of the now mature practice of extended-reach drilling. Today, this technique allows operators to construct wellbores that reach and drain reserves that are horizontally and vertically miles from the wellhead. The implication for breathing new life into old infrastructure is clear; old platforms and pipelines once used to support a now-depleted field may be used to access and service nearby reserves too small to justify new surface facilities but reachable and profitable using new directional drilling technology. Other examples of game-changing innovations are 3D seismic, logging and measuring while drilling, and real-time monitoring and control of drilling and production—all introduced and refined within the past two decades.

The intent of the Department of the Interior is valid. But all parties concerned, including the public, will be best served if the decision to order the decommissioning of individual pieces of infrastructure is balanced by consider-ing whether realistic, imminent technological advances are in the offing that might dictate leaving them in place.

Holly HopkinsSenior Policy Advisor, Upstream and Industry OperationsAmerican Petroleum InstituteWashington, DC

Holly Hopkins is a Senior Policy Advisor, Upstream and Industry Operations for the American Petroleum Institute (API). Her experience on environmental and energy issues includes work both inside and outside the US federal government. She staffs the API Drilling and Production Operations Subcommittee, which includes oversight of upstream safety, and staffs two of the four joint industry task forces formed in response to the Gulf of Mexico Macondo incident: the Offshore Equipment Task Force and the Subsea Well Control and Containment Task Force. Prior to joining API, she was a policy consultant to the Consumer Energy Alliance (CEA), providing advice and guidance to CEA members regard-ing the US government executive branch, specifically the US Department of the Interior (DOI) and the Minerals Management Service (MMS). From August 2001 to January 2009, Holly worked for the US DOI in several capacities. Most recently she served as the chief of staff to the MMS. Holly also served as MMS liaison to the assistant secretary, Land and Minerals Management and as spe-cial assistant to the deputy secretary. Prior to working for the DOI, she worked as a policy assistant at National Environmental Strategies, Washington, DC.

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Schlumberger

Oilfield Review

1 Offshore Idle Iron: Remains of the Past or Infrastructure of the Future

Editorial contributed by Holly Hopkins, Senior Policy Advisor, Upstream and Industry Operations, American Petroleum Institute

4 Sonic Logging While Drilling—Shear Answers

Modern sonic tools, which measure acoustic properties of rocks, provide compressional and shear wave data that engineers use to compute in situ mechanical properties. These properties are useful for determining optimal drilling parameters and identifying rocks with better completion characteristics. Until recently, acquiring shear wave data in all formations was not possible while drilling. New LWD tools and processing techniques enable shear wave data to be measured in real or near–real time. This information can be used to improve drilling efficiency and safety. Engineers can also characterize environments where acoustic measure-ments are difficult to obtain, such as highly deviated and horizontal wells. The results are better drilling and comple-tion decisions for operators.

16 Working Out of a Tight Spot

Stuck pipe costs operators hundreds of millions of dollars per year as a result of nonproductive time during drilling opera-tions. For this reason, for decades, drillers have included drill-ing jars in their toolstring as the first response to drillpipe that cannot be moved up or down or be rotated. Today, advances in the technology of jarring operations have extended their appli-cation to horizontal and highly deviated wells.

Executive EditorLisa Stewart

Senior EditorsMatt VarhaugRick von Flatern

EditorsRichard Nolen-Hoeksema Tony Smithson

Contributing EditorsJudy FederGinger OppenheimerRana Rottenberg

Design/ProductionHerring DesignMike Messinger

IllustrationChris LockwoodTom McNeffMike MessingerGeorge Stewart

PrintingRR Donnelley—Wetmore PlantCurtis Weeks

Oilfield Review is published quarterly and printed in the USA.

Visit www.slb.com/oilfieldreview for electronic copies of articles in English, Spanish, Chinese and Russian.

© 2012 Schlumberger. All rights reserved. Reproductions without permission are strictly prohibited.

For a comprehensive dictionary of oilfield terms, see the Schlumberger Oilfield Glossary at www.glossary.oilfield.slb.com.

About Oilfield ReviewOilfield Review, a Schlumberger journal, communicates technical advances in finding and producing hydrocarbons to employees, clients and other oilfield professionals. Contributors to articles include industry professionals and experts from around the world; those listed with only geographic location are employees of Schlumberger or its affiliates.

On the cover:

Mud logging serves a variety of important functions at the wellsite. By monitoring an array of drilling sensors and sampling formation cuttings and mud gas, mud loggers are able to recognize when the drill bit has penetrated a productive formation. As formation and pressure evaluation specialists, they also track drilling parameters to help the driller safely reach total depth. Here, a mud logger heads to the shale shaker to collect a sample of formation cuttings.

2

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Spring 2012Volume 24Number 1

ISSN 0923-1730

51 Contributors

53 New Books and Coming in Oilfield Review

55 Defining Perforating:Detonation for Delivery

This is the fifth in a series of introductory articles describing basic concepts of the E&P industry.

3

24 The Expanding Role of Mud Logging

Among its many important functions, drilling mud transports formation cuttings and formation fluids from the bit to the sur-face. For decades, analysis of these samples by mud loggers provided operating companies with some of the earliest indica-tors of reservoir potential. Today, advances in surface sensor design and automated monitoring give mud loggers powerful tools for improving drilling efficiency and safety. At the same time, new mud gas sampling and analysis techniques provide first insights into fluid composition and reservoir geochemistry, in advance of wireline sampling runs and well tests.

42 Offshore Permanent Well Abandonment

As deepwater fields become depleted, the offshore industry is tasked with permanently abandoning thousands of subsea wells and hundreds of platforms. Government directives are speeding the pace of decommissioning activity, which has added to operators’ burdens. Offshore service providers are trying to minimize the financial impact of these costly opera-tions through innovative technology and methods that reduce the time required to perform them.

Gretchen M. GillisAramco Services CompanyHouston, Texas, USA

Roland HampWoodside Energy Ltd.Perth, Australia

Dilip M. KaleONGC Energy CentreDelhi, India

George KingApache CorporationHouston, Texas

Alexander ZazovskyChevronHouston, Texas

Advisory Panel

Editorial correspondenceOilfield Review5599 San Felipe Houston, Texas 77056 USA(1) 713-513-1194Fax: (1) 713-513-2057E-mail: [email protected]

SubscriptionsClient subscriptions can be obtained through any Schlumberger sales office. Clients can obtain additional subscrip-tion information and update subscription addresses at www.slb.com/oilfieldreview.Paid subscriptions are available fromOilfield Review ServicesPear Tree Cottage, Kelsall RoadAshton Hayes, Chester CH3 8BH UKFax: (44) 1829 759163E-mail: [email protected]

Distribution inquiriesTony SmithsonOilfield Review12149 Lakeview Manor Dr.Northport, Alabama 35475 USA(1) 832-886-5217Fax: (1) 281-285-0065E-mail: [email protected]

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Sonic Logging While Drilling—Shear Answers

Engineers use acoustic data from sonic logging tools to drill more efficiently with

greater safety margins and to optimize completions. LWD sonic tools introduced in

the mid-1990s delivered compressional wave data but were unable to provide shear

wave data in all formations. A new LWD acoustic tool measures shear wave data in

formations where this was previously impossible, and engineers are using this

information to drill with greater confidence, determine optimal directions for drilling

and identify rocks with better completion characteristics.

Jeff AlfordMatt BlythEd TollefsenHouston, Texas, USA

John Crowe Chevron Cabinda Gulf Oil Company LtdLuanda, Angola

Julio Loreto Sugar Land, Texas

Saeed MohammedDhahran, Saudi Arabia

Vivian PistreSagamihara, Japan

Adrian Rodriguez-HerreraBracknell, England

Oilfield Review Spring 2012: 24, no. 1.Copyright © 2012 Schlumberger.For help in preparation of this article, thanks to Raj Malpani, Houston; and Utpal Ganguly, Sugar Land, Texas.Mangrove, Petrel, SonicScope, Variable Density and VISAGE are marks of Schlumberger.

The downhole drilling environment creates inhospitable conditions for logging-while-drilling (LWD) tools. The drill bit grinds through layers of rock as the rotating drillstring and BHA continu-ally slam against the borehole wall, shocking sen-sitive electronic components. Drilling mud surges through the drillpipe and exits through the bit, sweeping the hole clean and returning cuttings to the surface. Although LWD tools are designed to endure these environments, LWD sonic tools are

further required to acquire data in a setting inun-dated with noise and vibration.

Sonic acquisition is challenging while drill-ing; however, service companies have worked to develop LWD sonic tools because they provide information that is not readily available from other logging devices while drilling. Measure-ments derived from the propagation of sound waves through porous media provide helpful information about geologic and geophysical

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properties. Petrophysicists have developed meth-ods to use real-time acoustic measurements to determine formation attributes that include pore pressure and overburden gradients, lithology and mechanical properties. Petrophysicists also use sonic data for gas detection, fracture evaluation and seismic calibration.

The first LWD sonic tools, introduced in the mid-1990s, provided compressional wave measure-ments, along with shear wave data in some forma-tions. These data were used for computing sonic porosity, estimating pore pressure and correlating downhole depth-based data with surface seismic time-based data. Wireline sonic tools used differ-ent sources and, because they could process and transmit data at higher rates, provided answers that were beyond the capability of their early LWD counterparts. These capabilities include measure-ments of high-quality compressional and shear wave information to estimate geomechanical prop-erties in soft formations and the ability to deter-mine the orientation of rock properties in anisotropic formations. A recently introduced LWD sonic tool provides real-time compressional and shear wave data in formations where this was not possible with earlier tools.

This article reviews the use of sonic data in oil and gas operations, with special emphasis on LWD tools. A discussion of quadrupole sonic mea-surements is included, along with the process of deriving mechanical properties from sonic data. Case studies demonstrate how engineers have been able to extract shear data in soft formations using quadrupole sonic modes. These data, along with compressional data, are then used to opti-mize drilling practices, monitor real-time pore pressure while drilling, improve completions and estimate geomechanical formation properties.

Some Sound BasicsAcoustic logging tools measure the time it takes for an audible pulse of sound to travel from a trans-mitter, through the mud, along the borehole, back through the mud and then to an array of receivers along the body of the tool. This measured time equals the cumulative time of travel through the various media that have been traversed.

The velocity of the sound wave measured across the receiver array is the speed of sound through the formations directly opposite the receivers. Petrophysicists refer to this measure-ment as slowness—the inverse of velocity; it is expressed as traveltime per unit length. This measurement is also referred to as a delta t (Δ t)measurement because it is the interval transit time for the sound wave to travel through 1 m or 1 ft of formation.

Sound waves propagate through a solid medium in a variety of modes, such as compressional and shear waves, and these modes have different veloc-ities (above). In addition to these, other modes, including Rayleigh, mud and Stoneley waves, can be identified in the sonic signal.1

Many materials have been characterized by their acoustic slowness (below). For instance, a compressional sound wave travels through steel at 187 μs/m [57 μs/ft]. Compressional waves travel through zero-porosity sandstone at approx-imately 182 μs/m [55.5 μs/ft] and through limestone at around 155 μs/m [47.3 μs/ft].Compressional waves that pass through forma-tion rocks containing water, oil or gas have longer traveltimes than through rocks with no porosity.

The change in traveltime is related to the volume of fluid in the rock’s pore space, which is a func-tion of the porosity. Sonic porosity measurements were a key driver in the initial development of acoustic logging tools.

Depending on the physical measurement needed, the acoustic logging tool can be designed with transmitters, or sources, to generate a par-ticular type of pressure pulse. The most basic form, and the type that is common across all forms of acoustic tools, is the monopole source. Monopole sources produce a radial pressure field, analogous to the wave pattern produced by a pebble dropped onto the surface of a pond but in three dimensions. They are used primarily to obtain the compres-sional slowness of the formation.

> Acoustic waves. Sonic tools measure the time it takes for an acoustic pulse of sound to travel from a transmitter to a receiver array. The sound wave strikes the borehole, travels through the formation and then arrives back at the tool where the receivers measure the amplitude of the signal versus time. As the sound wave passes through rock, different types of waves are generated. The first two arrivals are the compressional, or P-waves, followed by shear, or S-waves. These two are the most important for oilfield applications because they are used to compute porosity and mechanical properties. Rayleigh, mud and Stoneley waves arrive later.

S-wave andRayleigh wave arrivals

Ampl

itude

Stoneley wavearrivals

P-wavearrivals

Time

Mud wavearrivals

Transmitterpulse

> Characteristic values for compressional wave slowness (Δ tc) and shear wave slowness (Δ ts).

Steel

MaterialCompressionalSlowness TimeΔtc, μs/m [μs/ft]

Shear Slowness TimeΔts, μs/m [μs/ft]

Sandstone

Limestone

Dolomite

Shale

Freshwater

Brine 620 [189]

715 [218]

200 to 300 [61 to 91]

143 [43.5]

155 [47.3]

182 [55.5]

187 [57]

Not applicable

Not applicable

varies

236 [72]

290 [88.4]

289 [88]

338 [103]

1. Rayleigh waves, named for Lord Rayleigh, who predicted their existence in 1885, are frequency-dependent dispersive waves that travel along the surface of the borehole. Rayleigh waves are used to evaluate velocity variation with depth. Mud waves are arrivals from the original sonic pulse that have traveled from the

transmitter through the mud column and are then detected at the tool receivers. Stoneley waves, named for Robert Stoneley, are surface waves that are associated with the solid/fluid interface along a borehole wall. They are used to estimate fracture density and permeability.

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As part of the process to measure compres-sional slowness, a monopole source generates a compressional wave in the borehole fluid sur-rounding the tool. The wave pattern expands radially, traveling at the compressional slowness of the fluid, until it encounters the borehole wall, where some of the energy is reflected back and some is refracted into the formation (below).

Snell’s law defines the relationship between the angle of refraction and the ratio of sound velocities in the fluid and the formation.2 The energy that is critically refracted travels along the borehole wall toward the receivers. The refracted energy propagates through the forma-tion as a compressional wave and travels faster than the fluid wave because the formation is stiffer than the fluid.

The critically refracted compressional wave generates a head wave in the borehole that travels at the formation compressional velocity.3 Following Huygens principle, at each point along the bore-hole wall, the compressional wave acts as a new source, transmitting waves back into the borehole.

The compressional head wave eventually arrives at the receiver array, allowing computation of the compressional velocity of the formation.

When the compressional wave from a mono-pole source is refracted into the formation, some compressional energy is converted to shear waves that refract into the formation. Whereas com-pressional waves propagate through both the fluid-filled borehole and the porous rock matrix, shear waves are not supported by fluids and prop-agate through fluid-filled porous media by travel-ing from grain to grain through the rock matrix. If the shear slowness in the formation is less than the compressional slowness in the borehole fluid—a situation known as a fast formation—the refracted wave is critically refracted and gen-erates a shear head wave in the borehole. This head wave travels at the shear velocity of the for-mation and may be detected by the receiver array. In this way, monopole acoustic tools can provide shear velocities, but only in the case of fast formations.

If the shear slowness in the formation is greater than the compressional slowness in the borehole fluid—a condition known as a slow for-mation—the compressional wave will still refract upon reaching the borehole, but the angle of refraction is such that critical refraction never occurs, and no head wave is produced in the bore-hole. Therefore, no shear head wave is detected at the receivers, and the shear velocity cannot be determined. This is a fundamental limitation of monopole sources for acoustic logging.

The ability to measure shear slowness with a monopole source thus depends on both borehole fluid and formation properties. Borehole fluid slowness values vary from around 620 μs/m[189 μs/ft] for water-base muds to 787 μs/m[240 μs/ft] or slower for synthetic oil-base muds. Slow formations are common at shallow well depths because of a lack of compaction by over-burden pressure. For the same reason, slow for-mations are common in deepwater drilling environments. Shear data, which are crucial for determining wellbore strength and stability in slow formations, cannot be extracted from data acquired with tools that employ only monopole sources. In wellbore sections where these data are often most needed, they are unavailable.

Limitations of monopole sources in measur-ing shear wave data in slow formations led to the development of dipole logging technology.4 Tools with dipole sources generate a flexural wave that is analogous to shaking the borehole (next page).Flexural waves are dispersive—their speed var-ies with frequency—and at low frequencies, they travel at the velocity of shear waves. Tools with dipole sources have the ability to deliver shear slowness measurements regardless of the mud slowness; therefore, they are useful for obtaining slowness measurements in slow formations.

The dipole source is also directional in nature, and by using directional receiver arrays and two such sources separated by 90°, engineers are able to derive oriented shear data from around the wellbore. This cross-dipole measurement pro-vides information such as maximum and mini-mum stress azimuths, radial velocity profiles with distance away from the borehole wall and the orientation of anisotropic shear data.

Wireline acoustic logging tools that combined a monopole source for compressional and shear data in fast formations and cross-dipole sources for oriented shear data in slow formations were introduced in the 1980s. Service companies con-tinue to use tools of this type, although current wireline tools with these sources can deliver a

> Sonic waves from monopole sources. Monopole sonic tools generate a pulse of energy that strikes the formation and then travels along the borehole as a compressional head wave. In hard, or fast, formations (top left), the compressional wave, or P-wave, generates shear waves, or S-waves, that arrive later in time than P-waves (bottom left). Soft, or slow, formations (top right) sustain shear waves, but they are refracted into the formation and may not arrive at the receivers (bottom right).Current tools have multiple receivers, and the sonic signal arrives later as the transmitter-receiver distance increases. Although the signal amplitude diminishes with distance between transmitter and receiver, data can be time shifted and stacked to improve coherence and signal-to-noise ratio. Stoneley waves (green) arrive later in time than the P- and S-waves.

P-wave P-waveS-wave

Fast Formation Slow Formation

Stoneley wave Stoneley wave

Compressional wave

Compressional waveShear wave

Fluid wave

Monopolesource

Monopolesource

Fluid wave

Head waves

Wellbore Wellbore

Head wave

Tran

smitt

er-re

ceiv

er d

ista

nce

Tran

smitt

er-re

ceiv

er d

ista

nce

Traveltime Traveltime

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wider range of measurements for petroleum applications than the earlier tools could.5

A third acoustic source, which was recently introduced for oilfield applications, generates quadrupole waves. At very low frequencies, these waves travel through the formation at a speed comparable to that of shear waves. As with dipole shear data, the quadrupole data converge asymp-totically to the shear wave velocity.6 Although somewhat similar to dipole waves, they exhibit a different propagation pattern, which is more dif-ficult to conceptualize. Another term applied to them—screw waves—presents an image of how they travel along the borehole. At present, ser-vice companies use quadrupole sources in LWD tools only.

The Rise of LWD Acoustic ToolsWireline acoustic tools deliver high-quality mea-surements in a relatively low-noise environment, but they have shortcomings. The lag between drilling and logging, along with conveyance meth-ods needed to deploy wireline tools, presents complications. Delivering tools to TD in extended-reach horizontal wells can also be complicated and time consuming, although a number of con-veyance techniques have evolved over the years.7

Furthermore, wireline sonic tools should be cen-tralized, and tool weight can make this problem-atic in high-angle and horizontal wellbores. In addition, shutting down drilling operations while logging dramatically increases the incremental cost of the logging operation, particularly in deepwater drilling operations where rig spread

rates—the total daily operating cost—routinely reach US$ 1 million.

For many applications, including pore pres-sure prediction and wellbore stability analysis, the ability to acquire data during the drilling pro-cess, and use the data as soon as possible, signifi-cantly increases the value of the data. Wireline measurements are obtained days or even weeks after a formation has been drilled, and therefore may be useful only for problem review or for plan-ning future wells.

Acoustic data are also affected by borehole conditions and challenges—such as mud filtrate invasion and rugosity—that may introduce mea-surement errors, the severity of which tends to increase with time after an interval has been drilled. Additionally, in settings involving damaged

2. Dutch mathematician Willebrord Snellius is credited with formulating the laws of refraction of waves. Snell’s law states that the ratio of the sines of the angles of incidence, i, and refraction, R, is equivalent to the ratio of phase velocities, V, in the two media. In this case, the media are the mud, m, and the formation, ƒ . The relationship can be written as follows:

Critical refraction occurs when the angle of refraction is greater than or equal to 90°, meaning the wave travels along the borehole wall.

> Acoustic sources. Three types of acoustic sources are used in well logging: monopole (top), dipole (center) and quadrupole (bottom).Monopole sources generate sound waves that radiate from the tool and travel through the formation as compressional waves. Dipolesources generate directional flexural waves. Cross-dipole sources emit two flexural waves that are oriented 90° apart. Quadrupole sources generate complex waveforms that are frequency dependent. At very low frequencies, they travel at velocities that approximate the velocity of shear waves. The blue stars represent the approximate location along the borehole of the wave represented in the cross section.

Monopole mode

Quadrupole mode

Dipole mode

90Azimuth

Flexural wave 1

Flexural wave 2

Nondeformedcross section

Radi

aldi

spla

cem

ent

180 270 360

90Azimuth

Radi

aldi

spla

cem

ent

180 270 360

90

AzimuthRa

dial

disp

lace

men

t

180 270 360

Compressional wave

Borehole Cross Section Radial Displacement Radiation Patterns

Flexural wave 1 Flexural wave 2

Quadrupole wave

3. Named for Dutch scientist Christiaan Huygens, the Huygens principle states that every point of a wavefront may be considered the source of secondary wavelets that spread out in all directions with a speed equal to the speed of propagation of the waves.

4. For more on cross-dipole sonic tools: Brie A, Endo T, Hoyle D, Codazzi D, Esmersoy C, Hsu K, Denoo S, Mueller MC, Plona T, Shenoy R and Sinha B: “New Directions in Sonic Logging,” Oilfield Review 10, no. 1 (Spring 1998): 40–55.

5. For more on advances in sonic logging: Arroyo Franco JL,Mercado Ortiz MA, De GS, Renlie L and Williams S: “Sonic Investigations In and Around the Borehole,” Oilfield Review 18, no. 1 (Spring 2006): 14–33.

6. A dispersion plot of shear slowness from dipole data versus the frequency of the acoustic wave will converge asymptotically on the formation shear slowness.

7. For more on logging tool conveyance methods: Billingham M, El-Toukhy AM, Hashem MK, Hassaan M, Lorente M, Sheiretov T and Loth M: “Conveyance—Down and Out in the Oil Field,” Oilfield Review 23, no. 2 (Summer 2011): 18–31.

sin i = .sin R

VmVƒ

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or unstable boreholes, wireline tools may not be able to reach TD, or operators may choose to forgo logging operations out of concern for tool sticking. These concerns led, in part, to the development of LWD acoustic tools.

The LWD sonic tools introduced in the mid-1990s used monopole sources and measured formation compressional slowness.8 These mea-surements were made available in real time by sending the acoustic data, along with other LWD measurements, to the surface using mud pulse telemetry systems.

Engineers could monitor pore pressure trends and compute sonic porosity from com-pressional data, and geophysicists could relate depth-derived borehole events with time-based surface seismic events. Using pore pressure trends measured while drilling, engineers can

avoid hazards such as drilling into overpressured zones and can optimize drilling mud density. For advanced processing, such as extracting shear data in fast formations, full waveforms for each transmitter firing were available, but were stored in memory and retrieved when the tools returned to surface.

Over the years, LWD sonic tools have evolved through several stages, primarily focusing on enhancing reliability and consistency of mono-pole-derived answers and increasing the amount of data available in real time. One hurdle to the development of LWD sonic tools was accounting for the energy from the transmitter that arrived at the receiver array after passing through the body of the tool. For integrity during drilling and because they must be as strong as the rest of the drillstring, LWD tools are built into steel drill

collars. Sound waves propagate easily through these collars and their arrival at the receivers overwhelms the signals from the formation. Eliminating collar arrivals was a considerable problem for early generation tools.

Slotted tool housings and materials designed to attenuate tool arrivals for wireline sonic tools are not an option for LWD tools, so engineers had to develop other methods to limit the energy coupled directly from the collar. Early generation LWD sonic tools featured heavily grooved collars, which were successful in limiting the effects of tool arrivals on the measured data. This design, however, resulted in a collar that was more flexi-ble than the rest of the BHA, which increased the tool’s susceptibility to shock, vibration, tool tilt between receivers and eccentering.

One of the most crucial shortcomings that engineers sought to address was the inability to obtain shear data in all formations, which mono-pole sources could not do. Engineers first attempted to replicate the physics upon which wireline tools are based. Experimenting with dipole sources, they discovered that at precisely the frequency range needed to acquire shear information in most formations, there was inter-ference between the dipole collar flexure signal and the formation signal (above left). Therefore, instead of dipole measurements, Schlumberger and other service companies adopted a quadru-pole technique for LWD sonic tools.9

As with dipole waves, quadrupole waves are dispersive, meaning their velocity depends on frequency. At low frequencies, the velocity approaches an asymptote equal to the shear velocity of the formation. Processing and an inversion technique extract shear slowness val-ues from the measured quadrupole dispersion data. However, because the low-frequency com-ponents of the quadrupole signal attenuate quickly, the quadrupole dispersion profile does not reach the asymptote of formation shear speed as clearly as the dispersion data from flexural waves created by dipole sources.

The more dispersive profile of quadrupole data may result in a wave velocity that falls below the actual formation shear speed. Quadrupole data are affected by formation properties, bore-hole conditions, drilling mud properties, tool characteristics and the tool’s presence and posi-tion in the wellbore. It is crucial that engineers understand these effects, which can be tool spe-cific, to extract shear slowness from quadrupole data. In addition, the processing of quadrupole data is more complex than the processing of dipole data.10

8. Degrange J-M, Hawthorn A, Nakajima H, Fujihara T and Mochida M: “Sonic While Drilling: Multipole Acoustic Tools for Multiple Answers,” paper IADC/SPE 128162, presented at the IADC/SPE Drilling Conference and Exhibition, New Orleans, February 2–4, 2010.

9. For a detailed explanation of quadrupole modeling and processing: Scheibner D, Yoneshima S, Zhang Z, Izuhara W, Wada Y, Wu P, Pampuri F and Pelorosso M: “Slow Formation Shear from an LWD Tool: Quadrupole Inversion with a Gulf of Mexico Example,” Transactions of the SPWLA 51st Annual Logging Symposium, Perth, Western Australia, Australia, June 19–23, 2010, paper T.

> Dipole sources in wireline and LWD tools. Flexural waves from dipole sources are dispersive. A wireline tool (left) in the borehole is designed so that the flexural signal (blue line) passing through the body of the tool does not interfere with the formation flexural slowness data (red). Slowness data plotted versus frequency on a dispersion plot will approach the formation shear slowness value at the asymptote (horizontal dashed line). To withstand the rigors associated with drilling, LWD sonic tools (right) are built into a stiff drill collar. The flexural wave (green) that propagates through an LWD tool interferes with and distorts the measurement (heavy dashed black line) such that it does not follow the shear slowness asymptote of the formation flexural response (red). For this reason, service companies have adopted quadrupole sources rather than dipole sources for LWD sonic tools.

Formation shearslowness

Shear asymptote

Weak interference

Tool flexuralresponse

Wellbore

Formation flexuralresponse

Frequency

Slow

ness

Slow

ness Strong interference

LWD dipole sonictool response

Frequency

LWD DipoleWireline Dipole

Tool Tool

Wellbore

10. Scheibner et al, reference 9.11. The SonicScope tool can also generate cross-dipole

flexural waves but they are not currently used. 12. Bulk density is usually provided by a density porosity

measurement.13. Named for 17th century British physicist Robert Hooke,

this law states that the strain within an elastic material is proportional to the applied stress. For anisotropic media, the law can be expressed as a second-rank stiffness tensor.

14. Zoback MD: Reservoir Geomechanics. New York City: Cambridge University Press, 2007.

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Spring 2012 9

Wideband multipole transmitter

48 wideband digital receivers

> SonicScope LWD tool. Built into a stiff drill collar that is about 9 m [30 ft] in length, the SonicScope tool has a wideband multipole transmitter and can be programmed to acquire data in several modes. The 48 receivers located on the outside of the tool are 4 in. apart and provide high-resolution data at high spatial density.

Engineers have performed extensive modeling and testing to confirm the validity of quadrupole source technology and of the processing technique used to extract shear data in slow formations. Because of these efforts, quadrupole sources are the common mode used by service companies for extracting shear data in slow formations using LWD tools, although the methods of extracting the answers differ from company to company.

Quadrupole LWD sonic tools offer answers that were not available from monopole tools. However, they do not yet fully replace the capa-bilities of cross-dipole wireline tools because quadrupole sources are not directional. But this newly acquired ability to deliver shear data for fast and slow formations in real time greatly increases the value of LWD sonic tools.

The Scope of LWD Tool DesignTo address the need for a quadrupole LWD tool, Schlumberger developed the SonicScope multi-pole sonic while drilling tool. The SonicScope tool has a wide spectrum of applications because it can acquire data in several modes. Although the answers depend on the type of data acquired and how it is processed, drillers, geophysicists, geologists, petrophysicists, reservoir engineers and completion engineers can all use the infor-mation it provides.

The SonicScope tool acquires monopole and quadrupole measurements using a powerful broad-band transmitter that excites the borehole in both modes over a frequency range from 1 to 20 kHz.11

There are 48 receiver sensors with 10-cm [4-in.] spacing mounted on the outside of the tool in pro-tected grooves positioned 90° apart (above right).The receivers are arranged in four arrays that pro-vide 12 axial and 4 azimuthal measurements. Each array contains 12 digitizers, one for each sensor. The transmitter-to-receiver spacing is optimized to maximize the signal-to-noise ratio. The tool’s 1-GB memory capacity enables the recording of all modes even with data recording rates of up to once per second. The current version of the tool has a 43/4-in. diameter; larger tools, with diameters of 63/4,81/4 and 9 in., are in development.

Generally, the tool is programmed in the field to record high-frequency monopole measure-ments for compressional slowness and shear slowness in fast formations, low-frequency mono-pole data for Stoneley waves and quadrupole data for shear acquisition in slow formations. For the quadrupole mode, data are acquired in a fre-quency range down to 2 kHz. From dispersion analysis, which uses an inversion algorithm to

best fit modeled responses, engineers can extract shear slowness values lower than 2,000 μs/m[600 μs/ft]. The SonicScope tool is fully combin-able with other MWD and LWD tools. When com-bined with other measurements, such as density data, the acoustic data offer solutions for applica-tions that include seismic correlation, pore pres-sure determination, log interpretation in complex lithologies and geomechanical rock properties.

Using the DataIn situ geomechanical properties cannot be mea-sured directly; however, they can be computed using compressional and shear slowness values in combination with the bulk density of the rock.12 For the case of isotropy, in which mate-rial properties are the same in every direction, geomechanics specialists apply Hooke’s law of elasticity to derive simple equations that use log-derived measurements to calculate several elastic moduli (right).13 The compressional modulus, M (also referred to as the P-wave or longitudinal modulus), is computed from com-pressional wave data. Similarly, the shear modu-lus, G, a measure of a material’s ability to withstand shearing, is computed from the shear wave data. Once these two values are deter-mined, the bulk modulus, K; Young’s modulus, E;and Poisson’s ratio, ν, can be calculated.

The bulk modulus is the ratio of average nor-mal stress to volumetric strain and is the extent to which a material can withstand isotropic compressive loading before failure. Young’s modulus relates strain to stress in one direction

and is a measure of the stiffness of a material. Stiffer rocks have higher Young’s modulus val-ues and are easier to fracture than rocks with lower values. Poisson’s ratio, which is the ratio of transverse strain to axial strain, is related to closure stress; rocks with higher Poisson’s ratio values are more difficult to fracture and prop open than those with lower values.14 Targeting intervals for hydraulic fracturing that have higher Young’s modulus values and lower Poisson’s ratio values may improve stimulation performance and well productivity.

> Hooke’s law and isotropic elastic moduli. For the case of isotropic rocks, engineers use three log-derived measurements to come up with five mechanical properties. The compressional modulus, M, is computed from the compressional slowness time (Δtc) and bulk density, ρb. The shear modulus, G, is calculated from the shear slowness time (Δts) and bulk density. The a in both equations is a unit conversion constant. In turn, these two moduli are used to compute the bulk modulus, K, Young’s modulus, E, and Poisson’s ratio, ν.

K = 4G3

M –

=6K + 2G3K – 2G

aρbM = ..

. .

.

(Δtc) 2

E

ν

= 9KG3K + G

aρb

(Δts) 2G =

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10 Oilfield Review

However, the simple equations relating log-derived measurements to mechanical rock prop-erties are not valid when elastic anisotropy is encountered.15 The general formulation relating stress to strain as described by Hooke’s law is represented by a fourth-order stiffness tensor that has 81 elastic constants and summations. Although symmetry reduces the number of con-

stants to 21, deriving the relationships used to determine mechanical properties in an anisotro-pic formation is a formidable task that is beyond the scope of this article.

When acoustic data are available, engineers use these data to compute pore pressure, derive elastic properties and correlate downhole data with surface seismic results. Drilling engineers

use pore pressure to facilitate drilling and increase safety margins. Using mechanical prop-erties derived from sonic data, they can optimize drilling programs and validate their ability to fol-low a given well profile while maintaining well-bore stability. Completion engineers use these same data to design stimulation programs. Geophysicists refine seismic data acquired at the surface using information derived from downhole sonic data.

Real-time data from LWD sonic tools have two main applications for pore pressure determina-tion: identifying overpressured formations and selecting mud density (left). For drilling engi-neers, overpressured zones present hazards that can range from mildly annoying to catastrophic. Optimizing mud weights to maintain borehole stability and drill safely may result in consider-able cost savings.16

During lithification, sediments are com-pacted by overburden pressure and fluids are expelled. The effects of compaction can be observed in sonic slowness data as a steady decrease in the compressional slowness. This is most obvious in shale intervals. Conversely, when fluids cannot escape, the formation retains fluids and becomes overpressured. Higher fluid content results in higher compressional slowness values.

Drilling through overpressured shale zones usually does not pose a hazard because these zones have inherently low permeability; however, should the bit encounter a porous layer that is overpressured, the hydrostatic pressure in the wellbore may be insufficient to contain the pore pressure. The result may be a rapid influx of res-ervoir fluids, or a kick. In extreme cases, the well may blow out.

Engineers can also use mechanical properties computed from acoustic data to construct a 1D mechanical earth model using programs such as the single-well geomechanics module in Petrel seismic-to-simulation software (next page, top).The models can be adjusted while drilling using real-time data from LWD sonic tools. Such models allow drillers to maintain a drilling mud density, or mud weight, that strikes a balance between the hydrostatic pressure in the wellbore and any anticipated increase in reservoir pore pressure.

There is a point, however, at which raising the mud weight can cause weaker rocks to fail. Pore pressure prediction programs can deter-mine the maximum mud density that can be maintained before the formation breaks down. When the maximum mud weight threshold is reached, casing is run to isolate weaker forma-tions. A mistake of a few meters can result in an expensive extra casing run or create hazardous

>Watching for trends. Real-time LWD gamma ray data (Track 1) indicate the well is penetrating shale in the upper half of this section. As long as the bit remains in a shale section, there is little potential for encountering overpressure and taking a kick; however, should the bit enter a permeable zone, there is a risk of influx of formation fluids. The driller would typically choose to manage overpressure by increasing mud weight, but if the shallower formations are not strong enough to sustain mud weights sufficient to control an overpressured condition, casing must be set. Because changes in lithology or fluid can mask changes in the pressure regime, resistivity (Track 2) may not always indicate overpressured conditions. The increase in sonic slowness (Track 3) at around X5,000 ftindicates a potential overpressured condition (red shading). If real-time shear data are available from the LWD sonic tool, engineers can compute the strength of shallower formations and determine the thresholds for mud weight maximum values.

X2,000

LWD Sonic SlownessPhase Shift ResistivityGamma Ray

Attenuation Resistivity

150150 0.2 2,000

2,000

0 ohm.m

0.2 ohm.m

gAPI μs/ft 50Dept

h, ft

X3,000

X4,000

X5,000

X6,000

X7,000

X8,000

Compactiontrend

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Spring 2012 11

drilling conditions. Mechanical properties of the formations must be known in order to determine the mud density limits.

Once the mechanical properties are com-puted from compressional and shear slowness data, geomechanical modeling programs can pro-vide solutions to drilling and completion ques-tions. Examples of modeling programs are VISAGE reservoir geomechanics modeling soft-ware and Mangrove reservoir-centric stimulation design software. VISAGE software is a full-scale reservoir-modeling program that engineers use to predict behavior during drilling, injection and production. Using finite-difference methods, the software calculates detailed 3D and 4D models that can display patterns of pressure, stress, strain, porosity and permeability at specific points or across an entire reservoir (below right).Fracture stimulations in conventional reservoirs can be modeled along with expected production. Mangrove software was developed for use with unconventional reservoirs.

An example of how geomechanical data are used in the development of unconventional resource plays is in identifying targets with better characteristics for multistage fracture stimulation. Spacing and location of perforation clusters are crucial elements in stimulation design of these reservoirs.17 A manual approach of identifying intervals with completion-quality rock can be tedious. However, current industry practice of designing stimulation jobs with evenly spaced perforation clusters regardless of variations in rock properties can result in sub-optimal recovery.

Other key challenges in completion design involve modeling the complex fracture networks that are frequently observed in unconventional reservoirs and evaluating their impact on produc-tion. Accounting for heterogeneity in completion design can help engineers enhance well produc-tivity, especially by identifying changes in geome-chanical properties—paticularly those that can be derived from sonic data. The absence of a sin-gle integrated solution to incorporate rock het-erogeneity has been an impediment to optimizing fracture stimulation designs.

15. For information on application of sonic data in formations with elastic anisotropy: Armstrong P, Ireson D, Chmela B, Dodds K, Esmersoy C, Miller D, Hornby B, Sayers C, Schoenberg M, Leaney S and Lynn H: “The Promise of Elastic Anisotropy,” Oilfield Review 6, no. 4 (October 1994): 36–47.

16. Brie et al, reference 4.17. King GE: “Thirty Years of Gas Shale Fracturing: What

Have We Learned?” paper SPE 133456, presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, September 19–22, 2010.

> Integrating sonic data. By including sonic data in reservoir models, such as this Petrel example, operators can design wellbore profiles that are compatible with the mechanical properties of the formation. Geoscientists compute mechanical properties from surface seismic data, and the LWD sonic data are used to update models in near real time. For instance, advanced computations deliver stress profiles that vary in a complex manner around the wellbore projection, and are graphically displayed along a near-wellbore grid (shown encircling the wellbore). These displays allow engineers to better understand the borehole geomechanical status and adjust well plans to safely reach a target (lower green area). The magenta background to the left represents Young’s modulus, an elastic parameter used to define the stress state, determined from seismic inversion. These types of information can be updated with downhole sonic data as the well is drilled. Sonic data can also tie time-based surface seismic data, such as the cross section displayed on the right, to specific depth references downhole.

800 600 400 200 0 –200 –400Effective stress, psi

> Drilling through operational windows. After populating 3D and 4D models with mechanical properties, engineers can perform field-scale stress simulations to determine magnitude and orientation of stresses (cyan crosses). Areas to be avoided within the reservoir can be identified, such as those shown in red in the background. Narrow operational windows, which may correspond to many factors, including maximum mud weight, regions of high fluid loss and mechanical instability, are displayed in 3D, allowing engineers to choose a well path that maximizes safety and efficiency. Drillers may decide to set casing above or below these zones, or proceed with caution, aware of the increased risks. An acceptable path can be located between areas with narrow operating windows (purple). The vertical cross section also provides detailed information about the effects of a nearby salt dome on the stress field. The mud weight safe operating margins, computed from seismic and sonic data, actually increase from top to bottom, which is the opposite of conditions in most reservoirs. The corresponding color changes go from blue (low safety margin) to green to yellow to orange (high safety margin).

Narrow operational window Negative operational window

Low

High

Mud

wei

ght s

afet

y m

argi

n

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12 Oilfield Review

To address unconventional hydraulic fracture design and to help optimize fracture stimula-tions, Schlumberger engineers developed Mangrove stimulation modeling software (above).18 The software incorporates seismic, geologic, geomechanical and microseismic data along with reservoir simulations to model frac-ture propagation and geometry. The software includes two different fracture simulators that are designed for complex hydraulic fracture mod-eling. They are linked to reservoir models for optimizing fracture design and production fore-casting. Reservoir and completion quality are

quantified from these multidomain reservoir data so that completion engineers can optimize stage placement and perforation programs.

Operators recognize the benefits of using acous-tic log data for well and completion design. Acquisition of data in extended-reach horizontal wellbores has been problematic with wireline tools because it is difficult to convey them to TD and it is hard to keep the tools centered in the wellbore. LWD sonic tools, designed to acquire data in these types of environments, provide real-time formation mechanical properties that may improve drilling decisions and stimulation programs.

Horizontal ApplicationChevron Cabinda Gulf Oil Company Ltd uses acoustic data to optimize drilling and comple-tions in a Lower Congo basin field offshore Angola.19 Shear data are required for computing mechanical properties, which are then used in well design to ensure wellbore stability. Engineers planned to acquire SonicScope data from two separate 6-in. horizontal boreholes, drilled sequentially, to confirm that high-quality shear data could be extracted while drilling. Along with the SonicScope tool, the LWD logging program included azimuthal density, neutron porosity and resistivity tools.

The reservoir consists of unconsolidated thin-bedded sands. To maximize exposure to the thin layers, lateral wellbores are drilled with sinusoi-dal trajectories. Interval A was drilled to a mea-sured depth of 4,570 ft [1,390 m] and then, without pulling out of the hole, the sidetrack Interval B was drilled to 4,240 ft [1,290 m]. The deviation ranged from 78° to 93° in Interval Aand from 80° to 97° in Interval B.

The primary focus for the study was to com-pare the compressional and shear measure-ments obtained using monopole sources with measurements extracted from quadrupole data. The engineers programmed the tool to obtain high-frequency monopole, low-frequency mono-pole and low-frequency quadrupole waveform data, which were acquired while running in the hole and while drilling in open hole. High-frequency monopole data were also acquired while in casing. Compressional slowness data were transmitted to surface in real time, and log-ging engineers transmitted the information to geoscientists at the onshore office. Data were also stored in tool memory for further processing after TD was reached in Interval B and the tools could be retrieved from the well.

Monopole data provided good compressional measurements; however, shear slowness data from the monopole source were frequently miss-ing from both intervals (next page). Processing of the quadrupole waveform data yielded continu-ous shear slowness data of good quality across the majority of both intervals. The shear slowness values from the quadrupole data in Interval A ranged from 132 to 310 μs/ft [433 to 1,020 μs/m],and in Interval B the range was 145 to 264 μs/ft[476 to 866 μs/m]. With the monopole data, no shear slowness values greater than 243 μs/ft[797 μs/m] were observed. With the quadrupole source, Chevron Cabinda Gulf Oil was able to quantify shear slownesses in zones that were too slow for the monopole source.

> Logging data for fracture design. In unconventional reservoirs, such as gas shales, operators frequently use geometry (top) rather than geology and geomechanics to determine fracture staging and perforation cluster locations. LWD acoustic data, such as those from the SonicScope tool, can identify rocks with low stress, which offer better completion quality (CQ), and petrophysical analysis can identify intervals with better reservoir quality (RQ). The Mangrove program generates a composite quality score combining CQ and RQ to rank the rock along the wellbore, recommends preferred locations for perforation clusters and groups similar rocks in treatment stages (bottom). The stress is presented beneath the well projection and ranges from low (red) to high (blue). The same number of perforation clusters are used in both examples—colored ovals represent perforation clusters in each stage—but in the recommended results they are concentrated in better quality rock (blue, green and yellow), and poor quality rock (red) is avoided. Operators following this engineering approach for completion design have seen substantial improvement in production. (Adapted from Cipolla et al, reference 18.)

Rock quality

Stress

Rock quality

Stress

Geometrically placed perforation clusters

Selectively placed perforation clusters

HighLow

Stress

Good CQ and good RQ

Bad CQ and good RQBad CQ and bad RQ

Good CQ and bad RQ

Rock quality

18. Cipolla C, Weng X, Onda H, Nadaraja T, Ganguly U and Malpani R: “New Algorithms and Integrated Workflow for Tight Gas and Shale Completions,” paper SPE 146872, presented at the SPE Annual Technical Conference and Exhibition, Denver, October 30–November 2, 2011.

19. Mohammed S, Crowe J, Belaud D, Yamamoto H, Degrange J-M, Pistre V and Prabawa H: “Latest Generation Logging While Drilling Sonic Tool: Multipole Acoustics Measurements in Horizontal Wells from Offshore West South Africa,” Transactions of the SPWLA 52nd Annual Logging Symposium, Colorado Springs, Colorado, USA, May 14–18, 2011, paper CC.

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Spring 2012 13

> Good quality shear data from the SonicScope LWD tool. Chevron Cabinda engineers use mechanical properties computed from acoustic data for well design and to optimize drilling practices in a Lower Congo basin field offshore Angola. In this example, several LWD logs were run in a horizontal well and provided rate of penetration (ROP), gamma ray and caliper data (Track 1) along with resistivity (Track 2) and porosity data (Track 4). The SonicScope tool was included in the suite to evaluate its ability to provide shear data in soft formations. Extracting shear slowness from monopole data is difficult in the unconsolidated formations that are typical of the field. Track 5 presents the coherence projections for the monopole compressional data (black curve on left) and monopole shear data (black curve on right). In several places across the logged interval, such as the gap in the middle of this interval, the monopole shear data are incomplete. Quadrupole shear data acquired with the SonicScope tool are continuous (Track 5, red curve). The coherence (Track 6) of the quadrupole data provides high confidence in the measurement quality. There is also a difference between the two shear slownesses measured by the different methods. This difference is associated with acoustic anisotropy in this horizontal well. Where monopole shear data are available, Vp/Vs ratios from the two datasets are shown (Track 3, green and dashed magenta lines). Monopole Poisson’s ratio (Track 3, purple) is compared with quadrupole Poisson’s ratio (Track 3, dashed red) and these data also exhibit some differences across the interval. A Variable Density log (Track 7) is used to check the quality of the received sonic data. (Adapted from Mohammed et al, reference 19.)

Washout

Measureddepth, ft

XX,000

XX,100

2-MHzResistivity

Data

Bit Size

Caliper

Gamma Ray

10-in.Phase Shift

22-in.Phase Shift

24-in.Attenuation

MonopoleΔtc Quadrupole Δts

Quadrupole Inversion Quality

WaveformVariable Density LogQuadrupole Δts

Monopole ΔtsDensity Correction

Neutron Porosity

Bulk Density

PEF

MonopolePoisson’s Ratio

0.2 240 34040

–1 1

40

1.95 2.95

0 20

45 –15%

μs/ft μs/ft

340 1 –440 μs/ftg/cm3

g/cm3

0 0.5

200

5 10in.

5

0

200 0ft/h

gAPI 150

10in.

ohm.m

0.2 200ohm.m

0.2 200ohm.m

0.2 200ohm.m

34-in.Phase Shift

ROP

QuadrupolePoisson’s Ratio

0 0.5

0 5

0 5

QuadrupoleVp/Vs Ratio

MonopoleVp/Vs Ratio

Monopole Δtc

Monopole Projection

Quadrupole Projection

34040 μs/ft

340

40 440

40 μs/ft

μs/ft

40 440 0 5,000μsμs/ft

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14 Oilfield Review

The absence of shear data in softer forma-tions would have made it impossible to compute mechanical properties in these zones. Because measurements with the quadrupole source deliv-ered shear slowness in slow formations inter-sected by both intervals, engineers are able to incorporate mechanical property data in future well designs.

In addition to compressional and shear slow-ness, the SonicScope tool provided cement bond logging (CBL) information in the 7-in. casing (above). From high-frequency monopole data, log analysts identified the top of cement (TOC) and estimated the cement quality. A Variable Density log, similar to wireline CBL logs, was also generated.

The interpretation based on the LWD sonic data is only qualitative, but is often sufficient to verify that the pipe is adequately cemented in place.

The Lower Congo basin reservoir described in this case study consisted of unconsolidated sands, which can pose drilling challenges. The ability to extract usable-quality acoustic shear data from LWD sonic quadrupole measurements in these unconsolidated sands enabled engineers to derive geomechanical properties for planning future extended-reach horizontal wells. These data were used for several purposes, including developing safer drilling programs, optimizing drilling, managing mud properties and under-standing limiting factors for future wells.

Sweet Spots in Real TimeIn addition to improving well design and optimiz-ing drilling with increased safety, sonic data help engineers make and validate real-time well placement decisions. Recently, engineers used data from the SonicScope tool to identify sweet spots in a horizontal well.20 Two drilling runs were made in the well, one of more than 1,500 ft[460 m] and a second of 886 ft [270 m].21 The LWD assembly did not include density or porosity data. Identification of sweet spots was based solely on changes in the ratio of compressional and shear velocities (Vp/Vs).

For this reservoir, a correlation had been observed between drilling rate of penetration (ROP) and production; zones with higher ROPs exhibited better hydrocarbon production. Drilling rates can, however, be influenced by fac-tors that are unrelated to reservoir quality, such as bit type and condition. On the other hand, stable Vp/Vs ratios had also been associated with better quality rock, and they reflect reservoir properties. Log analysts identified seven sepa-rate zones within the drilled interval based on Vp/Vs ratios. Zone 1 represents the interval con-taining the landing point. Zone 2 is the interval over which angle was built to penetrate the reser-voir. Changes in formation lithology and variable formation properties were identified from Vp/Vs ratios in zones 4 and 6. Zones 3, 5 and 7 have steady Vp/Vs ratios and correspond to 10% increases in ROP compared with the average ROP for the drilled section (next page).

From sonic data, engineers confirmed that three intervals offered the best quality rock for completion. The driller was also able to guide the well back to better quality intervals after inadver-tently exiting the preferred zones. The results of this study demonstrate the value of real-time sonic data to quantify rock quality.

Sound FutureEngineers recognize the importance of using mechanical property data in optimizing drilling programs and designing effective stimulation jobs. Identifying and responding to seemingly small variations in properties can mean the dif-ference between disastrous results and a well drilled with few complications. Small variations in mechanical properties can be exploited to improve commercial viability of drilling pros-pects where fracture stimulation is indicated.

> Cement bond logging with an LWD sonic tool. Data from the SonicScope tool can be presented in a format similar to that of wireline cement bond logs (CBLs) to evaluate cement behind casing. The measurements are qualitative rather than quantitative. The Variable Density log is a presentation of the acoustic waveform at a receiver, in which the amplitude is presented in shades of a gray scale. Because cement bonded to the outside of the casing attenuates the signals that would normally be present, the Variable Density log is a useful indicator of the presence of cement behind pipe. In this interval, the depth of end of casing is shown (red line). The absence of waveform arrivals in the casing window (dashed yellow line to dashed blue line) indicates good bonding of the cement behind the pipe. The patterns to the right of expected casing arrivals come from the formation, which signify bonding of cement to the formation. (Adapted from Mohammed et al, reference 19.)

05 10in. 3,000

Casing Arrival Window Stop

Casing shoe

Casing

Bit Size

μs

0 3,000

Casing Arrival Window Start

Variable Density Log

μs

0 3,000

High-Frequency Monopole Waveforms

μs

20. Sweet spots refer to target locations or areas within a play or a reservoir that represent the best production or potential production. Geoscientists and engineers attempt to map sweet spots to allow wellbores to be placed in the most productive zones of the reservoir.

21. Degrange et al, reference 8.

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Spring 2012 15

New LWD sonic tools and techniques allow access to these data in real time.

Integration of acoustic data in drilling, com-pletion and evaluation workflows is a key to the future of LWD sonic operations. Service compa-nies have demonstrated conclusively that these data can be extracted and that the information is

relevant to drilling and completion operations. Presenting the data in a form that decision mak-ers can use to visualize the downhole environ-ment is crucial.

The area around the bit is noisy and wracked by sound and vibrations while drilling. However, engineers have designed LWD acoustic tools that

overcome these conditions and answer funda-mental questions about the rocks being pene-trated by the bit. These tools are saying something important about the reservoir and the rocks, and geoscientists are listening. —TS

> Sweet spot drilling. ROP has been identified by the operator of this well as a sign of good completion-quality rock. However, ROP is influenced by factors other than reservoir quality. The ROP data (green curve) are not conclusive and have considerable variability. Stable Vp /Vs ratios are also an indicator of completion quality and can be computed from sonic compressional data (top, blue and red curves) and shear data (purple and green curves) acquired in real time or recovered from downhole memory. Engineers identified seven different zones (yellow and green shading) across the interval based on LWD Vp /Vs data (red curve). Poisson’s ratio (blue curve) is an indicator of rock stiffness. The cross section (bottom)shows the location of each zone of the wellbore relative to the sweet spot (between light blue lines). Zone 1 is the heel of the horizontal section where the well was kicked off, and Zone 2 is where angle was being built to enter the reservoir. Zones 4 and 6 were drilled out of zone for short intervals. Zones 3, 5 and 7 have stable Vp /Vs ratios around 1.625, were drilled in zone and were identified as good targets for fracture stimulation. (Adapted from Degrange et al, reference 8.)

0.500

0.375

0.250

0.125

1.500

1.625

1.750

1.875

2.000

Pois

son’s

ratio

0

0 500 1,000 1,500 2,5002,000

0

20

40

60

80

100

ROP,

ft/h

V p/V s

ratio

40

Δtc,

Δts,

μs/f

t

60

80

100

120

140

Δtc recorded mode Δtc real time Δts recorded mode Δts real time

True

ver

tical

dep

th, f

t

Horizontal departure, ft

Zones 1 and 2 Zone 3 Zone 4 Zone 5 Zone 6 Zone 7

Zones 1 and 2 Zone 3 Zone 4 Zone 5 Zone 6 Zone 7

Original well plan

Revised trajectory

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16 Oilfield Review

Working Out of a Tight Spot

For more than 80 years, jars have been widely accepted in the drilling industry as

inexpensive contingencies to save rig time and to protect the drillstring and wellbore

from damage in the event of stuck pipe. Advances in technology and increased under-

standing of the dynamics of successful jarring operations have extended the applica-

tion of jars to horizontal and highly deviated wells. Challenges to optimal use of jars

remain, however, and both the art and the science of jarring continue to evolve.

Bob CostoLarry W. CunninghamGlenn Joseph MartinJosé MercadoBrian MohonLiangjun XieHouston, Texas, USA

Oilfield Review Spring 2012: 24, no. 1.Copyright © 2012 Schlumberger.For help in preparation of this article, thanks to Eric Wilshusen, Houston.Accelerator AP, AP Impact, Hydra-Jar AP and Jar-Pact are marks of Schlumberger.

Drilling jars serve a single purpose: to free stuck pipe. Jarring is the process of dynamically trans-ferring strain energy stored in the drillstring to a device—a jar—that concentrates kinetic energy at the point where the pipe is stuck. Most opera-tors include jars in their drilling BHAs as precau-tion against the likely occurrence of stuck pipe. It is estimated that drillstrings become stuck an average of once for every three wells drilled, cost-ing operators hundreds of millions of dollars per

year.1 Approximately 50% of stuck pipe incidents occur during tripping, 20% while reaming and working pipe and 10% while drilling ahead.2

Jarring is the last line of defense against down-time, expensive fishing operations, sidetracking or well abandonment. Although E&P companies go to great lengths to avoid costs that result from stuck pipe, drilling teams are generally unfamil-iar with the mechanics and dynamics of jars and untrained in optimizing jarring operations.

1. Shivers RM III and Domangue RJ: “Operational Decision Making for Stuck-Pipe Incidents in the Gulf of Mexico: A Risk Economics Approach,” SPE Drilling & Completion 8, no. 2 (June 1993): 125–130.

2. Bradley WB, Jarman D, Plott RS, Wood RD, Schofield TR, Auflick RA and Cocking D: “A Task Force Approach to Reducing Stuck Pipe Costs,” paper SPE/IADC 21999, presented at the SPE/IADC Drilling Conference, Amsterdam, March 11–14, 1991.

3. Bowes C and Procter R: 1997 Drillers Stuck Pipe Handbook. Houston: Schlumberger (1997): 13.

4. Clausen J, Rebellon J, Blanc J and Barton S: “Novel Drilling Technology Delivers a Step Change in Challenging Deepwater Operations,” paper SPE 142501, presented at the SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, September 25–28, 2011.

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Consequently, operators don’t always realize the full value of their contingency plan, and millions of dollars remain at risk.

Service companies are partnering with opera-tors to dramatically reduce operational risk, downtime and cost by educating rig personnel and by encouraging the proper and timely use of jar placement analysis programs that have become the preventive component of jar contingency plans. Having a broader understanding of geology, wellbore and BHA geometry and the implications of jar placement will enable drilling engineers to design BHAs that optimize penetration rates and wellbore placement while providing maximum protection against potential downhole events that undermine drilling performance.

This article reviews causes of stuck pipe and the types of jars available and discusses jarring forces and the importance of planning and analyzing jar placement in the drillstring. Case histories from Canada, Oman and the US demon-strate the benefits of successful jarring operations.

Stuck Pipe Basics When the static force necessary to move a drill-string exceeds the rig’s capabilities or the tensile strength of the drillpipe, the drillstring becomes stuck. The pipe can no longer be moved up or

down or be rotated. Pipe can become stuck while drilling, making a connection, logging or testing or during any operation in which equipment is in the hole. There are two primary types of pipe sticking: mechanical and differential.

Mechanical sticking is usually encountered while the drillstring is being moved and is caused by a physical obstruction or restriction. Three mechanisms are responsible for stuck pipe: pack-off, bridging and wellbore geometry interference (above). Packoff occurs when an unconsolidated formation, formation cuttings or debris in the wellbore settle around the BHA and fill the annu-lus between the drillstring and the wellbore. It typically takes place after the mud pumps have been off for an extended period during opera-tions such as pulling out of hole. Bridging results when medium to large pieces of formation, cement or junk fall into the wellbore and block the annulus.

Wellbore geometry interference may arise when the shape or size of the well and that of the BHA are incompatible. Often the interference is caused by keyseat sticking when the hole deviates from true vertical. A keyseat is an indentation or groove cut into the formation in which larger diameter components of the drillstring, such as collar connections and the BHA, can become wedged. Other causes of interference include

undergauge hole, stiff drilling assembly, mobile formations, ledges, doglegs and casing failures.

Differential sticking occurs when the pipe is stationary or moving very slowly. It is caused by drilling fluid overbalance—when hydrostatic pressure in the mud column is greater than the pore pressure in the permeable formation—which pushes the pipe into the wellbore wall.3

Aggravating conditions include high overbalance pressures, thick filtercake, high-density drilling fluids and muds with high solids content.

When engineers have an understanding of the potential mechanisms and causes of stuck pipe, they may be able to optimize placement of jars early enough in the design process to maximize jarring effectiveness. Operators that have this knowledge may also better select the appropriate jarring forces and durations for the hole condi-tions once a drillstring becomes stuck.

How Jars WorkAlthough drilling jars have been in use since the 19th century, modern jars did not emerge until the 1930s. In 1931, engineers designed a jar that consisted of a telescoping mandrel held in place by a mechanical latch-type device. Numerous improvements since that time have enabled jars to handle the demands created by increasingly complex wells.4

> Stuck pipe mechanisms. Pipe may become stuck in the hole, unable to be moved up or down or rotated, for a variety of reasons. Packoff (left) may occur when an unconsolidated formation—loosely packed with little or no bonding between particles, pebbles or boulders—falls into the wellbore. Packoff can also occur when formation cuttings or debris settle around the BHA. Keyseating (center) may happen when the drillpipe rotates against a single point on the borehole wall where it wears a groove, or keyseat (inset), into the wall. When the drillstring is pulled out of the hole, the tool joints or sections of the BHA of larger diameter than the drillstring are unable to move through the keyseat. In this case, the drillstring may be moved down or rotated but cannot be pulled upward and thus is stuck in the hole. Differential sticking (right) may result when a force created by the hydrostatic pressure of the drilling fluid in the wellbore is greater than the pore pressure of a permeable formation. This overbalance presses the drillstring against the wellbore and is often initiated when the drillstring is stationary or moving very slowly and comes in contact with a permeable formation or a thick mud filtercake.

Packoff Keyseating Differential Sticking

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Today, a jar consists of a mandrel that slides within a sleeve and an internal detent mecha-nism that briefly delays the movement of the mandrel before releasing it.5 The mandrel is often referred to as a hammer and the sleeve as an anvil. This nomenclature helps explain how energy is released from the drillstring and trans-ferred to the stuck pipe (below).6

Jars operate on the principle of stored poten-tial energy. The potential energy available to the jar comes from overpull or set-down values applied at surface.7 Jars can strike, or fire, upward, downward or both. The jar is run in the drillstring either in tension or in compression. If run in tension, the mandrel is completely extended. If run in compression, it is completely closed. In either position, mandrel movement is prevented until jarring becomes necessary and drillers apply additional tension or compression to the drillstring.8

To fire a jar upward, the driller slowly applies overpull to the top of the string while the BHA remains stationary. The detent in the jar restricts the movement of the mandrel for a brief time, causing the drillpipe to physically stretch and store strain energy (above). This phase, often called the loading phase, typically lasts only a few seconds but when the rig crew uses hydraulic jars, which have long delay times, the loading phase can last for several minutes.9

The next phase, sometimes referred to as the preimpact phase, begins when the detent releases and concludes with jar impact. This phase typically lasts from 50 to 200 ms. The man-drel accelerates, and the energy stored in the stretched drillstring is suddenly released, setting into motion the drillpipe mass and the collar or heavyweight drillpipe (HWDP) mass directly above the jar. These masses gain momentum dur-ing free travel.

When the motion stops, an impact load, com-parable to a hammer striking an anvil, is imparted. The time interval of this impact phase is typically 10 to 50 ms. The impact generates a shock wave that travels up and down the drill-string. This process provides a sudden release of energy at the stuck point.

The postimpact phase lasts for a matter of seconds until the drillstring has returned to a state of complete rest. During the next phase, resetting, the drillstring is lowered until string weight imposes a compressive force on the jar, which resets it for the next jarring cycle.

When jarring downward, instead of overpull applied to the drillpipe, the weight of the tool-

string is released, delivering a compressive force at the sticking point in an effort to release the stuck tool by driving it downward. The jarring process is repeated—in some cases hundreds of times—until the stuck pipe is freed or, if jarring has not been successful, the operator decides to pursue a different course of action.

Two quantities that are generated by jarring combine to overcome the sticking force and move stuck pipe: impact and impulse. The first quantity, impact, is the peak force caused by the collision of the hammer with the anvil. The sec-ond quantity, impulse, is the change in momen-tum during the impact phase measured by the area under the load versus time curve (next page, top right). Both impact and impulse are influenced primarily by the number of drill

5. A detent is a device that positions and holds one mechanical part in relation to another so that the device can be released when a force is applied to one of the parts. An example of a detent in a common object is the release mechanism in umbrellas.

6. Kalsi MS, Wang JK and Chandra U: “Transient Dynamic Analysis of the Drillstring Under Jarring Operations by the FEM,” SPE Drilling Engineering 2, no. 1 (March 1987): 47–55.

7. Overpull is the amount of pull on the moving pipe that is in excess of its weight in air or fluid. Set-down weight, also referred to as slack-off or released drillstring weight, is the weight of the drillstring and BHA available at the stuck point or at bottomhole if the pipe is free.

8. Schmid JT Jr: “Designing BHAs for Better Drilling Jar Performance,” World Oil 195, no. 5 (October 1982): 100–104.

9. Aarrestad TV and Kyllingstad A: “Loads on Drillpipe During Jarring Operations,” SPE Drilling & Completion 9,no. 4 (December 1994): 271–275.

10. Newman KR and Procter R: “Analysis of Hook Load Forces During Jarring,” paper SPE/IADC 118435, presented at the SPE/IADC Drilling Conference and Exhibition, Amsterdam, March 17–19, 2009.

> Jarring assembly. A typical jarring assembly consists of a mandrel, or hammer, that slides within a sleeve, or anvil, and a detent mechanism. The detent restricts the movement of the mandrel briefly before releasing it. The time delay enables the drillpipe to store potential energy. The sudden release of the detent mechanism causes the mandrel to accelerate rapidly for a distance of 25 to 50 cm [10 to 20 in.] before it slams against the sleeve, releasing the stored energy and imparting an impact force at the stuck point. Upward motion of the mandrel causes the hammer to slam into the anvil, producing an upward force on the drillstring. Downward mandrel motion produces the opposite effect.

Drillpipe

Overpull force

Collar

Anvil

Detent mechanism

Bit

Hammer

Stuck point

Jar

> Acquiring strain energy. The energy available to the jar comes from the overpull force applied at surface to stretch the drillpipe. The type and length of drillpipe affect the amount it can stretch and the energy it can store. This graph for 5-in., 19.5-lbm/ft drillpipe compares two stretch lengths attainable for different applied overpull as a function of the length of free drillpipe above the stuck point. For a given stretch, the overpull force, and thus the energy available for jarring, decreases with increasing length of free drillpipe.

Over

pull f

orce

, lbf ×

1,0

00

250

200

150

100

50

07,0006,0005,0004,0003,000

Length of free drillpipe, ft2,0001,0000

16-in. stretch9-in. stretch

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collars above the jar; fewer drill collars result in a higher impact force, but more drill collars deliver a greater impulse. In successful jarring operations, a compromise is achieved through proper jar placement and regulating the number of drill collars to maximize how the impact and impulse forces work together to free the pipe.

The magnitude of the impact delivered by the jars is limited by the overpull or slack-off weight available. A properly designed jarring assembly usually exerts more force when jarring upward than downward because the driller can pull on the drillpipe with a force of up to 90% of the yield strength of the pipe. However, the available slack-off weight, and resulting compressive force, is much less than the total toolstring weight because of buckling limitations of the drillstring above the jar, drill collar length configuration and the relative position of the drill collars and the jar.10 Jarring is most effective when it is per-formed in the opposite direction to that which the drillpipe was traveling when the pipe became stuck; that is, jarring upward is most effective if sticking occurred while running the drillstring into the hole, and jarring downward is most effec-tive if sticking occurred while running out.

Two resistance forces can affect jarring. A high differential pressure between the inside and the outside of the jar, acting on the total sealed cross-sectional area at the mandrel, may create a force sufficient to open the jar and lift the drill-string. This is called jar pump open force, or jar extension force. When jarring upward, the opera-tor must add the pump open force to the surface overpull to obtain actual tension at the jar. When jarring downward while circulating, drillers must slack off more weight at the surface to overcome the pump open force acting in the opposite direction.

Pump open force can sometimes aid in upward jarring. In cases of severe differential toolstring sticking or drag, overpull cannot fire a mechanical jar or induce a large enough blow from a hydraulic jar. A jar may sometimes be fired by increasing the mud pump rate, which increases pump force, or by a combination of increasing mud pressure and applying tension to the drillstring. Drag on drillpipe increases over-pull requirements. In vertical wells, drag can be negligible, but drag in directional wells often increases the overpull required to fire the jar by as much as 10%.

Types of JarsJars are classified by function and by actuation method. Drilling and fishing jars have similar designs and deliver approximately the same

impact, but are constructed differently and have different functions. Drilling jars are the length of standard drillpipe, are durable enough to withstand drilling stresses and are run as components of the BHA. They may be fired and reset several times during a single jarring operation. Fishing jars are shorter than standard drillpipe, cannot withstand drilling forces and are run only after the pipe above the stuck point has been disconnected and retrieved from the hole. They are typically designed to jar upward only.

Mechanical and hydraulic jars function simi-larly, but differ in their detent mechanisms. Mechanical jars are actuated using a series of springs, locks and rollers with release mecha-nisms. The mechanical jar fires upward at a pre-set tensile force and downward at a preset compressional force; these normally exceed the tensile or compressional forces reached while drilling. Firing is dependent on load only, not on length of time. During drilling, the mechanical jar is either cocked or extended to its fully open or fully compressed position (below). Although

> Impact and impulse. When jars are activated, the aim is to create an impact force to overcome the force causing the pipe to stick. The impulse, with units of force x time, is momentum, and must be sufficient to move the pipe. Both impact and impulse are influenced primarily by the number of drill collars above the jar and by jar placement.

Forc

e

Time

Impulse = usable unitsof force × time

Impact

>Mechanical jar. When a mechanical jar detent mechanism is cocked (left),the tubular springs hold the trip sleeve against the mandrel, which prevents the jar from firing. By maintaining an applied tensile or compressional force that is less than the set tubular spring force, the jar may be run in and out of the hole without fear of tripping the jar. When applied tension is greater than the preset tubular spring force, the trip sleeve is forced upward or downward, allowing the mandrel to slide free (right) and the jar to be fired.

Mandrel

Down adjustingsleeve

Detent Mechanism Cocked Detent Mechanism Tripped

Up adjustingsleeve

Tubularspring free

Trip sleeve

Friction sleeveand outer housing

Tubularspring free

Tubular springloaded to tripload up

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mechanical jars are still preferred for some niche applications, including high-temperature wells, many engineers favor hydraulic jar technology for most applications.

Hydraulic jars were introduced in the 1940s to increase the impact loads, which are limited by latching mechanisms of mechanical jars. Hydraulic jars were designed, therefore, not to trip at a preselected threshold. Instead, they operate using a piston pulling through a restric-tion in a hydraulic fluid reservoir in the detent mechanism. When tension or compression is applied to the tool in the set position, the fluid from the high-pressure side of the reservoir is compressed and passes into the low-pressure side through an orifice between the reservoirs. The orifice causes a fluid flow restriction, result-ing in a time delay that enables potential energy to be stored in the drillpipe. Varying the metering rate of the fluid through the orifice affects the magnitude of impact at the stuck point.

The metering stroke is the overall distance traveled by the hydraulic jar and the fluid.11 When the stroke reaches a certain distance, the piston moves from the restrictive area into a larger area, allowing the compressed fluid to flow freely around the piston. The jar fires, and pressure between the two sides equalizes. The timing and force with which the jar fires determine the mag-nitude of the applied tension or compression.12

The driller influences overpull on the jar, which in turn influences the flow rate of the fluid

through the orifice and the speed and force at which the jar fires. The magnitude of the impact is proportional to overpull. Greater overpull pro-duces quicker jar firing and a more forceful impact. Any applied force can fire the jar, and drillers can vary the final force delivered to the stuck point.

Expanding the Limits of Hydraulic JarsThe progress of oil and gas exploration and development into deeper waters, more hostile downhole environments and complex wellbore geometries has generated demand for tools, including jars, able to perform reliably, effi-ciently and safely under higher downhole stresses. Jar manufacturers have responded with tools that can perform reliably in a variety of drilling environments: on land or offshore and in vertical, horizontal or deviated and ultradeep or high-pressure, high-temperature (HPHT) wells.

Hydraulic jars provide significant performance and operational benefits over mechanical jars but have some limitations. Friction generated by resistance to flow through the restriction during the metering stroke raises the temperature in the jar. When jars overheat, operators must cease jar-ring until the hydraulic fluid cools. To minimize the effects of the heat buildup, Houston Engineers developed the Hydra-Jar AP double-acting hydraulic drilling jar (above). The tool includes a unique temperature compensation design and high-temperature seals.

Jars may be run either in compression or in tension, providing the flexibility for optimized placement in the drillstring. Additionally, because the tool works without applied torque, the drillstring is not rotated during jarring, thus directional drilling tool orientation is not changed. To ensure that the Hydra-Jar AP drilling jar performs effectively and reliably in specific applications, engineers developed Jar-Pact BHA impact placement software. This software models the placement of the AP Impact advance perfor-mance system. Using data from the operator’s well plan—including borehole and BHA parame-ters—the software recommends the optimal placement for the tools to avoid locating them in or near the drillstring neutral point or transition zone.13 The software also ensures that the ratio of the hole and tool diameters is within recom-mended guidelines.

Although operators strive to jar pipe free quickly with as few firings as possible, experi-ences in a well in western Canada illustrate the strength and repeatability of advanced hydrau licdrilling jars. Apache Canada included a Hydra-Jar AP tool in the drillstring in a borehole as a precautionary measure while drilling in the dolomite-carbonate Keg River Formation in Alberta, Canada. During drilling, the string became packed off by calcium carbonate buildup after several lost circulation pills were pumped to stop fluid loss.14 A combination of backreaming and impacts from the Hydra-Jar AP tool helped free the stuck pipe. The jar fired more than 200 times over a seven-hour period, with no loss of impact force. The pipe was freed, and drilling continued to TD without a fishing job, minimizing lost time and rig expense.

Jar Acceleration ToolsFor a jar to impart peak impact at any given load, the mandrel must still be accelerating when it hits the sleeve. If terminal velocity is reached prior to impact, the jar impact will be limited. Because drill collars have been replaced by lighter HWDP in many BHAs, it is often the case that working weight is no longer sufficient to gen-erate enough jar impact or impulse levels. Adding a jar accelerator to the BHA significantly ampli-fies jar impact and impulse and reflects shock-waves downward toward the stuck point (nextpage, left). It also takes stress off the drillstring and surface equipment and protects the topdrive from wear.

The Schlumberger Accelerator AP impact tool is an example of a jar accelerator tool. It is a compact, high-load rate spring tool that is placed directly above the jar and the mass of HWDP.

> Double-acting hydraulic Hydra-Jar AP tool. The drive cylinder consists of a section that allows for free axial extension and retraction of the jar mandrel while allowing torque to be transmitted through the tool. The upper fluid cylinder and balance piston maintain a pressure balance with that of the borehole. The upper detent cylinder includes a restriction called the detent. When overpull tension is applied, the detent piston is pulled toward the detent, metering the hydraulic fluid through the detent piston and allowing stretch to accumulate in the drillstring. The detent piston moves through the cylinder at a slow rate until it clears the detent, tripping the jar and firing upward. The lower detent mandrel and cylinder perform the same functions as their upper counterparts, but allow for downward jarring.

Fluidcylinder

Drive cylinder Lower detentcylinder

Upperdetent

cylinder

DetentBalance piston

Upper detentmandrel

DetentpistonLubricant

Lower detentmandrel

Neutralizercylinder

Connectorsub

Neutralizerpiston

Hydraulicfluid

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11. Adelung D, Askew W, Bernardini J, Campbell AT Jr, Chaffin M, Hensley R, Kirton B, Reese R and Sparling D: “Jars, Jarring and Jar Placement,” Oilfield Review 3, no. 4 (October 1991): 52–61.

12. Adelung et al, reference 11.

When a load is applied to a jar accelerator tool impact system, the load compresses the fluid, gas or spring inside the accelerator tool, thereby storing potential energy in the tool. The jar and accelerator are coordinated so that when the jar

releases for impact, the stored potential energy in the accelerator is also released. The potential energy stored in and released from the accelera-tor tool accelerates the working mass above the jar much more efficiently than does energy

stored in the drillstring because it eliminates the wellbore friction and drag generated over hun-dreds of meters of drillpipe. Using the accelera-tor tool can effectively double the impact force of a jar (below).

> Stopping vibrations. When a jar is fired, it induces an initial wave of vibrations downward and upward along the drillstring. The downward wave is reflected upward from the stuck point. In addition to increasing jar efficacy, an accelerator effectively prevents the initial waves and reflected waves from reaching the drill floor by acting as a hydraulic disconnect within the drillstring.

Reflection point

Jar-induced initialvibration wave Reflected vibration

Stuck point

Jar

Accelerator

Reflection point

13. A transition zone is the area of the drillstring between the neutral point and the state of either tension or compression. The location of the transition zone varies throughout the drilling process.

14. Cook J, Growcock F, Guo Q, Hodder M and van Oort E: “Stabilizing the Wellbore to Prevent Lost Circulation,” Oilfield Review 23, no. 4 (Winter 2011/2012): 26–35.

> Amplifying jar impact. The accelerator tool consists of an outer barrel and an inner mandrel connected by a piston chamber filled with silicon fluid (topleft). When a force is applied to the accelerator tool (top right), the silicon liquid is compressed by the moving piston, storing the energy of the applied tension and providing extra stretch to the drillstring. When the force is released, the silicon liquid expands, and, like a spring, moves the piston back to its original position. This movement amplifies the final impact and impulse released (bottom) by a jar as a result of adding the energy stored in the accelerator to the energy stored in the pipe.

Inner mandrel

Accelerator withForce Applied

Accelerator withNo Force Applied

Outer barrel

Piston chamberfilled with

silicon fluidSilicon fluidcompressed byinner mandrelbeing pulled up

Piston

Impa

ct fo

rce,

lbf ×

1,0

00

0

200

400

600

800

1,000

1,200

1,400

140 1601201008060Applied force, lbf × 1,000

40200

Hydra-Jar APdrilling jar alone

Hydra-Jar AP drilling jarwith accelerator tool

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In contrast to the experience of Apache Canada, engineers at Arbaj Energy Services found quick jarring success through use of an accelerator tool. In a well in Oman, the drillstring became packed off and stuck when it was picked up 16 m [53 ft] to perform a flow check after drilling a long vertical section from 957 m[3,140 ft] to TD at 3,590 m [11,800 ft]. Circulation, rotation and upward and downward movement were lost. After initial attempts to free the BHA, the operator replaced a failed drilling jar and intensifier with a Hydra-Jar AP and Accelerator AP impact tool and performed a Jar-Pact placement analysis to optimize impact and impulse values at the stuck point.

Based on the results of the Jar-Pact analysis, the BHA above the stuck point was backed off one drill collar above the top stabilizer at a depth of 3,536 m [11,601 ft], and the pipe was pulled out of hole. The Hydra-Jar AP and Accelerator AP tools were deployed as a fishing assembly, which was run into the hole and engaged around the stuck BHA. Although the initial plan called for jarring downward for eight hours and then upward for another eight hours, the stuck BHA began to move after only one hour of downward jarring. Within six hours, a 14-m [46-ft] pocket had been created, enabling the operator to regain circulation and rotation of the BHA. The successful jarring operation saved Arbaj Energy Services more than US$ 1.3 million by avoiding a costly sidetrack.

Although jar accelerators are recommended for use in all types of holes, they are particularly beneficial in high-angle and horizontal wells, plastic salt sections, areas with a high probabil-ity of differential sticking, wells with a high degree of string drag and in downward jarring applications. Experiences in one West Texas, USA, well serve to highlight the benefits of fore-thought. Engineers had deployed a Hydra-Jar AP double-acting hydraulic drilling jar and an Accelerator AP tool in the toolstring to reduce potential topdrive damage resulting from jarring operations and to increase the likelihood of suc-cessfully freeing pipe that they thought might become stuck while drilling an 81/2-in. hole through the Akota Shale section. Heaving shale caused the BHA to become stuck while a connec-tion was being made, and the rig was unable to circulate. Jarring began immediately. The energy stored in the accelerator tool added to the energy already stored in the drillstring to provide up to twice the impact at the stuck point than would have been available without an accelerator.

However, because the accelerator is a telescop-ing component, it absorbed the refractory force that otherwise would have been sent up the drill-string to the surface equipment. With the jar and accelerator combination, the drillstring was freed in 45 min, with no damage to the topdrive. Drilling was able to proceed, and the operator averted a potential sidetrack operation.

Jar Placement GuidelinesJar design and jar placement are the largest determining factors in the success or failure of a jarring operation. Yet, since their introduction, methods of jar deployment have depended more on driller experience and common practice than on engineering analysis—partly because indus-try professionals have insufficient understanding of the design and dynamics of jars. Because jars appear solid, like drill collars, users often assume they are as strong as drill collars. However, unlike drill collars, the internal workings of jars are complex, with numerous connections and inherent weakpoints. Additionally, the threads on the internal connections of jars are not as strong as the API threads used to connect joints of drillpipe.

Jarring success rates vary, but Schlumberger engineers have determined that 65% of failures are related to improper jar placement. The differ-ence between proper and improper jar place-ment can translate to savings or losses of hundreds of millions of dollars per year for today’s operators. Yet the intricacies of jar place-ment are typically misunderstood and often overlooked, and published recommendations on jar placement, based on proven successes, are difficult to find.15

Directional drilling companies and their cli-ents often begin planning a directional well months in advance with attention to BHA designs that will propel the well from its starting point to TD. However, the jar is often placed in the BHA as an afterthought by engineers more concerned with placing the jar so it does not impede drilling than maximizing the impact and impulse that are critical to successful jarring. If engineers run a jar placement analysis, they often do so immedi-ately prior to tripping, which greatly reduces chances a jar will be optimally placed.

The role of engineering analysis in determin-ing proper jar placement is increasing, as is the need for running analysis earlier in the well plan-ning process. Because the dynamic response of a drillstring to the various forces associated with jarring is complex, there is growing industry demand for jar placement software programs

that are sophisticated in their functionality yet easy to use. Simple formulae may aid in the place-ment and use of jars; however, more-complex questions cannot be answered with simple engi-neering tools. These questions are best resolved through finite element analysis, which is integral to modern jar placement and analysis software programs. These programs can help the driller investigate and evaluate the effectiveness of the jarring operation at various jar locations in the BHA (next page).

In the absence of jar placement software, cer-tain guidelines have been developed for jar place-ment. The first step is to consider several basic questions:

drillstring becoming stuck?

compression?

drilling jar when drilling?

action?-

ters within the specifications of the drilling jar and accelerator tool design constraints?

deviated or horizontal?

For example, are temperatures or pressures extremely high? Does the mud have high solids content? Is hydrogen sulfide [H2S] present or suspected?

In addition to these basic questions, four fun-damental guidelines help optimize jar place-ment. The first is to place a minimum of 10% to 20% of the expected jar overpull as hammer weight above the jar, which ensures that an ade-quate weight will produce optimal impacts. This hammer weight range has been found to provide the ideal mass while maintaining adequate velocity for delivering optimal impacts to the stuck point.

The second guideline is never place the jar too close to the neutral point. Many drillpipe fail-ures occur around the neutral point because lateral vibrations tend to be more severe in this area. Additionally, placing the drilling jar too

15. Bouaziz S, Cummings J, Rebellon J, Barton S and Yankow A: “Advancements in Downhole Drilling Tool Placement for Highly Deviated Wells and ERD Applications,” paper SPE 144030, presented at the SPE North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, USA, June 14–16, 2011.

16. Askew WE: “Computerized Drilling Jar Placement,” paper IADC/SPE 14746, presented at the IADC/SPE Drilling Conference, Dallas, February 10–12, 1986.

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close to the neutral point will result in the jar continuously cycling between compression and tension, which can accelerate fatigue damage and decrease operational life; it may also cause the drilling jar to fire unexpectedly. Maintaining 20% of weight on bit (WOB) between the drilling jar and neutral point will ensure that the jar is outside the neutral point transition zone. Jar placement should be reconsidered when changes are made to WOB or the BHA.

The third and fourth guidelines are never to place stabilizers or other BHA components—if they have an outer diameter larger than that of the jar—above the drilling jar, and always to keep any stabilizer at least 28 m [92 ft] away from the drilling jar. A jar should never be used as a crossover between drill collars and HWDP or two different sizes of collars. High bending stresses that occur in these locations can increase the risk of tool damage.

Next StepsThe proliferation of highly deviated wells and extended-reach drilling associated with deepwa-ter operations and the discovery and development of shale plays have brought about new and increased drilling challenges, including the pos-sibility of pipe becoming stuck in two different sections of the wellbore. The art and experience that an oilfield fishing hand brings to fishing oper-ations have a value that can never be overesti-mated. However, given the demands, risk and cost of today’s drilling operations, experience may not be enough. Experience tends to be based on sur-face measurements, which may not reflect what is happening downhole.16 Conventional knowledge and assumptions about jar placement may not apply to these new drilling environments.

While placing a jar in the BHA can act as a precaution against wellbore damage, lost time and costs associated with stuck pipe, the place-ment of the jar must be carefully considered and analyzed for its benefits to be fully realized. As drillers learn more about the intricacies of jar-ring, and as jar providers and drilling companies collaborate sooner and more strategically in the well planning process, jarring success rates will rise, and damage and costs associated with stuck pipe events will decline. —JF

> Jar placement. High-angle and long-reach wells challenge conventional wisdom and assumptions about jar placement that are the legacy of many years of vertical drilling. For example, in horizontal wells, a single jar can be placed in either the upper curve (top left) or lateral section (top right).Placing a single jar in the upper curve protects the lower BHA and reduces the threat of not getting enough weight or overpull to operate the jar. However, jarring in the lateral section is relatively ineffective and impacts at the stuck point are almost always less than needed. Placing the jar in the horizontal section poses a greater risk of not being able to overcome the hole drag to fire the jar. More recently, operators are commonly placing jars in both the curve and the lateral (bottom left). Dual jar placement protects both the curve and the lateral while delivering stronger impacts at the stuck point. Adding an accelerator tool above each jar (bottom right) doubles the impacts of both jars by minimizing velocity losses caused by drag and increasing the efficiency of the lower jar. When running the dual jar option, it is important to maintain sufficient spacing between the two jars to avoid damaging the lower jar with impacts generated by the upper jar.

Drillpipe

Jar

Drillpipe

Heavyweight drillpipe

Horizontal Hole Placement, Single Jar in Top Curve

Drillpipe

Drillpipe

Heavyweight drillpipe

Horizontal Hole Placement, Single Jar in Lateral

Jar

Transition area,potential stuck point

Horizontal Hole Placement, Dual Jar

Jar

Jar

Drillpipe Accelerator

Drillpipe

Transition area,potential stuck point

Horizontal Hole Placement, Dual Jar and Dual Accelerator

Jar

JarAccelerator

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24 Oilfield Review

The Expanding Role of Mud Logging

For decades, samples and measurements obtained at the surface have provided mud

loggers with insights into conditions at the bit face. Information captured through

mud logging gave operators early indications of reservoir potential and even warned

of impending formation pressure problems. New sampling and analysis techniques,

along with advances in surface sensor design and monitoring, are bringing the

science of mud logging into the 21st century.

Peter AblardChris BellChevron North Sea LimitedAberdeen, Scotland

David CookIvan FornasierJean-Pierre PoyetSachin SharmaRoissy-en-France, France

Kevin FieldingLaura LawtonHess Services UK LimitedLondon, England

George Haines Houston, Texas, USA

Mark A. HerkommerConroe, Texas

Kevin McCarthyBP ExplorationHouston, Texas

Maja RadakovicSinopec-AddaxGeneva, Switzerland

Lawrence UmarPetronas Carigali Sdn BhdKuala Lumpur, Malaysia

Oilfield Review Spring 2012: 24, no. 1. Copyright © 2012 Schlumberger.For help in preparation of this article, thanks to Justin Ashar, Kamel Benseddik, Regis Gallard, Willie Stoker and Craig Williamson, Houston; John Christie, Paris; Gen Herga and Denise Jackson, Gatwick, England; Mark Jayne, Francois Le buhan, Remi Lepoutre, Jacques Lessi, Audrey Malmin, Keith Ross and Philippe Verdenal, Roissy-en-France, France; Nikhil Patel, Singapore; and Irwan Roze, Conroe, Texas.FLAIR, MDT, PreVue, RFT, StethoScope and Thema are marks of Schlumberger.

The mud logging unit has long been a common wellsite fixture. First introduced commercially in 1939, these mobile laboratories carried little more than a coffee pot, a microscope for examin-ing formation cuttings and a hotwire sensor for detecting the amount of hydrocarbon gas encoun-tered while drilling. The mud logger’s job was to record the depth and describe the lithology of formations that the drill bit encountered, then determine whether those formations contained any oil or gas.

Outside the logging unit, the mud logger’s domain ranged from the shale shaker to the drill floor. The shale shaker yielded formation cuttings and gas—both liberated by the drill bit—which were transported to the surface in the drilling fluid. Periodic visits to the shaker permitted the mud logger to collect cuttings for microscopic examination, while a suction line between the shaker and the logging unit carried gas from the gas trap to the logging unit’s hotwire gas detec-tion system. Visits to the drill floor allowed important exchanges of information between the mud logger and driller. Using basic surface mea-surements, the mud logger was able to produce a concise account of drilling activity.

For decades, gas measurements, lithology and rate of penetration (ROP) provided the earliest indications of reservoir potential. Before the advent of measurements while drilling (MWD) and logging while drilling (LWD), mud loggers were able to obtain valuable formation data from wells in which drilling conditions, formation characteristics or well trajectory conspired

against deployment of wireline logging tools. In such wells, analysis of mud gas and cuttings often provided the first, and perhaps only, indication that a formation might be productive. Today, although LWD technology is able to give the first glimpses of near-bit conditions in real time, adverse wellbore conditions sometimes preclude the use of downhole logging tools. In such cases, the mud log continues to inform operators of the producibility of their wells. At a minimum, the mud log gives the operator an early indication of zones that merit special attention, additional log-ging services or production tests.

The mud log serves a variety of functions. As a correlation tool, the mud log’s ROP and total gas curves exhibit a remarkable correspondence to gamma ray and resistivity curves, respectively.1

Throughout the drilling process, mud logs pro-vide real-time correlations with logs from neigh-boring wells and help the operator track the bit’s position in relation to target formations. Because the mud log is based on physical samples, it pro-vides direct, positive identification of lithology and hydrocarbon content. This information can be helpful when formation characteristics make wireline or LWD log interpretation complicated or ambiguous. It can also fill gaps where other such measurements have not been obtained. Thus, when integrated with wireline or LWD mea-surements, cores and well test data, the mud log provides independent evidence for a more com-prehensive understanding of reservoir conditions and geology.

1. Like electric logs, most mud logs conform to format standards set forth by the Society of Professional Well Log Analysts (SPWLA). For mud log standards promulgated by SPWLA: Mercer RF and McAdams JB: “Standards for Hydrocarbon Well Logging,” Transactions of the SPWLA 23rd Annual Logging Symposium,Corpus Christi, Texas, USA, July 6–9, 1982, paper LL.

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Spring 2012 2525

The scope of the basic mud logging service has broadened over time, as additional sensors brought more data into the logging unit—expanding in diversity from gas chromatographs to weight-on-bit and mud pit level indicators. The mud logging service now typically tracks ROP, lithology, visual hydrocarbon indicators, total combustible gas in mud and individual hydrocar-bon compounds in the gas, along with numerous drilling parameters. As a hub for monitoring drill-ing operations and rig sensors, the mud logging unit has become a source of crucial information for the company representative, the driller and the geologist.

The mud logger’s role takes on added impor-tance when there is a drilling break, or signifi-cant increase in ROP. Then the mud logger alerts the company representative and requests that drilling be stopped until mud and cuttings from the bit face can be circulated to the surface. If mud analysis indicates the presence of hydrocar-bons—called a show—the mud logger informs the geologist, who may elect to core or test the interval. Geochemists and biostratigraphers also rely on mud loggers to collect representative samples needed to make correlations and develop geologic models.

From a drilling standpoint, the mud logger’s most important task is gas monitoring. Mud gas trends that develop while drilling are integral to evaluation of mud balance and identification of potentially overpressured formations. By care-fully tracking gas and drilling parameters, the mud logger can recognize impending deviations from normal trends and give advance warning so the driller and company representative can miti-gate the problem by adjusting the density of the drilling fluid or shutting in the well. Thus, the success of a well and the safety of the drilling operation may hinge on how quickly a mud logger can synthesize and interpret myriad pieces of data.

Sand trap

Reserve pit

Mud pumps

Suctionpit

Mudmixing

pit

Mudloggingcabin

Settling pit

Drill floor

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26 Oilfield Review

Mud logging capabilities have evolved over the years. By the mid-1950s, gas samples were being analyzed by wellsite gas chromatography. In the 1960s, mud logging companies began offer-ing geopressure detection services.2 Automated event recorders, made possible through use of robust microelectronic components, were incor-porated into mud logging processes during the 1970s. During the following decade, mud logging units entered the computer age. Computers took the burden of printing the log away from the mud logger, who used to laboriously compile the data and then draw the log by hand. In addition, com-puters allowed mud loggers to organize and track data from multiple sources without sen-sory overload.

Advances in computing and networking tech-nology, surface sensor design and sample analysis are bringing the mud logging unit into the 21st century. Today, even more sensors lead into the logging unit, each acquiring data at a frequency of several times per second. To handle this increase in data volume, a context-aware processing sys-tem—based on computer-generated trend lines and a library of established models—makes the data easier for the mud logger and other end users to comprehend. Digital images of samples viewed under the microscope can be rapidly transmitted from the wellsite to the client office. And new approaches to gas sampling and analysis have been developed to extract geochemical properties at the wellsite.

This article describes how a basic mud log is assembled, reviews sampling and analysis tech-niques used in formation evaluation and dis-cusses basic methods for monitoring pressure. An overview of recent sensor technology maps the evolutionary path from basic formation evalua-tion to advanced analysis of mud gases for geolo-gists and well integrity services for drillers.

Mechanics of Mud Logging In the oil field, drilling fluid is integral to every drill-ing project. Be it water-base, oil-base or gas-base, drilling fluid is vital to the process of making hole:

on the drill bit to clean the bit and carry heat away from the bit face.

the surface, thus playing an essential role in the hole cleaning process.

wellbore stability and prevent the influx of for-mation fluids that could cause blowouts.

Over time, numerous variations on the basic mixture of clay- and freshwater-base drilling flu-ids have been developed (and sometimes dis-carded). Well-known variations are based on saltwater, mineral oil, diesel oil, polymers, nitro-gen, mist and foam. Each type has specific prop-erties that deliver superior performance in certain drilling environments. And each requires special accommodations when it comes to mud logging: Some require custom sampling tech-niques; others require special sample rinsing pro-cedures. This section focuses on the simplest of environments, in which freshwater-base drilling muds are used.

The practice of mud logging relies heavily on the mud circulation system, which carries forma-tion cuttings and fluids to the surface. High-pressure mud pumps draw drilling fluid from surface tanks and direct it downhole through the drillpipe (left). The mud exits the drillstring through nozzles at the face of the bit. Pump pres-sure forces the mud upward through the annular space between the drillpipe and casing, to exit at the surface through a flowline above the blowout preventer. The mud then passes over a vibrating mesh screen at the shale shaker, where forma-tion cuttings are separated from the liquid mud. The mud falls through the screens to the mud pits before being pumped back into the well.

As a bit drills through the subsurface, the rock it grinds up—along with any water, oil or gas contained therein—is carried to the surface by the drilling mud. What arrives at the surface and when it arrives

>Mud circulation system. Drilling mud, drawn from the suction pit and pumped through surface pipe, is sent downhole through the center of the drillpipe. It enters the open borehole through nozzles (not shown) on the bit. The mud cools and lubricates the bit, then carries away formation cuttings and fluids as it moves upward in the annular space between the pipe and borehole wall. At the surface, the mud, formation fluids and cuttings are diverted through a side outlet in the bell nipple and through an inclined flowline to the shale shaker. A mud agitator, or gas trap, is positioned at the shaker’s header box to liberate gas from the mud. A suction line at the top of the agitator siphons gas off from the mud and sends it to the mud logging unit for analysis. The mud flows over the shaker, where screens separate the cuttings from the mud, which is returned to the shaker pit.

Traveling block

Standpipe

Flowline

Suction line

Rotary tableMud logging unitShale shaker

Gas trap

Blowout preventerBell nipple

Kelly

Drill floor

Suctionpit

Shakerpit

Mudpump

Drillpipe

Casing

Bit

Reservepit

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Spring 2012 27

are fundamental to the science of mud logging. The type of material and the timing of its arrival are influ-enced to varying degrees by drilling practices, lithol-ogy and pressure.

The mud logger requires samples of formation cuttings to ascertain the subsurface geology at a given depth. Therefore, cuttings must be large enough to trap on the shaker or desilter screens. On average, rock cuttings are roughly the size of coffee grounds (right). Their size is controlled largely by how consolidated the rock is, along with grain size and cementation of the rock. In shale, pressure can affect the size of cuttings, and large elongated cavings of spalling shale that pop off the borehole wall are a strong indicator of overpressure. Bit type plays a significant role as well. Roller cone bits with chisel teeth produce a coarser grade of cuttings than do those with car-bide buttons. Polycrystalline diamond compact (PDC) bits in soft formations typically use large cutters that produce large cuttings (below right).Harder formations call for smaller PDC cutters, which produce smaller cuttings.

The volume of cuttings that flow across the shaker is a function of bit size and ROP.3 Bit size controls the cross-sectional area of the hole. ROP controls the thickness of the interval drilled over a given period. These factors are, in turn, affected by pump rate, weight on bit (WOB), rotary speed, fluid viscosity and mud density, commonly referred to as mud weight (MW).

To characterize the lithology of a particular interval in a well, the mud logger must account for the transport velocity of the cuttings to cor-rectly determine the amount of time it takes the cuttings to travel from the bit face to the shale shaker. This lag time increases with depth, taking just a few minutes while drilling the upper sec-tion of a well, but extending to several hours in deeper sections. An accurate determination of lag time is crucial for precisely correlating cut-

tings and fluid samples to the formations and depths from which they originate.

One method for determining lag is to calcu-late the amount of time required to displace the total annular volume of drilling fluid. This method calls for the mud logger to factor in the length and diameter of the open hole, the capacity and displacement of the tubulars—riser, casing and drillpipe—in addition to mud pump output, with separate calculations performed at each change in hole or pipe diameter. However, the calculated result tends to be optimistic, underestimating hole volume because it does not account for rugosity or washouts, which affect mud volume and velocity of flow.

A more reliable method for determining lag time may be obtained through use of a tracer that is pumped downhole and detected upon its return to the surface. Various tracer substances have been tested, ranging from oats, corn or rice to paint, calcium carbide nuggets or injected gas—some types are precluded out of concern for their effects on downhole equipment; others are used only in certain regions.4 In most cases, the tracer is simply wrapped in tissue paper, then inserted into the drillpipe when a connection is made on the drill floor. The paper disaggregates on its trip through the drillpipe and the tracer passes through the nozzles in the bit. The mud logger starts a timer when the pumps are turned on, and the time it takes the tracer to circulate downhole

and back to the surface is calculated so that the mud logger can anticipate its arrival. The timer is turned off when the tracer reaches the shale shaker. Knowing the pump rate and the inside diameter of the drillpipe, the mud logger can cal-culate the fluid volume contained within the pipe to TD; then, knowing the pump displacement, the number of strokes to pump the tracer downhole can be calculated. The mud logger can convert this to the time it takes the tracer to travel from the surface to the bit. Subtracting this time from the total measured time allows computation of the lag time from the drill bit to the surface.

2. Geopressure is synonymous with formation pressure. In common oilfield parlance, the term refers to an anomalous fluid pressure condition that is above or below the normal hydrostatic pressure condition for a given depth. Normal pressure, overpressure or underpressure is either equal to, above or below hydrostatic pressure, respectively.For more on this topic: Barriol Y, Glaser KS, Pop J, Bartman B, Corbiell R, Eriksen KO, Laastad H, Laidlaw J, Manin Y, Morrison K, Sayers CM, Terrazas Romero M and Volokitin Y: “The Pressures of Drilling and Production,” Oilfield Review 17, no. 3 (Autumn 2005): 22–41.

3. Whittaker A: Mud Logging Handbook. Englewood Cliffs, New Jersey, USA: Prentice Hall, 1991.

4. Calcium carbide [CaC2] reacts with water in the drilling fluid [CaC2+2H2O→C2H2+Ca(OH)2]. The acetylene [C2H2]produced in this reaction is a gas not normally found in sediments. The acetylene will, in turn, be picked up at the gas trap, and its arrival will be noted automatically by the gas detector and gas chromatograph inside the mud logging unit.

> Cuttings sample. Having been cleaned and dried, these shale cuttings will be examined under a microscope.

> Cuttings from a PDC bit. Claystone in a mud logger’s sieve shows tool marks, evidence of shearing action by a PDC bit.

8 in.

Cutting withtool marks

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28 Oilfield Review

Lag can also be measured in mud pump strokes. Sensors placed on the mud pumps detect piston movement and transmit a signal to the pump stroke counter display in the mud logging unit. The counters are set to zero when the tracer is inserted into the drillpipe and are read when the tracer arrives at the surface. A pump stroke counter will add increments only when the pump is running; its rate thus reflects the true pumping rate, despite interruptions for connections or pump maintenance. The number of pump strokes

needed to pump the tracer downhole to the bit is subtracted from the total count to determine the number of pump strokes required to circulate the mud and cuttings from the drill bit to the surface.

Lag is usually measured on a daily basis and at each casing point. The calculated lag is useful in determining the impact of formation washouts between measured lag intervals. For example, a carbide tracer is placed into the drillpipe during a connection. After 1,800 pump strokes, the gas detectors record an acetylene peak. Given that the

calculated lag was 1,710 pump strokes, this 6% dif-ference in lag time can be attributed to borehole

5. ECD is the effective density exerted at a given depth by circulating fluid against the formation. The ECD is calculated as:ECD = d + P/(0.052×D), where d is the mud weight in pounds per gallon (lbm/galUS); P is the pressure drop in psi in the annulus between depth, D, and surface; D is the true vertical depth in ft and 0.052 is the conversion factor from psi/ft to lbm/galUS.

6. In this case, swabbing refers to a slight reduction in annular pressure caused by pipe movement during a connection. The amount of gas produced into the borehole as a result of swabbing depends on mud rheology, pipe velocity during movement and pipe and annulus diameter.

> Excerpt from a basic mud log. A mud log typically displays ROP, depth, cuttings lithology, gas measurements and cuttings descriptions. It may also contain notes on mud rheology or drilling parameters. This log documents fairly routine drilling, with casing set in a shaly interval at 7,580 ft. After drilling out of casing and running a leakoff test (LOT), ROP was about 25 to 30 ft/h [7.6 to 9 m/h]. A trip for a new bit at 7,650 ft resulted in 1,548 units of trip gas (TG). During drilling at near-balanced conditions, small increases in connection gas (CG) were observed following each connection, prompting the driller to raise the mud weight. An increase in ROP at 7,890 ft signified a drilling break, which was accompanied by increasing sand content and a gas show, which reached a peak of 920 units of gas (FG). Gas detector results are expressed in parts per million (ppm) of equivalent methane in air on a volume basis, where 10,000 ppm is equal to 1% methane, or 50 units. The wellsite gas chromatograph typically tracks methane [CH4]—denoted as C1—as well as the following constituents: ethane [C2H6] or C2, propane [C3H8] or C3 propane [C3H8] or C3 and the normal isopolymers of butane [C4H10] or nC4 and iC4 and pentane [C5H12] or nC5 and iC5.

Fluo

resc

ence

10 100

1k 10k

100k

1,00

0k

Trip for new bit6.3 bbl gain

TG: 1,548 U

CG: 35 U

Clay

CG: 39 U

CG: 45 U

FG: 427 U

FG: 920 U

WOB 38 to 53 klbRPM 78 to 84Flow 650 gpm

7,500

100 50

ft/h Depth, Cuttings, Total Gas, units

Chromatograph, ppm

Mud Weight,ppg

In: 10.8Out: 10.8

Sandstone: Clr-lt gy-frst, m-f gr,sbelg-elg, sbang-sbrnd, m srt, tr Glau,calc mtx, p-m cmt, qtzc i/p, m ind,fri-m hd, p-fr intgran por, no fluor.

Sandstone: Clr-lt gy-frst, m-f gr,sbelg-elg, sbang-sbrnd, m srt, tr Glau,calc mtx, p-m cmt, qtzc i/p, m ind,fri-m hd, p-fr intgran por, no fluor.

Sand: Clr-frst, trnsp-trnsl, m-c gr,occ f, sbelg-sbsph, ang-sbang, m srt,tr Glauc, uncons-p cmt, p ind, lse, n por,Qtz, no fluor.

Sand: Clr-frst, trnsp-trnsl, m-c gr,occ f, sbelg-sbsph, ang-sbang, m srt,tr Glauc, uncons-p cmt, p ind, lse,Qtz, no fluor.

9 7/8-in. casing set at 7,580 ft MD/6,691 ft TVD. LOT = 14.8 ppg.Clay: Lt brn-tan, arg, calc, plas,sft, sol, slty, rthy, grty.

Clay: Lt brn-tan, arg, calc, plas,sft, sol, stky i/p, rthy, grty.

Clay: Lt brn-tan, arg, calc, plas,sft, sol, stky i/p, rthy, grty.

Shale: Lt gy-lt brn, grnsh gy, arg, calc,frm-hd, occ sft, p-m cpt, sbblky-blky,splty-ppy i/p, rthy, grty.

Shale: Lt gy-lt brn, grnsh gy, arg, calc,frm-hd, occ sft, p-m cpt, sbblky-blky,splty-ppy i/p, rthy, grty.

IncreaseMW to 11.3

IncreaseMW to 11.5

IncreaseMW to 11.7

IncreaseMW to 12.0

Lithological Descriptionand Notes

C1

%ft

ROP

0 0 125 250 375 500

0.5k 1k 1.5k 2k 2.5k

7,600

7,700

7,800

7,900

8,000

nC4iC4

nC5iC5

C2 C3

Shale Sandstone Sand Limestone Dolomite Anhydrite Coal

Formation gasFG CG TGConnection gas Trip gas Oil and gas Oil Gas Bit change, trip Shoe

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Spring 2012 29

enlargement. By multiplying pump displacement by the difference in pump strokes, it is possible to determine the total volume of borehole washouts. This volume is also used in extrapolating lag calcu-lations beyond the measured lag point.

In some cases, another type of gas may help mud loggers keep track of lag. Connection gas is typically detected when drilling at near-balanced conditions in which pressure exerted by the mud is held close to formation pressure. When a connec-tion is made on the drill floor, the mud pumps are stopped and the pipe is picked up to bring the bit off bottom. With pumps off, the effective mud weight is reduced from equivalent circulating density (ECD) to static mud weight, and the hole is swabbed some-what as the pipe is picked up.5 These conditions can create a reduction in bottomhole hydrostatic pres-sure sufficient for small amounts of gas to be pro-duced by the formation.6 When present, this connection gas is detected at one lag interval after a pipe connection. Each occurrence of connection gas reflects the amount of lag for the depth of the bit when the connection took place.

Basic Formation EvaluationIn its most basic form, the mud log is a record of the drill rate, cuttings lithology, total combusti-ble gas and individual hydrocarbon compounds brought to the surface during drilling operations.

The mud log provides a condensed record of sub-surface geology, the hydrocarbons encountered and notable activities while drilling the well (pre-vious page).

The ROP curve records how much time the bit takes to penetrate each meter or foot, as deter-mined by a sensor on the drawworks. The ROP curve can be plotted as a step chart or a continu-ous line, increasing from right to left. When dis-played in this manner, the ROP curve responds to changes in rock type or porosity in much the same manner as a spontaneous potential or gamma ray curve, making for easy correlation between these curves.

A variety of factors affect ROP, including rock type, porosity, WOB, MW and rotary speed (rpm) as well as bit type, diameter and condition. Because drilling practices affect ROP as much as geology does, the mud logger makes note of cer-tain drilling parameters next to the ROP curve, especially when they change.

The ROP curve is interpreted in the same manner as a gamma ray log. Typically, a shale baseline is established through a thick interval of generally slow, consistent drilling— the shale inference can be verified through analysis of

formation cuttings. Deviations from this ROP baseline may indicate a change in lithology or other downhole variables. For example, a drill-ing break may signify a change from shale to sand or an increase in bottomhole pressure caused by crossing a fault. A sudden decrease in ROP, sometimes called a reverse drilling break,may indicate a transition to rock of greater den-sity, or it may signal a problem with the bit. These indicators must be weighed against other measurements to ascertain their true cause.

The lithology column is based on analysis of lagged samples of cuttings. Samples are generally collected at regular intervals—for example, every 3 m [10 ft] or every 10 m [30 ft]—and prior to trip-ping out of the hole. They are also collected when ROP or gas curves exhibit significant deviations from established trends, indicating changes in for-mation characteristics. The lithology column dis-plays an estimate of gross lithology as a percentage of cuttings, reported in 10% increments.

The cuttings sample is rinsed and dried, then examined under a binocular microscope. The sample is then described in terms of lithology, color, grain size, shape, sorting, porosity, texture and other characteristics relevant to the particu-lar rock type (below).

>Microscopic examination. Rinsed and dried samples are examined under a microscope (left ) to provide lithological descriptions (right ) for the mud log. The inset photograph shows a typical sample with a mix of rock types, dominated by gray claystone with a lesser fraction of clear to off-white sand. In some logging units, a camera is attached to the microscope. This allows the mud logger to thoroughly document potentially productive zones, uncommon minerals, distinctive marker beds or even metal shavings (indicative of casing or bit wear) found in the sample.

Cuttings Sample Description

1. Rock name2. Color3. Hardness, fissility4. Elements or grains

6. Accessories, fossils7. Visual porosity estimation8. Hydrocarbon indications

5. Cement and matrix

Clastics a. grain size b. roundness c. sphericity d. sorting

Carbonates a. “grain” nature b. “grain” size

Clastics a. abundance b. nature

a. visual (stains and bleeding) b. direct fluorescence (extent, intensity and color) c. cut fluorescence (rate, intensity and color)

Carbonates a. abundance b. crystallinity

Camera

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The presence of hydrocarbons may not be obvious—even under a microscope—so each sample is subjected to a variety of simple tests to screen for hydrocarbons. First, the sample is examined under an ultraviolet (UV) light. Fluorescence is an extremely sensitive test for the presence of hydrocarbons in mud, drill cut-tings and cores. Sample fluorescence is evalu-ated in terms of color (ranging from brown to

green, gold, blue, yellow or white), intensity and distribution. Fluorescence color can indicate oil gravity, with dark colors suggestive of low–API gravity, heavy oils, while light colors indicate high–API gravity, light oils.

Because fluorescence may be attributed to a number of causes, the cuttings that fluoresce are separated from the main sample for further examination. Various mud additives, oil in the rock and certain types of minerals—such as pyrite and calcite—may cause a sample to fluo-resce. The mud logger must compare mud addi-tives against rock cuttings to recognize the effects of additives. Mineral fluorescence may closely resemble oil fluorescence, but the differ-ence can be confirmed by application of a sol-vent. Mineral fluorescence will remain undisturbed, whereas hydrocarbon fluorescence will appear to flow and diffuse into the solvent as the oil dissolves. This diffusion is known as cutfluorescence, or more commonly just cut. Under UV light, hydrocarbons may be seen to stream from the rock pores into the surrounding solvent, turning the solvent cloudy. If no streaming cut is observed, the sample is left until the solvent has evaporated and then examined once more under UV light. A fluorescent ring around the sample indicates that hydrocarbons have been liberated

by the solvent (above). The mud logger will note whether the cut is immediate or delayed, to pro-vide a qualitative inference of permeability.

Odor is another good indicator of hydrocar-bons. If the drilling mud is ruled out as the source of an oily odor, then the presence of hydrocar-bons should be investigated. However, the lack of an odor is not diagnostic of an absence of hydro-carbons, especially in gas zones.

Some rock grains may be stained through exposure to oil. The color of the stain can range from dark brown for low–API gravity oils, to col-orless for high–API gravity oils and condensate. The amount of staining or bleeding—the slow discharge of oil—in oil-bearing cuttings or cores is a qualitative measure of permeability.

Reaction to acid can be a sensitive indicator of oil in carbonate rock samples, as long as oil-base fluids or hydrocarbons were not added to the mud system. To test for oil, the mud logger applies dilute hydrochloric acid to fragments of rock in a spot plate (left). The presence of oil is indicated by the formation of large bubbles as the acid reacts with carbonate in the matrix to free the oil contained within the rock’s pores. In some cases, the oil will display an iridescent rainbow on the bubble’s surface.

> Fluorescence under UV light. Mineral fluorescence (light colors, left ), often seen in rock samples, is not an indicator of pay. Streaming cut (center ),however, is produced by an oil-bearing sample placed in solvent. Two faint streams of oil can be seen at the 5 o’clock and 11 o’clock positions on the sample. As this milky cut streams oil into the solvent, it gives the clear solvent a light blue hue. After the solvent is allowed to dry, any oil residue will produce a fluorescent ring on the sample glass (right ), which is useful for detecting oil in low-permeability samples that do not readily produce streaming cut. (Photograph courtesy of G. Haines.)

> Reaction of carbonate rock to acid. Dilute hydrochloric acid dissolves carbonate rock, liberating any oil contained within. As it dissipates, the oil turns the clear acid brown. The three larger bubbles are a result of greater surface tension caused by the presence of oil.

Bubbles

Bubble

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Wettability can be qualitatively assessed. Failure of a sample to take on water, or the ten-dency of cuttings to float in water, may indicate that oil is present and that the sample is oil wet.7

However, samples from air-drilled wells may not wet as a result of small particle sizes and surface tension effects.

A positive result from any of these screening tests is considered an oil show, which warrants immediate notification of the company repre-sentative and geologist. The mud logger also watches for gas shows by monitoring the gas detection equipment.

The gas detection system offers near-instan-taneous readings, limited only by the lag time from the bit to the surface. Suction lines trans-port a constant stream of air and gas from the gas trap, located at the shale shaker, to the logging unit. There, sensitive gas detection instruments process samples extracted from the drilling mud. The primary tool is a flame ionization detector (FID), which can sense hydrocarbon gas concen-trations as low as 5 to 20 ppm. FID results are expressed in parts per million (ppm) of equiva-lent methane in air on a volume basis, where 10,000 ppm is equal to 1% methane, or 50 units.

The FID measurements are used to plot the total gas curve on the mud log. Background gas—a more or less constant, minimum level of gas—establishes a baseline on the total gas plot. The level of background gas may be any value from a few ppm to several percent, depending on formation and circulating condi-tions. A gas show is any significant increase in detected gas, usually also correlated with a zone of increased porosity or permeability.

The mud logger consults the gas chromato-graph for more detailed analysis during oil or gas shows. Operating on an automated cycle, the chromatograph separates the gas stream into dif-ferent fractions according to molecular weight. Cycle time—the amount of time it takes to cycle a gas sample through the chromatograph col-umn—may range from less than a minute to sev-eral minutes, depending on the type of gas separation column used in the chromatograph. Commonly detected components fall within the alkane group: methane [C1], ethane [C2], pro-pane [C3], butane [C4] and pentane [C5]. The measurement of these light hydrocarbons helps geologists characterize reservoir fluid composi-tion while drilling. Because each reservoir fluid is composed of different hydrocarbon species with differing molecular weights, the relative propor-tions of light hydrocarbons change from one fluid

type to another. The quantity of the gas recovered and the ratios of the various gases are useful in identifying zones of producible oil or gas.8

Basic Pressure MonitoringDrilling crews around the world have had to con-tend with abnormally high formation pressures. High pressures are encountered in formations in which an impermeable layer, sealing fault, diapir or other barrier restricts natural fluid flow and pressure equilibration. In these overpressured formations, fluids trapped in the pores bear part of the weight of the overlying rock. Overpressure commonly occurs when low permeability pre-vents pore fluid from escaping as rapidly as required for compaction of pore space under the weight of newly deposited overburden sediments. Excess pressure builds as the weight of overbur-den squeezes the trapped fluid in a process referred to as undercompaction or compaction disequilibrium. This undercompaction typically occurs where there is a transition from a sand-prone to a shale-prone environment.9

Detection of overpressured formations is crit-ical to the drilling process; by providing this ser-vice, mud logging plays an important role in well control. Drillers are extremely keen to recognize impending threats to well control, but the sim-plicity of rig floor instrumentation sometimes makes it difficult to identify subtle changes in pressure parameters. An unnoticed failure of a sensor or display on the drill floor, a distraction at the wrong time or an unexpected change in drill-ing routine may prevent a driller from recogniz-ing the onset of a dangerous situation. Using surface indicators, mud loggers may be able to identify hazardous operating conditions.

Mud logging crews provide another set of eyes to monitor drilling systems while correlating mul-tiple drilling parameters. Through examination of cuttings and diligent monitoring of ROP, gas, mud weight, bulk shale density and mud pit vol-ume, mud loggers can frequently detect a transi-tion from normal to potentially dangerous pressure conditions.

As the bit approaches an overpressured for-mation, distinct changes in compaction and porosity may be observed. Formation pressure may approach that of the bottomhole pressure (BHP). When this pressure difference decreases, ROP increases as normally overbalanced bottom-hole conditions start to become underbalanced.10

Consequently, ROP is a key parameter in the detection of overpressured formations.

Shale porosity has long been considered a reliable indicator of abnormal formation pres-sure. Because the weight of overburden causes shale to become more compact with depth, ROP normally decreases with depth. If the drilling rate increases in shale, the driller and mud log-ger might reasonably suspect that porosity is increasing and that the bit may be entering an overpressured zone.

However, numerous factors influence ROP; weight on bit, mud weight, rotary speed, bit size and bit condition also affect drilling rate.11 To account for these mechanical variables, the mud logger computes a drillability exponent, or d-exponent (above). Some mud loggers use a corrected d-exponent (dcs), which factors in

7. Wettability is the preference of a solid surface to be in contact with one liquid rather than another. Intermolecular interactions between the solid surface and the liquid control wetting behavior. For more on wettability: Abdallah W, Buckley JS, Carnegie A, Edwards J, Herold B, Fordham E, Graue A, Habashy T, Seleznev N, Signer C, Hussain H, Montaron B and Ziauddin M: “Fundamentals of Wettability,” Oilfield Review 19, no. 2 (Summer 2007): 44–61.

8. For more on chromatography and gas ratio analysis: Haworth JH, Sellens M and Whittaker A: “Interpretation of Hydrocarbon Shows Using Light (C1–C5) Hydrocarbon Gases from Mud-Log Data,” AAPG Bulletin 69, no. 8 (August 1985): 1305–1310.

9. Bowers GL: “Detecting High Overpressure,” The Leading Edge 21, no. 2 (February 2002): 174–177.

10. Dickey PA: “Pressure Detection: Part 3. Wellsite Methods,” in Morton-Thompson D and Woods AM (eds): Development Geology Reference Manual. Tulsa: The American Association of Petroleum Geologists, AAPG Methods in Exploration Series no. 10 (1992): 79–82.

11. Jorden JR and Shirley OJ: “Application of Drilling Performance Data to Overpressure Detection,” Journalof Petroleum Technology 18, no. 11 (November 1966): 1387–1394.

> Formula for d-exponent. The d-exponentnormalizes the variables that can influence the drilling rate, making the resulting plot more sensitive to pore pressure. (Adapted from Jorden and Shirley, reference 11). The d-exponent varies inversely with the rate of penetration. Variations on the original equation have been developed since its publication in 1966; these variations account for changes in mud weight or bit wear. (Rehm and McClendon, reference 12.)

where: dRNWD

= drillability exponent= penetration rate, ft/h= rotary speed, rpm= weight on bit, lbm= bit diameter, in.

d = log R

60N

12W106D

log

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changes in mud weight or bit wear.12 After calcu-lating the d-exponent to normalize the ROP, the mud logger can view drillability as a function of rock strength and the density of the drilling fluid.

As compaction and rock strength increase with depth, the d-exponent increases when drill-ing through a uniform lithology with no changes in mud overbalance or bit performance. A plot of the d-exponent with depth should roughly mirror the ROP, showing an inverse relation to the drill rate (above). A drilling break would plot as a reversal in the slope of the d-exponent.

The arrival of gas in the mud is another indi-cation of compaction disequilibrium. If formation pressure exceeds the pressure applied by the col-umn of mud, formation fluids will begin to flow into the wellbore. A rapid influx of fluids is called a kick, and marks the beginning of serious well control problems. If formation fluid—especially gas—flows into the wellbore unabated, the effects will soon cascade. The influx will lower the overall mud column weight, reducing the effective pressure against the flowing formation, thereby permitting the formation to flow at a greater rate, leading to a blowout.

Mud loggers must try to interpret overpres-sure clues from a number of parameters. An increase in the temperature of the mud returns may result from faster drilling and increased cav-ings in undercompacted shales. Gas levels may

rise as a result of methane dissolved in the pore water of some overpressured shales. Gas escap-ing from the cuttings is detected at the mud log-ging unit as an increase in total gas. This indicator may be misleading, however, because increases in total gas may result from oil- or gas-bearing formations or organic-rich shales. The increase in porosity that is characteristic of undercom-pacted shales causes lower shale density than is found in normally compacted shales. The mud logger uses a density measuring device in the log-ging unit to determine the density of shale cut-tings at regular intervals.13

An increase in return flow, coupled with rising levels in the mud tanks, indicates a reflux of drill-ing fluids, with greater volumes of mud flowing out of the hole than were pumped into it. Pit level and flow rate sensors monitored at the drill floor and logging unit will trigger an alarm when they detect a mud level change, prompting the drilling crew to shut off the mud pumps, check for flow and prepare to close the blowout preventer.

At the opposite end of the spectrum is a decrease in mud levels, which indicates that the mud pumps are sending more fluid downhole than is being circulated back to the surface. This lost circulation may indicate that the formation has fractured and can have serious repercussions, depending on the rate of fluid loss.14 If the mud

level drops too far, the decrease in the hydrostatic pressure downhole may allow formation fluids to enter the wellbore, causing a kick similar to drill-ing into an overpressured zone.

A kick may also be indicated by an increase or decrease in drillstring weight. A small infu-sion of formation fluid can reduce the buoyancy of the fluid in the annulus; a sensitive weight sensor may indicate this change as an increase in drillstring weight. Given a substantial kick, however, formation fluid may enter the borehole with enough force to push the drillpipe upward, causing a marked decrease in indicated drill-string weight.

The ability to warn drilling crews of impend-ing trouble is heavily dependent on the mud log-ger’s capacity for monitoring changes in drilling parameters. This capability could never have been realized without the extra layer of hyper-vigilance derived from numerous sensors installed at critical points around the rig.

Moving into the 21st CenturyEarly mud loggers grew attuned to the sounds of the drilling rig and could often tell what was hap-pening simply by the clang of the driller’s tongs, the revving of the drawworks engine and the squeal of the driller’s brake. Any variation in the normal routine and rhythms of the rig was cause for investigation. Today, robust, highly sophisti-cated sensors acquire data at several times per second while a context-aware processing system helps the mud logger piece it all together.

Through the years, an impressive array of sen-sors has been developed or adapted for use by advanced mud logging companies. One such com-pany, Geoservices, a Schlumberger company, is an industry leader in mud logging technology.15

Over its 53-year history, Geoservices has devel-oped or acquired a wide variety of sensors to mea-sure and record critical drilling performance and circulation system parameters. Most sensors are intrinsically safe for operating in hazardous con-ditions and must be robustly constructed to ensure reliable operation in harsh drilling envi-ronments and climates. Sensor signals are con-verted from analog to digital as close to the

12. Rehm B and McClendon R: “Measurement of Formation Pressure from Drilling Data,” paper SPE 3601, presented at the SPE Annual Meeting, New Orleans, October 3–6, 1971.Lyons WC (ed): Standard Handbook of Petroleum & Natural Gas Engineering, vol 2. Houston: Gulf Professional Publishing (1996): 1045.

13. Dickey, reference 10. 14. For more on mud loss prevention and remediation:

Cook J, Growcock F, Guo Q, Hodder M and van Oort E: “Stabilizing the Wellbore to Prevent Lost Circulation,” Oilfield Review 23, no. 4 (Winter 2011/2012): 26–35.

15. Geoservices was acquired by Schlumberger in 2010.

> Effects of overpressure on drilling rate and d-exponent. Through a normally pressured shale interval, ROP (red line) generally decreases with depth. The d-exponent (blue line) tends to increase with depth, following a normal compaction trend. Deviations from these trends may be related to undercompaction and may signal that the bit is encroaching on an overpressured zone.

d-exponent Formationpressuregradient

Transition zone

Normallypressured zone

Overpressuredzone

Rate ofpenetration

Dept

h

Increasing drilling rate, d-exponent and formation pressure gradient

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sensor as possible to prevent problems associ-ated with analog signal transmission and a multi-tude of cables running across the rig floor.

Pressure sensors measure a variety of crucial parameters. These sensors can be fitted to key pieces of rig equipment to obtain measurements such as weight on hook, WOB, rotary torque, standpipe pressure, casing pressure and cement unit pressure.

By measuring small movements of the draw-works drum, the drawworks sensor helps the mud logger track the movement of the drillstring and the position of the bit while drilling or tripping (right). This sensor is fitted onto the main shaft of the drawworks. Drawworks sensor outputs help the mud logger determine drilling rate, hook position and bit position.

Noncontact proximity sensors monitor pump strokes and rotary speed. Pump strokes are used to calculate mud flow rates, which are essential for optimization of drilling hydraulics, estimation of lag time and various kick control functions. Monitoring of rotary speed (rpm) is necessary for assessing drilling performance and calculating the d-exponent. The proximity sensor emits an electromagnetic (EM) field and uses EM induc-tion to detect the passage of a metal activator.

Variations in rotary torque often provide the first indications of problems with downhole drill-ing equipment. For a given rotary speed, a grad-ual increase in torque might signal that the drill bit is worn and should be replaced. Mud loggers can also use torque variations to identify forma-tion changes while drilling. A rotary torque sen-sor uses a transducer, which is clamped around the cable feeding the electric motor that powers the rotary table or topdrive. The electric current drawn by the motor is proportional to the rotary torque applied to the drillstring.

Detection of changes in mud pit level is key to the safety of the drilling process. The ultrasonic pit level sensor is positioned over the mud pits and measures fluid level. This sensor emits an ultrasonic wave that reflects off the surface of the liquid (right). This sensor is light, compact, accu-rate and highly reliable, requiring no moving or immersed parts. Precise measurement of the time it takes for the ultrasonic signal to return to the sensor gives the distance between the sensor and the level of liquid in the pit. On floating rigs, multiple sensors may be installed in each pit to account for variations in mud level caused by ocean wave motion.

Density sensors provide rapid, accurate mea-surements of drilling fluid density; they can detect slight changes in mud weight, enabling the mud logger to alert the drilling crew to an influx of lower-density formation fluids into the well. The density sensors are also used to monitor the addition of weighting material or fluid to the mud system. Mud density is measured by two pressure sensors immersed at different depths in the mud pit and calculated from the pressure dif-ferential and depth between the sensors.

Three types of flow sensors are available for continuous monitoring of drilling fluid flow:

the mud in the mud return flowline. When con-nected to the logging system computer, the sen-sor provides a continuous chart of relative height. The mud logger can set alarms for flow height above and below preselected limits.

flowmeter that operates on the principle of magnetic induction. It can be installed on the standpipe to measure flow into the well and on the return flowline to measure flow out of the wellbore. Each sensor unit replaces a short section of the pipe on which it is mounted.

Each sensor consists of a pair of circular electrodes flush with the inside of the pipe. When the sensor is energized, a magnetic field is established at right angles to the pipe axis,

creating a potential difference between the two electrodes that is proportional to the fluid flow rate. The electromagnetic flowmeter operates in water-base muds or in muds in which the continuous phase is conductive. Connection to the logging system computer enables real-time monitoring and permanent recording of the flow parameters as well as automated calculation of differential flow, which is essential for reliable detection of small-volume kicks or losses.

> Pit level sensor. This device (inset) emits a series of ultrasonic pulses to detect changes in fluid level in the mud pit.

Mud pit

> Drawworks sensor. This sensor consists of a disk that rotates in harmony with movements of the cable drum. Movements of the disk are detected by proximity sensors, which send pulses to the main processor in the logging unit.

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-

-

-

-

Advanced Services

--

-

> Coriolis flowmeter. Coriolis meters are installed in the flowline. When there is no flow, current through the pickoffs (top left ), generates sine waves on both inlet and outlet sides of the meter (bottom left and top right ) that are in phase with each other. Fluid moving through the tubes causes them to twist in opposing directions (bottom right ) and also causes the sine waves to go out of phase by a factor Δt,which can be converted to mass flow rate.

Flow inlet

Flow outlet

Sine wave

Magnet

Inlet pickoff

Outlet pickoff

Flow

Inlet side

Outlet side

Δt

Top view

Outlet side

No flow

Inlet side

Outlet side

In phase

Out of phase

Inlet pickoff

Outlet pickoff

Inlet side

No flow

No flow

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up-to-date analysis of drilling mechanics, hole condition and rig performance.

FLAIR advanced mud gas logging—Duringthe past 10 years, advances in mud logging tech-nology have significantly improved the quality and utility of wellsite formation evaluation data. Today, high-resolution gas chromatography and mass spectrometry provide data and interpreta-tive capabilities that enable quantitative evalua-tions of key formation parameters. FLAIR fluid logging and analysis in real time gives early infor-mation pertaining to formation fluid composi-tion. Integration of FLAIR data with data obtained by other formation evaluation tech-niques enables more-accurate assessments of hydrocarbons in the formation.

The FLAIR system analyzes hydrocarbons extracted from the drilling mud under constant thermodynamic conditions. These hydrocarbons are continuously analyzed to obtain a quantitative evaluation of the light gases C1 through C5, while also providing qualitative information on heavier components C6 through C8, including methylcyclo-hexane and the light aromatics benzene and tolu-ene.16 Other nonhydrocarbon components, such as helium, hydrogen, carbon dioxide and hydrogen sulfide can also be monitored.

Specialized mud gas extraction equipment is a key component of the FLAIR system. The FLEX fluid extractor continuously samples mud from the flowline as the mud returns from the well. The FLEX extractor heats mud samples to a con-stant temperature under constant pressure and volume conditions. This method provides a steady air-to-mud ratio inside the extraction chamber, creating an extremely efficient and repeatable process. The capability to heat the sample can be particularly important in deepwa-ter environments, where mud return tempera-tures may range from 10°C to 15°C [50°F to 59°F]. At low temperatures, there is not enough

inherent energy in the system to efficiently liber-ate the heavier gas components from the mud. Traditional mud gas extractors that do not heat the sample may yield inaccurate data because more of the gas is left in the mud during the extraction process.

With the FLEX extraction process, the FLAIR mud gas logging system operates under constant thermodynamic conditions, enabling calibration of the extraction efficiency for the C1 to C5 components. The heavier hydrocarbons, C6 to C8, are not as easily extracted, but their presence can be detected qualitatively. The cali-bration is coupled with a correction that accounts for any gas that might have been recy-cled through the mud system. This is achieved by placing a second FLEX unit in the pump suc-tion line, the point at which the mud is pumped back into the well (above). In this manner, the fraction of hydrocarbons recycled with the mud and pumped back into the well can be quantita-tively measured. Correction for recycled gas is possible because the extraction conditions are the same for both FLEX units.

Extracted hydrocarbons are fed to an advanced gas chromatograph–mass spectrome-ter (GCMS) analyzer, which detects and analyzes gases at the parts-per-million (or micrograms-per-gram) level. The mass spectrometer enables the FLAIR analyzer to detect and differentiate between coeluting peaks created by the various ion currents that characterize components extracted from the mud. This leads to a very short analysis time—85 s for analysis up to C8, includ-ing differentiation of several isomers.

Comparisons between pressure-volume-tem-perature (PVT) analysis of actual downhole fluids with results obtained through FLAIR analysis of C1

to C5 components show a close match. This capa-bility was demonstrated during a collaboration between Shell and Geoservices, in which PVT and FLAIR data from Gulf of Mexico wells were found to be comparable, whereas a traditional mud gas logging system consistently underestimated the concentrations of the C2+ gas species.17

Among other capabilities, the FLAIR service can help geoscientists differentiate between dif-ferent fluid types. As a bit penetrates a reservoir, an increase in gas density measured at the sur-face may indicate a transition from gas cap to oil leg. This increased density is caused by a proportional increase in heavier gases (C3+)compared with the lighter C1 and C2 components. Measurements of heavy components and their relative proportions to the light fraction are used to calculate the hydrocarbon balance (Bh) and wetness (Wh) ratios, which help geoscientists discriminate between oil and gas.18

The FLAIR service was run on an offshore UK appraisal well drilled for Hess Corporation and partners Chevron, DONG Energy and OMV. Two of the operator’s key objectives for the well were to confirm the volume of hydrocarbons in place within the main reservoir and to investigate the presence of hydrocarbons in certain formations above and below this reservoir. After the pilot hole was successfully drilled, a sidetrack was drilled and the well was landed horizontally in the main reservoir target interval, designated as

16. Light hydrocarbons such as C1 to C5 are easily removed by the mud gas extraction process, so their concentrations can be assessed quantitatively. The heavier C6 to C8hydrocarbons are more difficult to remove from the fluid by this process. Their presence can be detected but not easily quantified, so a qualitative measurement is provided.

17. McKinney D, Flannery M, Elshahawi H, Stankiewicz A, Clarke E, Breviere J and Sharma S: “Advanced Mud Gas Logging in Combination with Wireline Formation Testing and Geochemical Fingerprinting for an Improved Understanding of Reservoir Architecture,” paper SPE 109861, presented at the SPE Annual Technical Conference and Exhibition, Anaheim, California, USA, November 11–14, 2007.

18. Bh = [(C1 + C2) / (C3 + iC4 + nC4 + C5)].Wh = [(C2 + C3 + C4 + C5) / (C1 + C2 + C3 + C4 + C5)] × 100.For more on these ratios and their interpretation: Haworth et al, reference 8.

> Arrangement of FLEX extraction units. Using specialized gas extraction units placed in the discharge and suction lines, the FLAIR analysis system compares the two gas streams to correct for any recycled gas that the mud system’s degassing units failed to remove.

Bit

Mud pitShaleshakers

Mudpump

Hose

Kelly

Swivel

Cuttings

Drillstring

FLEX out

Fluid coming from the well

AnalyzerResults

Fluids data interpretationFacies determination

Fluid compositionGas chromatographMass spectrometer

Fluid pumped back into the well

FLEX in

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the S3 horizon. The sidetrack well raised a num-ber of questions pertaining to vertical connectiv-ity, fluid variability, presence of altered and unaltered fluids and geosteering uncertainties within the horizontal section.

Hess investigated potential hydrocarbon zones where gas peaks were recorded above background level. FLAIR analysis of gases from

these zones helped the operator divide them into distinctive fluid facies. These facies were defined by graphing gas ratios on star diagrams—multi-variate plots in polar coordinates—to depict chemical composition and highlight their differ-ences (above). Based on these analyses, the operator identified several distinct fluid facies from different horizons within the well.

The FLAIR service also helped the operator evaluate a formation’s potential for producing oil or gas. The ratio of heavy to light fractions was used to calculate the hydrocarbon balance and wetness ratios. Another potential indicator was the appearance of methylcyclohexane [C7H14], a member of the naphthenic family that usually is present in the liquid phase (next page).

In addition, the operator sought to distin-guish between biodegraded and nonbiodegraded fluids in the reservoir. Biodegradation can affect both the quality of hydrocarbons and their pro-ducibility.19 Among other effects, biodegradation can raise oil viscosity, decrease API gravity and increase asphaltene, sulfur and metals content. In addition, biogenic gas may override oil in a res-ervoir, moving updip to disrupt existing reservoir fluid gradients. This influx modifies the gas/oil ratio, creating compositional variations. Gradient disruptions from charging and recharging may indicate the presence of compartments.

In a study conducted prior to spudding the well, Hess evaluated PVT analyses obtained from offset wells to assess the effects of bio-degradation in the reservoir. These analyses helped to identify markers that could prove useful in recognizing alterations resulting from biodegradation. The study indicated that specific ratios of heptane [nC7], methylcyclo-hexane [C7H14] and toluene [C7H8] were com-mon to the wells in which biodegradation was observed. The C2/C3 ratio was found to be another useful indicator of early-stage biodeg-radation because C3 is one of the first compo-nents that bacteria attack and remove; in a later stage they remove the C2.

FLAIR analysis provided quantitative compo-sition only in the C1 to C5 range and provided qualitative evaluations of the heavier hydrocar-bons. In the Hess well, these results showed low values of the nC7/C7H14 ratio, which is in line with biodegradation effects observed in reservoir flu-ids from offset wells. When extremely low values of toluene were detected—close to the sensitiv-ity of the analyzer—a change in the analysis rou-tine was called for. The C7H8/nC7 ratio was replaced by a C2/C3 ratio, providing a clear dif-ferentiation between biodegraded and unaltered fluids (left).

19. For more on biodegradation in the reservoir: Creek J, Cribbs M, Dong C, Mullins OC, Elshahawi H, Hegeman P, O’Keefe M, Peters K and Zuo JY: “Downhole Fluids Laboratory,” Oilfield Review 21, no. 4 (Winter 2009/2010): 38–54.

> Fluid facies characterization. Variations in fluid composition produce distinctive star plots that can be classified as different fluid facies. This star diagram highlights different levels of heterogeneity. The lightest fluid was encountered in the 3a facies, whereas heaviest fluids were found in facies 3e and 3f.

C1/C2

C1/C3

C1/C4s

C2/C4s

C3/C4s

iC4/nC4

90%

92%

95% to 96%

92% to 93%

90% to 91%

88% to 89%

86% to 87%

85% to 86%

2a:

2b:

3a:

3b:

3c:

3d:

3e:

3f:

Fluid facies, % C1

> Recognizing fluid differences. Hess scientists identified two distinct fluid families, based on the level of fluid alteration. The hydrocarbon ratio analysis confirmed the fluid in an upper reservoir was biodegraded, whereas the fluid in a deeper reservoir in the well was unaltered.

2.500

1.875

1.250

0.625

01.000.750.500.250

C 2/C 3

nC7/C7H14

Biodegraded fluid, pilot hole

Biodegraded fluid, sidetrack well

Nonbiodegraded fluid, sidetrack well

Upper reservoir

Deeper reservoir

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> Fluid facies log. Precise hydrocarbon measurements are obtained through FLAIR gas analyses and are used to distinguish between fluids produced from different reservoir intervals. The resulting fluid facies are numbered sequentially, with a letter indicating subfacies (Track 3 and legend). Measurements of the C1 to C7 components (Tracks 4 to 8) are used to calculate hydrocarbon balance (Bh) and wetness (Wh) ratios (Track 10). In this well, methylcyclohexane [C7H14] was also useful in determining the presence of a liquid phase (Track 9). The R2 and R3 formations (Track 2) are characterized by fluid facies 2, while the other formations contain fluids from facies 3. The targeted S3 reservoir was fairly homogeneous, its fluids being relatively light in the C1 to C5 range, but with a proportionally higher abundance of C7H14, which suggested the presence of a liquid phase. The coal seams S1 and T1 were consistently characterized by high gas levels, with the gas ranging between 95% and 96% C1—but without methylcyclohexane.

C1

ppm0 10kLith

olog

y

Form

atio

n

Flui

d Fa

cies

Gamma Ray

2a

2b

2a

2b

3a

3b

3c

3a

3b

3d

3e

3e

3f

3a

3b

gAPI–50 150

nC5

ppm0 100iC5

ppm0 100

nC4

ppm0 150iC4

ppm0 150

C3

ppm0 500C2

ppm0 500

C7H14

ppm0 250C7H8

ppm0 50

Bh

0 100Wh

0 100

nC7

ppm0 100nC6

ppm0 100

Vertical Depth

ftX,100 X,700

Lithology

2a: 90% 2b: 92% 3a: 95% to 96% 3b: 92% to 93%

Fluid facies, % C1

3c: 90% to 91% 3d: 88% to 89% 3e: 86% to 87% 3f: 85% to 86%

Oil

Oil

Oil

CoaCoaCoal gl gll as

Coall gas

Coall gas

R2

R3

S1

S3

S2

T1

T1

Clay CoalSand

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The FLAIR services also proved useful as an aid to geosteering. While the horizontal sec-tion was being drilled, a decrease in resistivity was observed within the reservoir zone (above). This drop might have signaled an impending roof or base exit from the targeted section, or it might have indicated that the bit was entering the water leg of the reservoir. However, fluid facies analysis performed in real time showed that the fluid remained unchanged, indicating that the wellbore had not exited the oil zone. The resistivity decrease was attributed to increasing irreducible water saturation within the oil zone.

PreVue real-time geopressure service—ThePreVue services provide prespud pressure predic-tion along with wellsite monitoring of pore pres-sure and wellbore stability. Far in advance of rig mobilization, pressure specialists collect data from nearby offset wells and seismic surveys. They analyze well logs, pressure tests and mud reports to create a vertical stress model of each wellbore, then correlate velocity and log response to wellbore pressure anomalies.

After creating a 3D seismic interval velocity model from local and regional seismic data, the pressure specialists calibrate the model using acoustic logs and checkshot surveys from offset wells.20 Next, they conduct a velocity volume analy-sis, computing normal compaction trends (NCTs) and creating pore pressure and wellbore stability models. Leakoff test data from offset wells provide control points for modeling the fracture gradient. These models help the PreVue pressure engineers identify potential zones of abnormal pressure, determine kick tolerances, develop mud weight windows and project where casing points should be set (next page).

Once drilling commences, PreVue wellsite pressure engineers closely monitor ROP and gas readings as well as LWD and MWD logs; they update pressure plots, revise trend lines and watch for variations from the predrill model. Using this information, they can apprise the wellsite com-pany representative of impending problems.

As drilling proceeds, LWD provides important data for interpreting changes in pressure

regimes. The sonic velocity, density and resistiv-ity logs are especially useful for pore pressure and fracture gradient interpretation. Although a number of factors—such as washouts, formation fluid type and anisotropy—can influence log response, in general, these tools respond to changes in rock porosity.

When PreVue engineers observe a porosity increase as depth increases, they immediately notify the driller and company representative. Quick detection of influx and changing gas con-tent is a critical task for the PreVue engineer.

A typical response would be to increase mud weight until the influx is under control. However, this strategy is not without risk, such as uninten-tional fracturing of the formation that can result in sudden mud loss. Increasing the mud weight may create new fractures or open existing frac-tures and force mud into the formation. In per-meable formations, this can lead to fluid loss. Apart from the cost of losing expensive drilling fluid, significant mud loss from the annulus can lead to lower hydrostatic pressure and result in a difficult well control situation.

20. Following normal compaction trends, seismic interval velocities increase with depth. Decreases in velocity with depth may be used to identify potential zones of abnormal formation pressure.

21. Umar L, Azian I, Azree N, Ali ARM, Waguih A, Rojas F, Fey S, Subroto B, Dow B and Garcia G: “Demonstrating the Value of Integrating FPWD Measurements with Managed Pressure Drilling to Safely Drill Narrow Mud Weight Windows in HP/HT Environment,” paper SPE/IADC 156888, presented at the SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Milan, Italy, March 20–21, 2012.

> LWD log. During drilling through the reservoir section, FLAIR gas analysis (Track 3) helped to ease concerns about a decrease in resistivity. FLAIR analysis confirmed that the well had not exited the reservoir zone.

Lithology

Formation

Gam

ma

Ray

gAPI

–50

150

S2 S3

C 1

ppm

015

k

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stiv

ity S

hallo

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stiv

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eep

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.m

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.m

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Ismail Z, Azian Bt A Aziz I, Umar L, Azree B Nordin N, Nesan TP, Rodriguez FR, Zapata FG, Garcia G, Waguih A, Subroto B and Dow B: “Automated Managed Pressure Drilling Allows Identification of New Reserves in a HPHT Exploration Well in SB Field, Offshore Malaysia,” Paper IADC/SPE 151518, presented at the IADC/SPE Drilling Conference and Exhibition, San Diego, California, March 6–8, 2012.

22. For more on look-ahead VSP methods: Borland W, Codazzi D, Hsu K, Rasmus J, Einchcomb C, Hashem M, Hewett V, Jackson M, Meehan R and Tweedy M: “Real-Time Answers to Well Drilling and Design Questions,” Oilfield Review 9, no. 2 (Summer 1997): 2–15.Breton P, Crepin S, Perrin J-C, Esmersoy C, Hawthorn A, Meehan R, Underhill W, Frignet B, Haldorsen J,

Harrold T and Raikes S: “Well-Positioned Seismic Measurements,” Oilfield Review 14, no. 1 (Spring 2002): 32–45.Arroyo JL, Breton P, Dijkerman H, Dingwall S, Guerra R, Hope R, Hornby B, Williams M, Jimenez RR, Lastennet T, Tulett J, Leaney S, Lim TK, Menkiti H, Puech J-C, Tcherkashnev S, Ter Burg T and Verliac M: “Superior Seismic Data from the Borehole,” Oilfield Review 15, no. 1 (Spring 2003): 2–23.Blackburn J, Daniels H, Dingwall S, Hampden-Smith G, Leaney S, Le Calvez J, Nutt L, Menkiti H, Sanchez A and Schinelli M: “Borehole Seismic Surveys: Beyond the Vertical Profile,” Oilfield Review 19, no. 3 (Autumn 2007): 20–35.

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Turning on mud pumps raises the pressure of the mud, and this phenomenon can be regarded as a virtual increase in the mud density. Management of this gap between the effective static density (pumps off) and effective circulat-ing density (pumps on) and its relationship to the formation pressure and rock strength is a key to successful drilling. The objective of the PreVue service is to balance the mud density—both static and circulating—between the formation pressure and the rock strength.

In 2011, Petronas Carigali Sdn Bhd drilled the high-pressure, high-temperature SBD-2 well, in the Malay basin offshore Malaysia. Based on pre-vious experience in the area, drillers expected that they would have to contend with a narrow mud weight window constrained by pore pressure and fracture pressure.21 An earlier offset well, the SBD-1, experienced pressure problems accompa-nied by heavy mud losses, which prevented the well from reaching its objective.

Using logs from the SBD-1 well, Petronas geologists were able to identify the onset of abnormal pore pressure. Before spudding the SBD-2 well, Petronas wanted to determine the depth of the transition from a lower pressure gra-dient to a higher pressure gradient. PreVue pres-sure specialists analyzed seismic data to ascertain the top and base of this pressure ramp. A 3D seismic volume of the area was analyzed and the velocity data from offset wells were extracted and compared with wireline and LWD data. These data were used to compute overburden gradients and normal compaction trends in offset wells, which were then integrated into a velocity model across the prospect location. Velocity values from the prospect location and other sites were ana-lyzed to determine the depth at onset of abnor-mal pressure and the magnitude of pressure. The difference between pore pressure and kick toler-ance left the driller with an extremely narrow equivalent mud weight window of just 1 to 1.5 lbm/galUS [0.12 to 0.18 g/cm3].

During subsequent planning sessions, the operator elected to obtain borehole vertical seis-mic profile (VSP) data after each casing run. This intermediate VSP data from the wellbore could be obtained in the relatively safe environment of the SBD-2 cased hole. Moreover, it would allow the project team to make time-depth conversions in their original model, which relied on surface seis-mic data. The VSP data would also allow the opera-tor to identify any changes in the model and could be used as a tool for gauging the pore pressure profile ahead of the bit. This valuable look-ahead information would guide the drilling team’s strat-egy for drilling the well to its target.22

Drilling progress toward the pore pressure ramp was tracked by integrating LWD resistivity logs and d-exponent plots, along with emphasis on gas measurements and trends. Prior to drilling into the pressure transition zone, the operator ran a zero-offset VSP to update previous esti-mates of pore pressure. Based on this VSP data, high- and low-pressure cases were developed with the same normal compaction trend line used to generate pore pressure curves from seis-

mic velocity. Both cases indicated that the range for increase in pore pressure gradient was around 1 lbm/galUS. This gave the drilling team a clearer picture of what lay ahead and reinforced confi-dence in the computed model.

The interval between intermediate casing and TD in the SBD-2 well was drilled in two sections. The first of these was drilled using a 10½-in. bit and a 12¼-in. underreamer. After 95/8-in. casing was set, the second section was

> Predrill analysis of an offset well log. Overpressured zones or intervals of inhibited compaction are characterized by increased porosity, which can be identified through log responses from nearby offset wells. Pore pressure indicators (red dots, Track 1) are based on average shale resistivity (black) and help to establish a normal pore compaction trend line (green). Deviations from the normal compaction trend may indicate abnormal pressure. PreVue pore pressure studies evaluate seismic data and logs, leakoff tests and mud reports from offset wells to predict the onset of abnormal pressure, its magnitude and the range of mud weights that can be used to control it. In this example, deviations from the normal compaction trend start at about 8,800 ft. The equivalent mud weight curves (Track 2)display a corresponding pressure behavior. Kick tolerance (light blue) is dictated by the weakest formation exposed in open hole. The fracture gradient (dark blue), pore pressure (green), overburden gradient (red) and normal hydrostatic gradient (black) have been calculated to establish an allowable mud weight window (hatched) bounded by the kick tolerance and pore pressure curves.

Resistivity

ohm.m0.2 20

1,000

Depth,ft

2,000

3,000

4,000

5,000

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7,000

8,000

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10,000Casing Leakoff

test

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Casing

Casing

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12,000

Pore Pressure Indicator

ohm.m0.2 20

Normal Compaction Trend

ohm.m0.2 20

Normal Hydrostatic Gradient

ppg0 23

Overburden Gradient

ppg0 23

Pore Pressure

ppg0 23

Fracture Gradient

ppg0 23

Kick Tolerance

ppg0 23

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drilled to TD using an 8½-in. bit and a 9½-in. under-reamer. The underreamers increased the annular volume, which reduced circulating pressures in the annulus and lowered the ECD, thus counteracting the effects of the heavy muds. Throughout this inter-val, the mud weight was maintained close to the

estimated pore pressure profile and ECDs were maintained close to the fracture gradient. Any pres-sure increase in which downhole ECD exceeded kick tolerance resulted in seepage losses and thus gave the drilling team a reliable indicator for main-taining downhole pressures.

PreVue engineers also used gas measure-ments to obtain accurate indications of mud bal-ance. As the well neared TD, gas peaks were observed following pump stoppages. PreVue engi-neers analyzed these gas increases and found that, instead of a troublesome influx resulting from low mud weight, these gas peaks were caused by well breathing.

Well breathing may be observed in some wells following brief stoppages of the mud pump. When mud weight approaches the equivalent of the fracture gradient, small fractures can develop in weak formations or along the interface between rock layers. While mud pumps are turned on, the fractures may open, allowing drilling fluid to enter. Light gases diffuse from the formation into the drilling fluid. When the pumps are turned off briefly, such as during a pipe connection, the fractures slowly close, forcing the mud with gas to flow back into the hole. When the drilling fluid circulates to the surface, it registers as an increase in total gas. However, on the chromato-graph, it is characterized by an increase in C1 and C2 gases, with little change in C3, C4 and C5 gases.

To maintain mud weight within the narrow pressure window, managed pressure drilling (MPD) techniques were used for early kick detec-tion, maintaining constant bottomhole pressure control and conducting dynamic flow checks and dynamic formation integrity tests (FITs).23 When engineers compared the VSP look-ahead pore pressure curves with actual pressure readings from an MDT modular formation dynamics tester and StethoScope formation pressure-while-drill-ing tool, they found that the readings closely matched each other (left). After TD was reached, the wellbore was displaced with kill mud and the well was completed successfully.

Thema drilling operations support and anal-ysis service—The Thema service processes real-time, high-frequency data streams from a number of sensors around the rig to provide up-to-date analysis of hole condition, drilling efficiency, well pressure balance and rig performance. This infor-mation is displayed on customizable screens installed at the logging unit and the company rep-resentative’s workspace; it can also be accessed remotely from the operator’s offices.

In hole condition mode, Thema engineers analyze wellbore stability and hole cleaning effi-ciency in real time. The drillstring weight is recorded while it is static, rotating or reciprocat-ing. This program can also process input from cuttings flowmeters. Data are presented in depth or time, enabling the user to rapidly establish a sequence and correlation between events. These

> Final composite log. Look-ahead estimates of pore pressure from VSP analyses are confirmed by actual pressure readings from MDT and StethoScope tools. Mud weight was kept as low as possible to keep the ECD from exceeding the fracture strength of the rock. In spite of this effort, some mud losses were experienced. The plots show that mud pressures (red) were maintained close to the estimated pore pressures.

Depth,m

Overburden Gradient Averageppg8 23

Interval Velocity Fracture Gradient, High-Pressure Caseppg8 23

Fracture Gradient from Deep Resistivityppg8 23

Interval Velocity Fracture Gradient, Low-Pressure Caseppg8 23

Equivalent Circulating Densityppg8 23

Mud Weight Inppg8 23

Interval Velocity Pore Pressure Gradient, High-Pressure Caseppg8 23

Pore Pressure Gradient from Deep Resistivityppg8 23

Interval Velocity Pore Pressure Gradient, Low-Pressure Caseppg8 23

Normal Hydrostatic Gradientppg8 23

X,100

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Mud gain5 bbl

13 3/8-in. shoe

11 3/4-in. liner

9 5/8-in. shoe

Casing depth Kick or flow MDT or StethoScope pressures Leakoff test Lost circulation zones

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data are analyzed to derive industry-standard val-ues for torque, ECD, pickup, slack-off and free-rotating weights.

The drilling efficiency mode evaluates vari-ous drilling parameters to assess bit behavior and wear. Surface sensors monitor the fre-quency and magnitude of axial vibration caused by bit bouncing and stick-slip torsional vibra-tions. These inputs are used to anticipate poten-tial problems such as bit balling, drillstring vibration and bit wear to optimize drilling parameters. The drilling efficiency mode may help improve ROP and increase the life of down-hole and surface equipment.

The Thema service helped one operator in the Middle East enhance core recovery in a forma-tion susceptible to breakage. Breaks in core cause two main problems. First, the operator has difficulty in recovering representative samples of the formation. Second, broken core causes gaps in the core recovery footage count, which can severely degrade the quality of interpretation of any core that is eventually recovered.

Analysis of drilling sensor data from the first coring run revealed the core was being sub-jected to severe torsional vibrations inside the core barrel, resulting in a poor-quality core with many breaks and fractures. During a subsequent coring operation, the Thema service was used to manage drilling parameters and minimize drill-string vibration. The operator obtained a clean, unbroken core, thus validating the Thema anal-ysis and recommendations.

To monitor rig performance, the Thema service automatically tracks and displays a specific combination of parameters, such as connection time or net drilling time per stand. The duration of each activity is logged, enabling assessment of the rig performance during various operations such as drilling, slid-ing, tripping and circulating. The wellsite data specialists work with Thema engineers at the operator’s office to provide timely updates to rig site and office project members.

The Thema service was recently called on to determine the cause of poor drilling rates in wells off the coast of Brazil. During a three-year drilling campaign, the operator utilized Geoservices mud logging and Thema services on several wells drilled from semisubmersible rigs in the Campos basin. While most of these wells were drilled and completed on schedule, a few were taking longer than expected to reach TD, owing to dramatic decreases in ROP.

In contrast to neighboring wells with ROPs averaging 40 m/h [130 ft/h], some wells attained only 16 m/h [52 ft/h]—a 60% reduction. An eval-uation of drilling performance indicated that ROP was hampered by vibration. However, the driller was unable to identify the exact cause of the problem.

On one well, the Thema service was used to record responses of various drilling perfor-mance sensors located around the rig. The Thema system acquires data at up to 50 Hz, enabling rapid correlation of sensor responses to various drilling parameters. Among the inputs were data from sensors to detect motion on the riser tensioner, heave compensator and topdrive block.

Analysis of sensor data helped Geoservices personnel track the problem to its root cause: Drilling energy was being dissipated through shock and torsional resistance as a result of heave motion (above). As is typical of semisub-mersibles, the rig used heave compensators to reduce vertical drillstring movement caused by the rise and fall of ocean waves.

By fine-tuning the damping motion of the heave compensator, the drilling contractor was able to mitigate the problem and boost ROP while reducing stress on the drillstring. The ROP increased from 16 m/h to 45 m/h [148 ft/h]—exceeding the 40-m/h average of neighboring wells by more than 10%. These results prompted the operator to implement the same monitoring and mitigation practices on the five rigs the com-pany employed in the area. In light of these results, the operator plans to use the Thema ser-vice in future wells.

The scope of services offered by mud logging companies continues to expand as new sensors and analytical tools are developed. In response, the mud logger has taken on an important role in providing the operator and drilling crew with information that is crucial to the success of the well and to the safety of the rig. In addition to formation evaluation experts, the mud logging unit must now accommodate specialists who are responsible for drilling efficiency and well safety. By linking a wide array of surface sensors to rapid analytical capabilities and operational expertise, the mud logging unit is fast becoming the nerve center of the drilling rig. —MV

> Heave versus compensation. Using Thema service data, Geoservices personnel tracked a drillstring vibration problem on a well in the Campos basin off the coast of Brazil. A comparison between the magnitude of heave and compensation (left ) showed deficiency in heave damping, which was subsequently corrected (right).

–0.8

–0.6

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0

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Time, min:s

01:00 01:04 01:08 01:12

Heig

ht,m

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23. For more on managed pressure drilling: Elliott D, Montilva J, Francis P, Reitsma D, Shelton J and Roes V: “Managed Pressure Drilling Erases the Lines,” Oilfield Review 23, no. 1 (Spring 2011): 14–23.

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Offshore Permanent Well Abandonment

Worldwide, government and regulatory officials are informing the offshore oil and gas

industry that unproductive wells must be immediately sealed to permanently remove

these potential environmental threats. Service companies are developing tools and

methods to limit the economic impact of fulfilling these obligations.

Lucas W. AbshireBroussard, Louisiana, USA

Praful DesaiHouston, Texas, USA

Dan MuellerConocoPhillipsHouston, Texas

William B. PaulsenATP Oil & Gas CorporationHouston, Texas

Robert D. B. RobertsonTorodd SolheimStavanger, Norway

Oilfield Review Spring 2012: 24, no. 1. Copyright © 2012 Schlumberger.For help in preparation of this article, thanks to Hani Ibrahim and Eric Wilshusen, Houston.2M, Hydra-Stroke and Shortcut are marks of Schlumberger.

1. Smith I, Olstad E and Segura R: “Heightened Regulations Create Demand for Well Abandonment Services,” Offshore 71, no. 10 (October 2011): 70–73.

2. King GE: “Plug and Abandonment—Producing Well,” George E. King Engineering, Inc. (March 14, 2009), http://gekengineering.com/Downloads/Free_Downloads/Plug-and_Abandonment_Basics.pdf (accessed March 14, 2012).

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Subsea fields are reaching the end of their pro-ductive lives in the North Sea and the Gulf of Mexico, where the offshore oil and gas industry first moved into waters deep enough to require floating drilling and production units. As a conse-quence, and spurred by environmental concerns and official regulatory agencies, operators are poised to plug and abandon (P&A) a substantial number of wells in both those regions in the next few years.

This proliferation of present and future P&A needs is turning what has been a niche market into a multibillion dollar industry for offshore service companies. In the UK sector of the North Sea alone, it is estimated that more than 500 structures with about 3,000 wells are slated for permanent abandonment in the near future. By some estimates, as many as 12,000 wells are no longer producing in the Gulf of Mexico, qualifying them all as P&A can-didates.1 In the Norwegian sector of the North Sea, more than 350 platforms and more than 3,700 wells eventually must be permanently abandoned. Additionally there are more than 200 structures slated for decommissioning off-shore the Netherlands, Denmark, Ireland, Spain and Germany.

The basics of P&A operations vary little, whether the well is on land or offshore. Operators remove the completion hardware, set plugs and squeeze cement into the annuli at specified depths across producing and water-bearing zones to act as permanent barriers to pressure from above and below in addition to protecting the for-mation against which the cement is set (aboveright). Operators remove the wellhead last. Today, regulators are increasingly demanding that operators remove sections of casing so that a cement plug may be set that is continuous across the entire borehole in a configuration often referred to as rock to rock.

Similarly, both onshore and offshore, the decision to P&A a well is invariably based on eco-nomics. Once the production rate has fallen below the economic limit—that point at which production levels deliver income that is less than or equal to operating expenses—it becomes pru-dent to abandon the well. In some instances, although considerable reserves may remain, the cost to repair a well problem is more than the projected income from potential production from a reworked well. On the other hand, in some off-shore wells, engineers are able to permanently plug an offshore completion below a certain depth, remove one or more intermediate casing strings and set a whipstock. The operator is then

able to reenter the original mother bore and drill a sidetrack well off the whipstock to an untapped section of the reservoir.

The steps required of operators to qualify their offshore wells as permanently abandoned vary widely with regulatory jurisdiction. For example, an offshore platform well in Norway is far more costly to abandon than one in the Middle East because meeting the standard of permanency set by regulators of the former requires more expensive operations than do those of the latter.

As a consequence of the high cost of offshore operations, prudent operators consider the cost of permanently abandoning a well and its sup-porting infrastructure during the field planning stages. Abandoning subsea wells can cost millions of dollars per well, particularly when the task must be performed from a deepwater drilling ves-sel. Operators planning to permanently abandon a well are therefore driven by the sometimes com-peting interests of safety and economics.

This article discusses the final steps of aban-donment operations unique to offshore wells and describes the tools being developed to meet the needs of permanency while providing cost effi-ciencies. Because official governing bodies of the North Sea and Gulf of Mexico recently have made decommissioning a priority and because the two represent the largest mature offshore arenas in the world, this article focuses on operations in those areas. Similarly, legislators governing oper-ations in the North Sea and Gulf of Mexico are themselves more experienced in this work than are their counterparts elsewhere around the world. Consequently, these official bodies are likely to both drive and incorporate new technol-ogy in future regulations that are realistic in terms of the operators’ bottom lines while ensur-ing that taxpayers not be burdened with repair costs for wells that, decades later, turn out not to be truly permanently abandoned.

Attacking the High Cost of P&AThe inability to recover 100% of all the oil and gas trapped in formation rocks is due in part to eco-nomics and in part to constraints imposed by technology and geology. In all cases, some hydro-carbon will be left behind because the cost to bring it to surface is higher than the price it will bring at market; other pockets of oil and gas remaining in the reservoir will never be recov-ered because even technologies such as water injection, which are used to force hydrocarbons to the wellbore after natural drives are depleted, eventually become ineffective or uneconomic.

When operators abandon a well, they are obliged to leave it in a condition that protects both the downhole and surface environment in perpetuity. In all parts of the world, sometimes numerous regulatory bodies of overlapping responsibilities define procedures and qualifica-tions of a permanent well abandonment. In the Gulf of Mexico, for example, depending on dis-tance from shore and water depth, operators may have to meet requirements set by agencies from both federal and state jurisdictions.

Despite disparities between regulators around the world, the intent of all P&A operations is to achieve the following:

-ter zones

well

mandated level below the surface.2

> Basic plug. A requirement for a permanent well barrier is that it must include all annuli, extending to the full cross section of the well and seal both vertically and horizontally. In this illustration, the cement plug is sealing vertically inside the casing and sealing both horizontally and vertically in the casing-formation annulus above the casing shoe.

Annulus

FormationCement

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Casing shoe

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44 Oilfield Review

P&A operations offer permanent solutions to wells that are no longer profitable or that have developed problems that cannot be economically repaired. However, offshore, it is a common prac-tice for operators to permanently abandon the zones within a well before completing and pro-ducing others. Additionally, offshore develop-ment plans often call for lower sections of depleted wells to be permanently abandoned to free a slot in subsea templates and platforms through which another well may be drilled to an untapped section of the reservoir. This practice is termed slot recovery.

To permanently abandon a well, operators must leave behind a wellbore that is configured according to local regulations for plug type, length and depth (left). Operators remain responsible for an abandoned well long after the wellbore has been cemented and the surface equipment removed. In the event a seal fails and well fluids leak to the surface or crossflow is detected, the operator is liable for the problem.

To meet P&A obligations, the oil and gas industry has developed methods and materials designed to provide long-term zonal isolation even when downhole conditions change over time.3 In efforts aimed at reducing the expense of offshore abandonment operations, operators and regulators continue to change the way traditional P&As are performed, and service companies strive to stay abreast of these changes and to develop tools and techniques to facilitate them. Minimizing these costs, without sacrificing the integrity of the abandoned well, is critical to operators who must make these significant investments with no hope of financial return.

Depending on water depth, offshore well abandonment can be staged from a fixed plat-form such as jackup rig, from a large floating platform such as a semisubmersible drilling rig or from a support vessel with dynamic position-ing. In UK waters, abandonment from a fixed platform is the least expensive—about US$ 1 to 2 million per well. By contrast, abandonment oper-ations using a semisubmersible or dynamically positioned floating drilling unit typically cost operators US$ 5 to 6 million per well, and the cost of support vessel–based abandonments falls between those two extremes (next page, left).4

In Norway, the cost of permanent well abandon-ment is significantly higher to meet both the operators’ self-imposed standards and regula-tors’ requirements.

> US P&A regulations guide. Depending on a well’s location, depth, condition and other parameters, operators are obliged to perform and document specific steps that are outlined by the regulating body for the area. This table shows samples of the procedures to be performed so that a well in the Gulf of Mexico is deemed permanently plugged. The procedure called for depends primarily on the well configuration prior to plugging and is set by the US Bureau of Safety and Environmental Enforcement. [Adapted from the Electronic Code of Federal Regulations: “Permanent Well Plugging Requirements,” http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?c=ecfr&sid=06d320a6f4723641d7d1b83be409c10d&rgn=div8&view=text&node=30:2.0.1.2.2.17.93.11&idno=30 (accessed March 28, 2012).]

Set cement plug(s) from at least 100 ft [30 m] below the bottom to 100 ft above the top of oil, gas and freshwater zones to isolate fluids in the strata.

Zones in open hole

Situation Procedure

Open hole below casing

Perforated zone that is currently open and not previously squeezed or isolated

Casing stub with the stub endwithin the casing

Casing stub with the stub end below the casing

Annular space that communicates with open hole andextends to the mudline

Subsea well with unsealed annulus

Well with casing

Fluid left in the hole

Permafrost areas

Perform one of the following:Set, by the displacement method, a cement plug at least 100 ft above and below the deepest casing shoe. Set a cement retainer with effective backpressure control 50 ft [15 m] to100 ft above the casing shoe, and a cement plug that extends at least 100 ftbelow the casing shoe and at least 50 ft above the retainer.Set a bridge plug 50 to 100 ft above the shoe with 50 ft of cementon top of the bridge plug for expected or known lost circulation conditions.

Perform one of the following: Set a cement plug at least 100 ft above and below the stub end.Set a cement retainer or bridge plug at least 50 to 100 ft above the stubend with at least 50 ft of cement on top of the retainer or bridge plug.Set a cement plug at least 200 ft long with the bottom of the plug no more than 100 ft above the stub end.

Set a plug as specified in the openhole sections, above, as applicable.

Set a cement plug at least 200 ft long in the annular space; for a well completed above the ocean surface, pressure test each casing annulus to verify isolation.

Use a cutter to sever the casing; set a stub plug as specified in casing stub sections, above.

Set a cement surface plug at least 150 ft [45 m] long in the smallest casing thatextends to the mudline with the top of the plug no more than 150 ft below the mudline.

Maintain fluid in the intervals between the plugs that is dense enough to exert a hydrostatic pressure that is greater than the formation pressures in the intervals.

Leave, in the hole, fluid that has a freezing point below the temperature of the permafrost and a treatment to inhibit corrosion and use cement plugsdesigned to set before freezing and that have a low heat of hydration.

Perform one of the following:Use a method to squeeze cement to all perforations.Set, by the displacement method, a cement plug at least 100 ftabove to 100 ft below the perforated interval, or down to a casing plug, whichever is less.If the perforated zones are isolated from the hole below, use anyof the five plugging methods specified below instead of the two specified in

this section, immediately above. ■ Set a cement retainer with effective backpressure control 50 to 100 ft

above the top of the perforated interval and a cement plug that extends atleast 100 ft below the bottom of the perforated interval with at least 50 ftof cement above the retainer.

■ Set a bridge plug 50 to 100 ft above the top of the perforated intervalwith at least 50 ft of cement on top of the bridge plug.

■ Set, by the displacement method, a cement plug at least 200 ft [60 m] in length, with the bottom of the plug no more than 100 ft above the perforated interval.

■ Set a through-tubing basket plug no more than 100 ft above the perforated interval with at least 50 ft of cement on top of the basket plug.

■ Set a tubing plug no more than 100 ft above the perforated interval topped with a sufficient volume of cement so that it extends at least 100 ftabove the uppermost packer in the wellbore with at least 300 ft [90 m] of

cement in the casing annulus immediately above the packer.

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Spring 2012 45

As the upstream oil and gas industry moved into deeper water, it sought ways to temper steeply rising capital and operating expendi-tures. In deep water, where numerous satellite jackets are impractical, one approach is to com-plete subsea wells with wellheads that are on the seabed and connected to a field platform via flowlines strung along the seafloor. Subsea well-head valves and instruments are monitored and manipulated through bundled hydraulic and electric lines called umbilicals (above right).

3. For more on P&A procedures: Barclay I, Pellenbarg J, Tettero F, Pfeiffer J, Slater H, Staal T, Stiles D, Tilling G and Whitney C: “The Beginning of the End: A Review of Abandonment and Decommissioning Practices,” Oilfield Review 13, no. 4 (Winter 2001/2002): 28–41. For more on long-term zonal isolation: Bellabarba M, Bulte-Loyer H, Froelich B, Le Roy-Delage S, van Kuijk R, Zeroug S, Guillot D, Moroni N, Pastor S and Zanchi A:

> Subsea lubricator. In the 1970s, Schlumberger introduced a subsea intervention lubricator that could be landed on a subsea tree and connected via a rigid riser to a dynamically positioned vessel. This allowed operators to perform light slickline, wireline or coiled tubing well interventions without deploying a costly offshore floating drilling unit. The capability to cost effectively reenter subsea wells greatly reduced well maintenance costs and allowed engineers to perform necessary work more frequently, thus extending well life.

CSO Seawell

Rigid riser

Subseainterventionlubricator

Subsea tree

> Subsea completions. To minimize demands on surface support facilities in deep water, operators place subsea wellheads (yellow) on the ocean floor. Bundled flowlines and umbilicals (green) carry production and electric and hydraulic control and monitoring signals between wellheads; fluids and signals travel to the production facility at the surface via risers (red). This system allows engineers to deploy smaller and fewer high-end deepwater support vessels for service in large areal fields.

“Ensuring Zonal Isolation Beyond the Life of the Well,” Oilfield Review 20, no. 1 (Spring 2008): 18–31.

4. Liversidge D, Taoutaou S and Agarwal S: “Permanent Plug and Abandonment Solution for the North Sea,” paper SPE 100771, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Adelaide, South Australia, Australia, September 11–13, 2006.

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Most subsea wells are completed with three or more casing strings of progressively smaller diameters and are usually bonded to each other by a cement sheath in the annulus. Typically, dur-ing the abandonment process, three or more drillpipe trips are required to remove each casing string. The first trip is made to retrieve the casing and hanger seals from the wellhead. The casing is then cut during a second trip, and a third trip is required to pull the casing and casing hanger from the well. Following recovery of these inter-mediate strings, the conductor casing is cut and the wellhead retrieved.

Rig time for these operations is considerable; in deep water, each trip commonly takes 8 to 10 hours.5 To reduce time and thus cost of cutting and pulling strings of intermediate casing from a subsea well, SERVCO has developed the Shortcut deepwater plug and abandonment system (left).It is designed to latch and retrieve the seal assembly and then sever a single string of casing, engage it for removal and retrieve the wellhead seal assembly in a single operation.

The Shortcut system is run in the hole on drillpipe and has a mechanical spear fishing tool that can be engaged near the point at which the cut is being made. Once the casing is cut, the fishing tool can be released and moved to the top of the severed casing string and reset. The recov-ered casing is hung in the rotary table while the spear is released and the workstring is racked back out of the way, which allows the casing to be handled safely and efficiently as it is being removed from the wellbore. A retrieval tool may be included in the system to enable removal of the wellhead seal assembly. A key component of the system is the SERVCO hydraulic cutting tool, whose knives can extend the maximum sweep diameter created by the often eccentric configu-ration of cemented pipe (next page, top).

To cut and pull a string of casing, engineers first engage the wellhead seal assembly with the retrieval tool and strip the seal assembly up into the riser. The casing cutter is then posi-tioned at the appropriate depth and the spear is engaged and used to place the string in ten-sion. Pumps are turned on and drillstring rpm rates are slowly increased to turn the mud motor rotor, which rotates the cutter.

The driller monitors the differential pressure across the positive displacement motor; when data indicate a fluid pressure drop, the cut is complete. The driller then slacks off and manipu-lates the drillpipe to disengage the spear, which is pulled to just below the wellhead where it is

> Cut and pull. The Shortcut deepwater P&A system uses a hydraulic cutter to sever the casing and a spear to latch it. The collets of the Shortcut spear are extended to engage the casing near the cut point until the cut is complete. The spear is then released and pulled to the top of the casing section where it is reengaged. This ability to change the position of the spear allows it and the drillstring it is run on to be racked out of the way while the casing is being pulled. The cutter arms are rotated by fluid pumped through the mud motor. The bumper sub attachment allows the rig operator to jar the casing if necessary.

Hydra-Strokebumper sub

Mud motor

Hydraulic pipe cutter

Bumper sub

Shortcut spear

Cutter arms

Collets

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Spring 2012 47

reengaged. The casing is then pulled from the well, and the seal assembly and retrieval tool are laid out on the surface. The driller continues to pull out of the hole until the casing hanger is landed on the rotary and the spear can be disen-gaged and racked back in the derrick so that cas-ing lay down may proceed.

A similar tool, the SERVCO 2M cut-and-pull system, is also a single-trip system primarily used to cut and retrieve 20- and 30-in. casings and sub-sea wellheads. This tool is able to pull the casing alone or the casing and wellhead together, and because it is designed to latch the wellhead and casing in noncritical areas and thus avoid seal bores in casing hangers, the recovered parts need not be machined before reuse.

Because the cutting assembly may be run on a single stand of 8-in. drill collars, the 2M system reduces workstring handling time and eliminates the need for a marine swivel typically required for these operations (below right). The cut-and-pull system consists of a standard or rotating spear, hydraulic pipe cutter and nonrotating sta-bilizers placed above and below the pipe cutter.

Slot RecoveryMost P&A operations are an unavoidable cost of doing business and offer no return on the capital invested in them. However, slot recovery opera-tions are a different story because such opera-tions provide access to untapped reserves that will extend the life of the field. Not only does this operation result in more revenue from produc-tion, but as the field ages it helps extend the life of the platform and other infrastructure that rep-resent very large preproduction capital expendi-tures. Because slot recovery is performed in maturing fields, operators tend to be concerned with cost cutting when accessing these second-ary targets. One key to controlling the costs of these new wells is reining in the P&A portion of slot recovery costs by reducing the number of trips required to cut and retrieve the multiple casing strings that prevent installation of a new well.

5. Going WS and Haughton D: “Using Multi-Function Fishing Tool Strings to Improve Efficiency and Economics of Deepwater Plug and Abandonment Operations,” paper SPE/IADC 67747, presented at the SPE/IADC Drilling Conference, Amsterdam, February 27–March 1, 2001.

> Eccentric casing. Cutting two strings of casing can be complicated when the distance from center to casing wall is extended by eccentricity. In this case, a 7-in. casing is inside a 95/8-in. casing string. When the two are perfectly centered (left), the largest diameter the cutting knife must reach is 10.62 in. In extreme cases, the 7-in. casing is tightly pressed against the inner wall of the 95/8-in. casing (right), thus the knife must sweep a 13.68-in. diameter.

3.06 in.1.53 in. 3.78 in. 5.31 in.

10.62-in. sweep necessary

Worst Case

13.68-in. sweep necessary

3.78 in. 6.84 in.

Best Case

> Rigless well abandonment package. The SERVCO power swivel stand consists of hydraulic jacks with 445-kN [100,000-lbf] pulling capacity power swivel, control panel, power tongs and a mast with which to swing the tongs in and out of position. The stand is positioned over the well; once a string of casing is pulled to the surface by a spear fishing tool, it is connected to the power swivel head. The hydraulic jacks lift it out of the well to the next connection; the power tongs break the connection. The stand allows the crew to rack back the spear and drillstring. This system replaces the alternative method using a spear and drillstring to retrieve each stand of casing.

Ultrahigh-torquepower tongs

Powerswivel head

Controlpanel

Powerswivel stand

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Typically, in addition to the conductor, or sur-face, casing string, offshore wells include inter-mediate and production casing strings, production tubing and a production packer (above). The section of the well below the packer is referred to as the lower completion. Slot recov-ery consists of plugging and abandoning the lower completion—which often includes working

through collapsed tubing—and sidetracking from a kickoff point some distance above this new plug, which must be across all annuli and sealed against the formation. A simplified version of the procedure requires the following:

more cement plugs—in the production tubing below the packer

completion inside the production casing

the production casing to below the kickoff point

casing.Conventional systems for this work involve

multiple trips to run cutting and fishing tools and retrieve casing sections. Usually, the well has been in place for many years, so cutting and pull-ing the casing may be difficult because of a firm cement bond, barite settling from drilling fluid in the annulus or a combination of the two.6 Pulling units may be unable to overcome the strong bonds created by cement or barite. As a result, the cut-ting and pulling operation may require several trips and cuts for each string before an interval is found that is free of binding cement or barite.

To address this possible eventuality, a team of engineers reviewed the conventional tools used for these jobs. They found that the standard kit could make only a limited number of cuts down-hole. Based on these findings, the team designed a pipe cutting tool with three sets of tungsten-carbide cutters, which can be activated indi-vidually and remotely. This capability allows operators at least three attempts to cut the cas-ing without having to pull out of the hole for fresh knives. An indicator in the tool confirms to observers on the surface that the cut is com-pleted. A hydraulic spear and packer assembly being developed for future inclusion in the BHA will allow engineers to pull and circulate fluid behind the production casing.7

The product of this design effort is the multi-cycle pipe cutter (MCPC) system (next page, top).It incorporates an indexing piston assembly that moves in response to applied drilling fluid pres-sure and is used to engage and guide the tool’s axial and rotational movements. A combination of an indexing mechanism and flow fluctuations allows the engineer to selectively activate one of three sets of cutters and the hydraulic spear and packer assembly. Those cutters not engaged are securely collapsed within the body of the tool.

A pressure drop indicator at the top end of the tool consists of a stationary stinger within the

piston bore. Initially the stinger remains in the piston bore, creating a flow restriction and a higher activation pressure. When the cut is com-plete, the piston moves downward, resulting in removal of the flow restriction and a drop in pres-sure of 1.4 to 2.1 MPa (200 to 300 psi) that is dis-played at the surface.

Developers used proprietary tungsten carbide inserts positioned on the cutters to provide the optimal cutting angle. They also designed the tool for an operational sequence—complete the cut and activate the spear to grip and pull the casing segment—that was repeatable in a single down-hole trip. To do this, engineers developed a hydraulic spear compatible with the MCPC tool that is activated at a higher flow rate than that required to activate the MCPC. This ensures that only the spear is activated and the correct cut-pull sequence will take place.

The tool was field tested on a slot recovery operation on the Norway Continental Shelf. Rather than test the viability of the single trip method, the operator chose to cut and pull 95/8-in.casing in two trips. Initial cuts were made at 861 m [2,825 ft] and 983 m [3,225 ft] using a stan-dard SERVCO pipe cutter. The first section, from wellhead to 861 m, was pulled successfully with an overpull of 320,000 lbf [1,420 kN]. The second section from 861 m to 983 m was pulled success-fully with 700,000 lbf [3,110 kN] overpull using a downhole pulling tool.

The operator’s next objective, based on the previous two cuts, was to validate the selective cutting capabilities of the MCPC with six cuts in a single run at 1,602; 1,509; 1,409; 1,300; 1,068 and 1,031 m [5,256; 4,951; 4,623; 4,265; 3,504 and 3,383 ft] using the MCPC tool.

All cuts were completed, requiring from 10 to 14 min each. The pressure drop displayed on the rig floor pressure gauge clearly indicated at every cut that the tool had functioned as intended and that the casing was cut. Based on inspections of the tool at the surface, it was clear that all three sets of cutters had been deployed.

The casing from 983 m to the cut at 1,031 m was then pulled free and removed from the well-bore with an overpull of 940,000 lbf [4,180 kN] using a standard spear and a hydraulic jacking unit. The casing section from 1,031 m to 1,068 m was again pulled free using the same spear and a downhole jacking unit, but this time saw an over-pull of 640,000 lbf [2,850 kN]. Again, this section was pulled to surface and the spear assembly was run once more to retrieve the 1,068- to 1,300-m section. It was confirmed, however, after pulling a maximum of 1,052,000 lbf [4,680 kN] that the cas-ing section was too long to allow retrieval in one

> Offshore completion. Lower completions that must be pulled from the hole as part of slot recovery procedures typically consist of packers to isolate production zones and the tubing-casing annulus, landing nipples for deploying slickline intervention tools and perforated production tubing.

Intermediate casing

Production casing

Packer

Landing nipple

Perforations

Wireline entryguide

Perforatedproduction tubing

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piece and had to be subsequently cut at 1,104 m [3,622 ft] and 1,202 m [3,944 ft]. These two cuts were performed with a standard pipe cutter.

The three resulting sections of casing were pulled free using the standard spear and downhole jacking unit with an overpull of 820,000; 930,000 and 440,000 lbf [3,650; 4,180 and 1,960 kN], respectively.

When attempting to pull the 1,300- to 1,409-m section of casing, engineers discovered that the casing would not pull free with a maximum of 1,052,000 lbf overpull.

The team then decided to make six more cuts to shorten the remaining pieces of casing to be removed. These cuts were performed with the MCPC in one run at 1,570; 1,545; 1,472; 1,436; 1,372 and 1,335 m [5,151; 5,069; 4,829; 4,711; 4,501 and 4,380 ft]. As with the first six cuts, the MCPC tool performed as intended, and cutting times were between 6 and 14 min each. In all, engineers esti-mated using the MCPC method delivered to the operator a savings of about 1.5 days and US$ 200,000 over conventional methods.

The remaining pieces have not yet been retrieved from the wellbore because the cus-tomer decided to temporarily suspend operations on this well for various reasons not related to the MCPC operations. The operator will return to the well and continue pulling the remaining sections in the near future.

Perforate, Wash and CementA crucial requirement of a permanent abandon-ment procedure is placement of a cement plug across the wellbore and in the annuli of the lower casing sections remaining in the well once upper sections have been pulled. In the majority of these cases, the procedure is to mill a window through all casing strings through which cement may be pumped into the annuli and against the exposed formation (right). This procedure also removes any cement, settled mud or other debris from between the casing and the formation that could prevent the required multidirectional sealing.

A potential drawback to this practice arises from the fact that a highly viscous drilling fluid must be used during the milling operation to lift the metal cuttings, commonly known as swarf, to the surface. Swarf-laden fluids have a density that is usually considerably greater than the formation can withstand before fractures are induced. The resulting equivalent circulating density (ECD) is more than sufficient to cause lost circulation

6. Hekelaar S, Gibson K and Desai P: “Increasing Reliability of Cutting/Pulling Casing in a Single Trip,” paper SPE 145494, presented at the Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, September 6–8, 2011.

7. Hekelaar et al, reference 6.

>Multicycle pipe cutter (MCPC). Through changes in pump pressure, operators are able to position activating cams so that they act to extend one set of knife blades on the MCPC while the others remain retracted. Varying mud pulse signals cause the cycle indexing mechanism to engage a hydraulically activated, mechanically actuated casing spear (not shown) while simultaneously retracting all blades. When the cut is complete, a piston moves downward to a piston stop (not shown), creating a larger flow area through the pressure drop indicator. The resulting pressure drop is displayed at the surface, serving as confirmation that the cut is complete.

Pressure drop indicator

Activating cams

Knife blades

Indexing mechanism

>Milled windows. Casing strings of lower completions that are poorly cemented but cemented in a manner that renders them irretrievable (left),must be milled. One trip is required to mill the production casing (middle) and then separate trips are required for any intermediate casings (right) until all annuli and the formation are exposed. This allows the operator to cement each annulus according to permanent P&A requirements before drilling the sidetrack.

Intermediatecasing

Cement

Productioncasing

Production casingwindow

Intermediate casing and productioncasing window

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problems in the exposed zones.8 Additionally, sur-face equipment may be easily damaged when metal-laden fluid passes through it.

As a consequence, these operations are time consuming and can be difficult to perform safely and effectively. Additionally, it is difficult to test the effective plug seals through the two methods typically deployed in section milled casing: leav-ing the top of the cement inside the casing above the milled window and leaving the top of the cement in the open hole.

To test the former, the plug is tagged, weight tested and then pressure tested. These tests assess the quality of cement inside the casing and make no determination of quality of cement in the casing annulus or in the open hole. In the latter test, the plug can be tagged to verify posi-tion, but in most cases, it is impossible to pres-sure test it.

One response to these challenges has been the introduction of a system known as perforate, wash and cement (PWC). This technique removes debris from the annulus through perforations, which eliminates milling debris and a high ECD to remove swarf.

The PWC method uses a tool made of pipe-conveyed perforating guns attached below a wash tool, which is below a cement stinger. The PWC

tool is run to plug-setting depth where the guns are fired and automatically dropped. Fluid is then circulated and conditioned to match wellbore pore pressure conditions. A ball is dropped, which seals off the bottom of the wash tool and opens a sliding sleeve to direct circulation between the wash cups. Washing is done across the perforated interval from top to bottom. Circulating fluid cleans the annular space through the perforations between the wash cups and the annular space above the top wash cup.

When the tool reaches the bottom perfora-tion, the washing continues while the tool is moved upward. The wash tool is then run back to the bottom of the perforations and a cement spacer is pumped between the wash tool cups and into the annular space as the tool is pulled upward. A ball is dropped and landed, discon-necting the wash tool from the cement stinger. The wash tool is then pushed to below the perfo-rations. The wash tool cups are designed to main-tain contact with the casing inner wall and are then used as a base for cementing operations. The cement stinger is pulled above the top perfo-ration and the casing cleaned a final time through the workstring before the interval is cemented through the stinger. The cement is then squeezed into the perforations.

The workstring can then be used to wash downward to the top of the cement for tagging and pressure testing. If the plug needs to be tested, the operator can drill out the cement plug, pressure test the annulus and then set a plug inside the casing, which can be tagged and tested according to regulators’ requirements.

By August 2011, operator ConocoPhillips had completed 20 PWC plug installations in the North Sea. Through experience and operational improvements using the PWC method, the opera-tor progressively whittled down time required to set a permanent plug to 2.6 days. By comparison, in the course of six conventional operations, the operator required an average of 10.5 days to set a permanent downhole plug (left). As a result, the company calculated a savings of 124 rig days over the course of the 20 PWC wells.9

A New TimelineBecause of increasing concerns over the many wells no longer in production but not yet perma-nently sealed, regulators in the mature offshore areas of the Gulf of Mexico and the North Sea are pressing for action. This promises to immediately create enormous demand for abandonment ser-vices in those markets. The overall cost of decom-missioning on the UK Continental Shelf is estimated at about US$ 48.6 billion by 2050, with US$ 7.2 billion expected to be spent in the next five years. Well plugging will account for more than US$ 2.6 billion spent by 2016.10 North Sea operators have indicated these are modest estimates and that they expect to pay tens of millions of dollars in P&A costs per well plus the cost of decommission-ing surface facilities and other infrastructure.

Because there is no profit to be gained from abandoning a well, operators look to service com-panies to limit the economic downside of these obligatory operations. And because the tangibles, such as cement and reamers, are relatively inex-pensive and nearly fixed in amount and quality, the service industry challenge is to develop advantages by improving the intangibles—the methods that save time and money during perma-nent abandonment exercises.

The number of wells ready for these final pro-cedures may rise with time because while opera-tors work to permanently abandon their backlog of idle wells, many wells being drilled today will have a shorter productive life than wells drilled in the past. Earlier offshore wells captured hydro-carbons from large accessible reservoirs, while many of the remaining reservoirs are substan-tially smaller and will have shorter life spans that will make them abandonment candidates after fewer years of production than their predeces-sors. Additionally, regulators have made it clear that the time between the end of a well’s life and its permanent sealing will now be shorter than in the past. Given these new parameters, it behooves operators to plan for a well’s final days even as they spud it. —RvF

> Time saved during perforate, wash and cement (PWC). With continual operational improvements, engineers reduced the average plug-setting time from 10.5 days to 2.6 days for a single run PWC plug. Over the history of 20 jobs, engineers estimated a savings of 124 rig days. (Adapted from Ferg et al, reference 9.)

0

2

4

6

8

10

12

Tim

e sa

ved,

d

Section milling

10.5

6.04.3

2.6

Three-trip PWC Two-trip PWC Single-trip PWC

8. For more on lost circulation: Cook J, Growcock F, Guo Q, Hodder M and van Oort E: “Stabilizing the Wellbore to Prevent Lost Circulation,” Oilfield Review 23, no. 4 (Winter 2011/2012): 26–35.

9. Ferg TE, Lund H-J, Mueller D, Myhre M, Larsen A, Andersen P, Lende G, Hudson C, Prestegaard C and Field D: “Novel Approach to More Effective Plug and Abandonment Cementing Techniques,” paper SPE 148640, presented at the SPE Arctic and Extreme Environments Conference and Exhibition, Moscow, October 18–20, 2011.

10. Chesshyre M: “Braced for the North Sea ‘Bow Wave’,” Offshore Engineer 36, no. 11 (November 2011): 33–37.

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Contributors

Spring 2012 51

Peter Ablard is an Appraisal Geologist for the West of Shetland Exploration and Appraisal group for Chevron North Sea Limited. He holds a BSc degree in geology from The University of Edinburgh, Scotland, and an MSc degree in integrated petroleum geoscience from the University of Aberdeen. Since graduating, Peter has worked for Chevron, based in Aberdeen, in the areas of development, appraisal and exploration.

Lucas W. Abshire is a Business Development Manager for Schlumberger in Broussard, Louisiana, USA. He is responsible for North America fishing, well abandon-ment and pipe recovery product lines. Lucas previously worked as a field engineer for three years before obtaining his current position. He received his BS degree in civil engineering from the University of Louisiana, Lafayette, USA. He is a registered profes-sional engineer in the state of Louisiana.

Jeff Alford, based in Houston, is the North America Land Acoustic Domain Champion for PathFinder, a Schlumberger company. In addition to supporting operations at the field and client level, he is involved in developing geophysical and geomechanical solutions for drilling, formation evaluation and completion problems with a focus on unconventional resources. Since joining Schlumberger in 1981, he has participated in the development and testing of the sonicVISION*, SonicScope*, Ultrasonic Imager, Dipole Sonic Imager, Sonic Scanner* and Isolation Scanner* tools. He currently serves on the SPWLA board of directors as Vice President Information Technology.

Chris Bell, who has worked with Chevron for more than 30 years, is currently an Operations Geologist in the Chevron North Sea Limited Onshore Europe team in Aberdeen. For most of his career, he has been involved in wellsite geology and geological and geo-physical operations, well planning and geosteering. He is focused on the development and deployment of new technology and strategies to enhance reservoir charac-terization and optimally placed wells. Chris began his career in the early 1970s as a cartographer; he worked for Marathon Oil Corporation starting in 1978 and joined Chevron in 1981. Chris obtained a BSc degree (Hons) in geology and an MSc degree in sedimentation and stratigraphy at Birkbeck University of London.

Matt Blyth, who has been the LWD Acoustics Domain Champion for Schlumberger North America Offshore operations since 2009, is based in Houston. His primary role is in technical sales and operations support for LWD acoustics operations in the Gulf of Mexico, Atlantic and Eastern Canada and Alaska. Before joining Schlumberger in 1997, he worked as a civil engineer for water supply infrastructure projects in the UK. Since joining Schlumberger, he has had a variety of roles in Canada and the US before becoming an instructor at the Drilling & Measurements (D&M) Sugar Land Learning Center in Texas, USA. Matt received bachelor’s and mas-ter’s degrees in engineering from the University of Cambridge, England.

David Cook is the Vice President Operations for Mud Logging for Geoservices, a Schlumberger company, in Roissy-en-France, France. Prior to his current position, he was the Geoservices vice president of sales and marketing. David began his career as a mud logger on an offshore drilling rig in South Korea in 1989. He has more than 23 years of experience in mud logging as a field engineer, pore pressure specialist, and for the last 15 years, in various line management positions in Asia, Latin America and the Middle East. He holds a BSc degree (Hons) in geology from the University of Portsmouth, Hampshire, England.

Bob Costo, who began working for Schlumberger in 2005, is an Engineering Manager in charge of develop-ment of BHA, surface equipment and tubular products. Currently based in Houston, he spent 10 years with Hughes Christensen prior to joining Schlumberger. Bob earned a BS degree in mechanical engineering from The University of Texas at Austin.

John Crowe, who works in Luanda, Angola, is the Formation Evaluation Team Leader for Chevron Cabinda Gulf Oil Company Ltd and is responsible for formation evaluation support for both shelf and deep-water operations. He began his career in 1980 with Chevron Overseas Petroleum Inc in San Francisco, California, USA, and has more than 19 years of experi-ence with Chevron in Nigeria, Kuwait, Spain and Angola. He worked as a research scientist for 11 years at Chevron Oil Field Research Company and Chevron Petroleum Technology Company in La Habra, California, where he specialized in basin modeling, wireline and LWD resistivity tool modeling and in numerous wireline, LWD and horizontal well logging applications. John holds a BS degree in mining geophysics from Columbia University, New York City, and a PhD degree in marine geophysics from the Massachusetts Institute of Technology, Cambridge, and Woods Hole Oceanographic Institution, both in Massachusetts, USA.

Larry W. Cunningham, Schlumberger Senior Vice President of Impact Tools, has 38 years of experience in BHA tools. He is based in Houston. He was previously employed by Dailey Petroleum Services Corporation, National Oilwell Varco and Smith International. From 2003 to 2008, he was the president of Sup-R-Jar LLC. Larry earned a BA degree in history from Southwest Texas State University, San Marcos.

Praful Desai is a Senior Engineer for the Schlumberger Drilling Tools & Remedial segment in Houston, where he works on special projects. Praful began his career with Smith International Inc in California in 1979 and has more than 30 years of experience with Smith in drilling, fishing, remedial, wellbore departure and well abandonment tools and services. He received his BS degree in mechanical engineering from Trine University, Angola, Indiana, USA, and an MS degree in mechanical engineering from California State University, Los Angeles.

Kevin Fielding is a Senior Staff Geologist with Hess Services UK Limited. He works in the Hess London Office for the Global New Business Development team; previously he worked for Hess predevelopment, devel-opment and production teams in northwest Europe. During his 20-year career in the upstream oil and gas

industry, he has worked in a variety of technical and managerial roles. Kevin obtained a first class BSc (Hons) degree in geology from the University of Sheffield, South Yorkshire, England, and a PhD degree in geo-chemistry from The University of Edinburgh, Scotland.

Ivan Fornasier is Manager of the Schlumberger Geoservices Expertise Center (GEC) for Formation Evaluation, in Roissy-en-France, France. He started his career in 1995 as a mud logger for Geoservices, then became a data engineer before specializing in FLAIR* technology. In 2009, he moved to the Geoservices main office to serve as a fluid specialist, and moved to his current position a year later. Ivan holds a bachelor’s degree in geology from the University of Naples Federico II, Italy.

George Haines has worked in various capacities for Geoservices since 1981. After attending the University of Pittsburgh at Johnstown, Pennsylvania, USA, he worked as a mud logger and data engineer in the Rocky Mountain region of the US and then took assign-ments in Central and South America, Europe and North and West Africa. He has served as a mud logging trainer, a technical writer and a recruiter. Based in Houston, George is currently the Health, Safety and Environment Manager for Geoservices North America.

Mark A. Herkommer manages the PreVue* service line for Schlumberger in Conroe, Texas, and is actively involved in all pressure-related phases of well planning and drilling. Prior to joining Schlumberger, he was the owner and president of Petrospec Technologies, which specializes in solutions to pore pressure, fracture gra-dient and wellbore stability challenges in offshore operating environments. Mark is a licensed profes-sional geoscientist in Texas. He obtained a BS degree in geology from Eastern Michigan University, Ypsilanti, USA, and an MS degree in applied mathematics from The University of Texas at Dallas. He has authored more than 70 publications related to the geosciences and mathematics.

Laura Lawton is a Senior Geologist at Hess Services UK Limited in London. She has worked at Hess for five years on a range of exploration, appraisal and produc-tion projects in Europe and North Africa. Laura earned an MSc degree in petroleum geoscience from Imperial College, London, and an MSc degree in natural sci-ences from the University of Cambridge, England.

Julio Loreto is the D&M Data Quality Manager and Acoustics Technology Product Champion for Schlumberger. Based in Sugar Land, Texas, his primary responsibilities are the assessment of current and future market needs for development of new technolo-gies in LWD acoustics. He joined Schlumberger in 1997 as an MWD and LWD engineer and has worked in West Africa and the Gulf of Mexico. From 2005 to 2011, he was D&M operations manager in Venezuela, Alaska and Mexico. Julio holds a BS degree in electronics engineer-ing from Universidad Simón Bolívar, Caracas.

Glenn Joseph Martin is a Global Business Manager with Schlumberger in Houston. Glenn has 35 years of experience with impact tools. He began working with Smith in 1998 as a business development manager.

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52 Oilfield Review

Kevin McCarthy is a Petroleum Systems Analyst/Geochemist with BP Exploration in Houston. From 2008 through 2011, he served as a geochemist with Schlumberger in Houston and at the Heavy Oil Regional Technology Center in Calgary. He was a research assis-tant at Tufts University in Medford, Massachusetts, where he analyzed aqueous and soil samples in support of the US National Aeronautics and Space Administration Phoenix Mars Mission; he was also a hydrologist consulting on water management issues in Sarasota County, Florida, USA. Working with Woods Hole Oceanographic Institute in Massachusetts, he researched deep sea hydrothermal vents as a scientist diver in the manned submersible Alvin. Kevin has a master’s degree in geochemistry with a special focus on hydrogeology from the University of South Florida in Tampa, and a bachelor’s degree in geology from Salem State College in Massachusetts.

José Mercado, a Schlumberger Global Product Engineer in Houston, provides technical advice and assistance to sales and operations of all Smith Services products and services. He began his career with Smith International in 1998 as a QHSE regional manager in South America. He earned a BS degree in civil engi-neering technology from Wentworth Institute of Technology, Boston, Massachusetts, and an MS degree in structural steel design from Universidad Central de Venezuela, Caracas.

Saeed Mohammed is the LWD Acoustics Domain Champion for Schlumberger D&M and is based in Al-Khobar, Saudi Arabia. He began his career in the oil industry in 1993 as a seismologist in the Borehole Geophysics Division of Seismograph Service Limited. In 2001, he joined Schlumberger; for the majority of his career, he has focused on borehole acoustics measure-ments and is currently involved in field testing LWD sonic tools. Saeed has a degree in applied geology from Abubakar Tafawa Balewa University, Bauchi, Nigeria, and an MS degree in petroleum geology from University of Benin, Benin City, Nigeria.

Brian Mohon is a Schlumberger BHA Tool Design Engineer in Houston. His responsibilities include new product development and technical support for various downhole tools, including drilling jars. He received his BS degree in mechanical engineering from Texas Tech University, Lubbock.

Dan Mueller is a Cementing Specialist for the ConocoPhillips Global Wells Drilling Engineering Group in Houston. He has 33 years of experience in cementing operations, technical sales, research and applied technology. He was past chair of an API sub-committee (SC-10) on well cements and currently serves as chair of both the editorial group of the ISO technical committee on well cements and the API SC-10 publications committee. He authored the ISO standards Testing of Deepwater Well Cement Formulations and Methods for Determining the Static Gel Strength of Cement Formulations. He was a 2000/2001 SPE Distinguished Lecturer, has published more than 30 technical papers and has been awarded 10 US patents. Dan holds a BS degree from the University of Oklahoma, Norman, USA.

William B. Paulsen began his career in 1977 with the Red Adair Company in Houston. He then worked as a drilling, completions, workover and production opera-tions supervisor at Corpus Christi Oil & Gas Company. In 1997, he began as a petroleum consultant for BP Exploration, where he was responsible for field supervi-sion of remedial well operations in the BP Cusiana and

Cupiagua development project in Colombia. He cur-rently works for ATP Oil & Gas Corporation in Houston, as a Production Superintendent. William manages the decommissioning of pipelines, wellbores and platforms and is responsible for through-tubing recompletions and workovers on shelf properties; he is involved in deepwa-ter riserless well interventions planning.

Vivian Pistre, based in Sagamihara, Japan, is Geophysics, Acoustics and Geomechanics D&M Domain Head for Schlumberger, a position he has held since 2010. He began his career with Schlumberger in 1982 and has worked as a field engineer, operations manager and log analyst in a number of locations, including Africa, Latin America and Europe. Since 1996, he has been involved in the development of wire-line and LWD sonic tools, primarily at the Schlumberger Kabushiki Kaisha Center in Japan. Vivian earned a BS degree in engineering and an MSc degree in computer science and artificial intelligence from École Nationale Supérieure d’Électronique, d’Électrotechnique, d’Informatique, d’Hydraulique et des Télécommunications, Toulouse, France.

Jean-Pierre Poyet is Vice President of Technology for Geoservices in Roissy-en-France, France. Throughout his oilfield career, he has experience in engineering, research, marketing and operations with Schlumberger Wireline and Testing. For the past decade, he has worked for Geoservices in mud logging, slickline and multi-phase flow production activities. When Geoservices was acquired by Schlumberger, Jean-Pierre served as Geoservices deputy general manager. He received an engineering degree from École Centrale de Lyon, France, and a PhD degree in astrophysics from Columbia University, New York City.

Maja Radakovic is a Drilling Performance Engineer for Sinopec-Addax in Geneva, Switzerland. Prior to her current position, she worked in Roissy-en-France for Schlumberger as a Geoservices product champion for drilling support products related to mud logging. She spent three years at the GEC in Roissy-en-France to assist with development, growth and sales of the Thema* service and was also in charge of Brazil opera-tions. She joined Geoservices in 2006, starting as a mud logger and data engineer, and worked primarily in the UK sector of the North Sea. Maja obtained her master’s degree in geotechnics from the Faculty of Mining and Geology, University of Belgrade, Serbia.

Robert D. B. Robertson joined Smith International in 2007 as an operations manager. Based in Stavanger, he has been a Schlumgerger Global Product Engineering Advisor since 2011. Robert is responsible for product development, reliability and technical follow up of the fishing and remedial product line with an emphasis on global plug and abandon technology.

Adrian Rodriguez-Herrera is a Schlumberger Reservoir Geomechanics and Development Engineer, based at the Reservoir Geomechanics Center of Excellence, Bracknell, England. Since 2009, he has worked in the design and development of geomechanical workflows involving 3D numerical modeling. He supports oil and gas field management projects aimed at the efficient integration of seismic, structural and log data for geo-mechanical applications. Adrian began working for Schlumberger in 2008 at the Schlumberger Heavy Oil Center of Excellence, Puerto La Cruz, Venezuela, where he focused on reservoir engineering and simulation. He has a BS degree in petroleum engineering from the Universidad de Oriente, Maturín, Venezuela.

Sachin Sharma joined Geoservices in 1997 as a mud logging geologist and pore pressure engineer, working mainly in Southeast Asia. In 2003, he became a FLAIR field engineer when the service was launched and two years later established the GEC in the UK. He later worked as a GEC manager in Roissy-en-France, where he now works as a Schlumberger Product Champion for Formation Evaluation, Surface Data Logging Services. Sachin attained his master’s degree in geology from the University of Lucknow, Uttar Pradesh, India.

Torodd Solheim, based in Stavanger, is a Schlumberger Senior Product Line Manager, Fishing and Remedial for Europe and Africa. He was previously operations sup-port manager for Europe and CIS. He began his career with The Red Baron Ltd as fishing supervisor, and his experience includes all aspects of fishing, plug and abandonment and wellbore departure operations world-wide, including supervising abandonment operations in North Sea fields. Torodd earned a bachelor’s degree in education from the University of Stavanger.

Ed Tollefsen is Business Development Manager for PathFinder in Houston where he supports LWD and MWD technology development, use and education. Prior to his current position, he served as business development manager for Schlumberger D&M in North America. His career with Schlumberger began in 1990 as a field engineer with wireline evaluation services, formation testing and seismic acquisition. He served as a staff engineer and field service manager for Gulf Coast Special Services, Belle Chase, Louisiana, USA, where his primary responsibility was design changes to offshore units. While there, Ed also served as wireline US land seismic and special services operations man-ager. He received a BS degree in computer engineering from the Georgia Institute of Technology, Atlanta, USA.

Lawrence Umar started his oilfield career in 1991 with Sarawak Shell Berhad. In 2000, he joined Lundin Petroleum before moving to Petronas Carigali Sdn Bhd the next year. He started as a wellsite drilling engineer and progressed to project drilling engineer, senior drilling supervisor, operations engineer and eventually Drilling Superintendent, a position he has held for the last 13 years. As a drilling superintendent, he has man-aged drilling operations on jackup rigs, semisubmers-ibles, drillships, tender barges, semisub tenders and land rigs. He has been involved in drilling various well types, including horizontal, multilateral, splitter, extended-reach drilling, carbonate gas, slimhole mono-bore and HPHT wells using technologies such as expandable tubulars, casing drilling, twin and triple wellheads and managed pressure drilling. He is based in Kuala Lumpur.

Liangjun Xie is a Schlumberger Senior Application Developer in Houston. Since 2008, when he joined Smith International, he has developed soft string and stiffness string mechanical models for torque and drag, established the hydraulic model for swab and surge and developed the vibration model for jar place-ment. Previously, Liangjun was an R&D engineer with Jiangnan Shipyard Company Ltd in Shanghai for three years. He has a BS degree in naval architecture from Huazhong University of Science & Technology, Wuhan, China, a master’s degree in electrical engineering and a doctoral degree in systems engineering from Washington University, St. Louis, Missouri, USA.

An asterisk (*) is used to denote a mark of Schlumberger.

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Spring 2012

The Quest: Energy, Security, and the Remaking of the Modern WorldDaniel YerginThe Penguin Press, a division ofPenguin Group Inc.375 Hudson StreetNew York, New York 10014 USA2011. 816 pages. US$ 37.95ISBN 978-1-594-20283-4

Daniel Yergin continues the story of global energy as the engine of geopoliti-cal and economic change in this book, a follow-up to his 1991 book The Prize: The Epic Quest for Oil, Money, and Power, for which he won a Pulitzer Prize. From China to the Caspian Sea, from the Mideast to Capitol Hill, Yergin explores the decisions and choices that are shaping our energy-dependent future. He also describes the history of nuclear energy, coal, electricity and natural gas and investigates biofuels and wind and solar energy, explaining why these are crucial to the world’s energy future.

Contents:

Russia Returns, The Caspian Derby, Across the Caspian, “Supermajors,” The Petro-State, Aggregate Disruption, War in Iraq, The Demand Shock, China’s Rise, China in the Fast Lane

Isthe World Running Out of Oil?, Unconventional, The Security of Energy, Shifting Sands in the Persian Gulf, Gas on Water, The Natural Gas Revolution

Alternating Currents, The Nuclear Cycle, Breaking the Bargain, Fuel Choice

Glacial Change, The Age of Discovery, The Road to Rio, Making a Market, On the Global Agenda, In Search of Consensus

Rebirthof Renewables, Science Experiment, Alchemy of Shining Light, Mystery of Wind, The Fifth Fuel—Efficiency, Closing the Conservation Gap

Carbohydrate Man, Internal Fire, The Great Electric Car Experiment

Mr. Yergin is back with a sequel to . . . and, if anything, it’s an

even better book. It is searching, impartial and alarmingly up to date. . . . will be necessary reading for C.E.O.’s, conservationists, lawmakers, generals, spies, tech geeks, thriller writers . . . and many others. But it won’t be easy reading. This is a very large and not overly elegant book. . . . is ency-clopedic in its ambitions; it resists easy synopsis. What sucks you onward are its strong set pieces, some of the best of which are about what Mr. Yergin calls ‘the new world of oil.’

The New York Times

The House of Wisdom: How Arabic Science Saved Ancient Knowledge and Gave Us the RenaissanceJim al-KhaliliThe Penguin Press, a division ofPenguin Group Inc.375 Hudson StreetNew York, New York 10014 USA2011. 336 pages. US$ 29.95ISBN: 978-1-594-20279-7

The author describes the scientific innovations—in medicine, mathemat-ics, optics, astronomy and chemistry—of the Islamic world from the ninth through the fourteenth centuries and reveals how they underpinned and enabled the European Renaissance. These discoveries, principles and evidence-based approaches were, the author posits, obscured by later Western versions of the same principles. The author also explores why and how the Arab world entered its own dark ages after centuries of enlightenment.

Contents:

British-Iraqi physicist Al-Khalili . . . retraces this vital contribution of Islamic scientific thought. His enthusiasm, interjection of personal anecdotes, and conversa-tional style will make the story accessible for nonspecialists.

. . . . The book is marred by the author’s repeated admonitions to acknowledge the value and worth of the Islamic tradition, by comparisons of the ‘greatness’ of this or that Islamic figure with one from the Latin West, and, ironically, by assessments of the work of Islamic figures based, not in their historical and intellectual context, but in their closeness to or presaging of modern ideas.

Choice

. . . . modern historians of science agree that more attention should be given to the Arab contribution to the preservation and expansion of knowl-edge at this critical period, and the author has done so in considerable detail and with rising passion. . . . By recounting Arabic science’s luminous past, al-Khalili says he hopes to instill a sense of pride that will ‘propel the importance of scientific enquiry back to where it belongs: at the very heart of what defines a civilized and enlightened society.’

The New York Times

Coming in Oilfield Review

Going to Extremes. High-pressure, high-temperature (HPHT) wells pres-ent challenges for conventional sampling and pressure equipment. Whereas engineers can repackage sensors or protect sensitive down-hole electronics for short durations with flasks, some tools used for evaluating wells must be completely reengineered if they are to survive the rigors of HPHT conditions. This article describes three reengineered tools used for evaluating wells and a mud system that can withstand extreme operating temperatures.

Seismic Methods for Mapping Fractures. Over the last decade, oil and gas companies have had increased success placing wells within productive zones—sweet spots—of fractured reservoirs. Advances in seismic techniques have been especially useful in help-ing geoscientists identify and char-acterize these zones. This article describes detailed case studies of successes using seismic methods to help operating companies make decisions about well placement in fractured reservoirs.

Drilling Automation. For the past 10 to 20 years, many newly built rigs have included automated drill floor hardware such as iron roughnecks and pipe-handling equipment to increase safety and operational con-sistency. Drilling automation seeks to optimize the drilling process as a whole. This article looks at how the industry is linking the rig to auto-mated downhole systems in efforts to lower reservoir access costs and out-perform manual operations.

Microbes. Microbes and humans have existed as both enemy and ally for millions of years. That dual nature also exists in the oil field. Microbes can plug formations and cause corrosion and reservoir sour-ing, but they can also enhance oil recovery. New, analytical methods are giving scientists insights into this unseen world. As a result, new applications are emerging that will help producers more effectively con-trol and harness microbial behavior.

NEW BOOKS

53

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Oilfield Review54

The Diffusion Handbook: Applied Solutions for EngineersR. K. Michael ThambynayagamMcGraw-Hill Companies, Inc.1221 Avenue of the Americas, 45th FloorNew York, New York 10020 USA2011. 2,048 pages. US$ 199.00ISNB: 978-0-07-175184-1

In this book, Thambynayagam, a Schlumberger Technical Director and Senior Advisor, provides solutions to boundary-value problems associated with Dirichlet, Neumann and Robin boundary conditions as well as solutions to variations on these problems. TheDiffusion Handbook is the recipient of the 2011 R. R. Hawkins Award, the top prize from the American Association of Publishers for Professional and Scholarly Excellence, as well as the PROSE Award for Excellence in Physical Sciences & Mathematics and the PROSE Award for Excellence in the Engineering & Technology category.

Contents:

p(x, t x t

p(x, tx t

p(x, y, tx, y t

p(x, y, t x, y t

p(x, y, tx, y t

p(x, y, z, tx, y, z t

p(x, y, z, tx, y, z t

p(x, y, z, tx, y, z t

p(x, y, z, tx, y, z t

p(r, t rt

p(r, t r t

p(r, θ, tr, θ t

p(r, θ, tπ

p(r, θ, t r, θ t

θθ ϑ, ϑ π

r, θ t

θ

0 ≤ θ ≤ ϑ ϑ π p(r, θ, t)r, θ t

z p(r, z, tr, z t

z z = d p(r, z, t)r, z t

zp(r, z, t) Is

r, z t

z z = d p(r, z, t)r, z t

p(r, θ, z, t) Is

π p(r, θ, z, tr, θ, z t

z z = dp(r, θ, z, t

π p(r, θ, z, t)r, θ, z t

zp(r, θ, z, t)

π p(r, θ, z, tr, θ, z t

z z = d p(r, θ, z, t)

π p(r, θ, z, tr, θ, z t

This reference book is a compen-dium of analytical solutions of the diffusion equation in three dimensions for a variety of geometries and boundary conditions. . . . The table of contents is . . . unique in that each solution is listed by showing a sketch of each geometry being solved and the associated boundary conditions. . . .

This massive book is mainly filled with mathematical solutions. . . . Engineers or scientists who work with solutions to the diffusion equation and would like an extensive reference book for analytical solutions rather than relying on numerical techniques would find this book to be an incred-ible resource with nothing else comparable.

IEEE Electrical

Insulation Magazine

The Philosophical Breakfast Club: Four Remarkable Friends3Who Transformed Science and Changed the WorldLaura J. SnyderBroadway Books, an imprint of Crown Publishing, a division of Random House1745 BroadwayNew York, New York 10019 USA 2011. 448 pages. US$ 27.00

A four-in-one biography of William Whewell, Charles Babbage, John Herschel and Richard Jones, this book looks at how the lives of these 19th-century scientists intertwined. Author Laura Snyder describes their personal lives, accomplishments and influences on science and economics.

Contents:

Philosopher and science historian Snyder . . . has written an impressive biography of four Victorian poly-maths. . . . The collaborations of these remarkable men in economics, sci-ence, mathematics, and social policy, particularly their development of institutional reform . . . virtually created the ‘profession’ of science with its institutions, curricula, norms, and methods. . . . The men’s entangled lives and work make engaging and informative reading. Highly recommended.

Choice

Laura J. Snyder’s

describes how . . . Babbage, Herschel, Whewell and Jones set out to modern-ize the way science in England was taught, organized and conducted—to elevate science from an avocation into a specialized profession. Ms. Snyder, a scholar of Victorian science and culture at St. John’s University in New York, shows a full command of the scientific, social and cultural dimensions of the age.

The Wall Street Journal

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> Shaped charge detonation. A shaped charge (top left) consists of a small primer igniter, an outer casing, explosive material and a conical liner. The detonator cord connects individual shaped charges (upper right) and, when detonated, begins a chain reaction in which the liner focuses the energy of the explosives into a jet (middle left). This generates a tremendous high-velocity pressure wave. The jet tip travels at 7,000 m/s [22,965 ft/s] and exerts as much as 103 GPa [15 × 106 psi], creating perforation tunnels that penetrate the casing, cement and the formation (bottom right).

Perforating gun

Reservoir

Detonator cordCasing

Cement

Shaped charge

Before detonation

After detonation

Detonator cordPerforating gun

Liner

Explosive

Detonation front

Jet tip

Jet tail

Primer igniter

Jet tip

Spring 2012 55

DEFINING PERFORATING

Detonation for Delivery

Oilfield Review Spring 2012: 24, no. 1. Copyright © 2012 Schlumberger.

Tony SmithsonEditor

Perforating—the act of blasting holes through steel casing, cement and formation rock—happens in an instant, and yet, the long-term viability and profitability of most oil and gas assets depend on it. Perforating guns carry explosive shaped charges downhole, where they are detonated to create tunnels that act as conduits through which reservoir fluids flow from the formation, into the wellbore and up to the surface.

In the 1920s, E&P companies began the practice of cementing metal pipe in the wellbore. The cement supported the casing and isolated produc-ing intervals from other zones. Although effective, the practice created a dilemma for operators: how to reach the hydrocarbons on the outside of the pipe. Bullet guns were originally used to mechanically punch through the pipe and cement, but their penetration and effectiveness were limited. Shaped charge technology, based on military antitank weaponry, was intro-duced to the oil field in 1948. It revolutionized well completions.

A shaped charge has an outer shell that houses a primer igniter and explosive material, which are held in place by a conical liner (below). The igniter acts as the link between the detonator cord and the explosives in

the shaped charge. The liner does more than hold the explosives in place; its conical shape creates a high-pressure jet of energy, which penetrates the casing, cement and formation.

Perforating involves the use of high-order explosives, which must be han-dled with great care. Most explosives used for perforating are referred to as secondary explosives, meaning another source must initiate their detonation. A blasting cap detonator usually begins the chain reaction; the detonator may be electrically or mechanically initiated. Conventional blasting caps are elec-trically initiated when a current passes through a filament, which ignites a match that sets off a lead azide primary explosive charge (above). Mechanically initiated blasting caps are also referred to as percussion detonators. The blasting cap is connected to the detonator cord, which creates the shockwave that sets off the shaped charges in the perforating gun, all of which culmi-nates in the creation of perforation tunnels.

Electrical detonators have proved to be quite reliable, but a number of safety practices have been developed to prohibit the unintentional detonation of the caps. Such practices include grounding electrical sys-tems and shutting off power during the arming of guns. Today, radio trans-missions pose one of the greatest dangers to conventional blasting caps because these transmissions may induce current in the detonator wires. When perforating with conventional blasting caps, wellsite personnel must shut down radio transmitters, which include cell phones.

Because today’s wellsites rely on continuous communication via radio, shutting down all transmissions is problematic. To address this drawback to using conventional detonators, engineers designed a detonator that con-tains no primary explosives and has a power threshold of 3 megawatts to initiate detonation; a conventional blasting cap detonator has a power threshold around 1 watt. When operators use this new detonator, radio transmissions can continue safely during the arming of guns because stray voltage or induced current cannot initiate detonation.

> Electrical detonator. There are many varieties of detonators; some are electrically initiated, others are set off by pressure or mechanical shock and do not require electrical power. Engineers set off electrical detonators such as the one shown by applying current to the leg wires. This heats a filament wire, causes a pellet to ignite and begins a chain reaction as lead azide and RDX in the primer and booster sections set off the detonator cord. Lead azide is a type of primary explosive; RDX is a type of secondary explosive. The safety resistors attached to the leg wires serve two functions: They inhibit the flow of induced current in the wire and provide a known value of resistance, which can be checked with a safety meter to confirm that there is continuity through the filament in the ignition pellet.

Legwires

Rubberplug

Two 27-ohmsafety resistors

Filament

Booster section

RDX RDXLeadazide

Lead azideprimer

Matchignition

pellet

Detonatorcord

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DEFINING PERFORATING

Perforating guns come in a variety of sizes and configurations. The two primary categories of gun systems are through-tubing guns and hollow-carrier, or casing, guns (below). Hollow-carrier guns are larger than through-tubing guns and facilitate bigger charges, more phasing optionsand higher shot density. Phase is the angle between individual charges, expressed in degrees, and shot density is the number of holes per unit of length. Completion hardware in place and reservoir properties usually dic-tate the type of gun system used. However, operators may install a particular type of completion to accommodate a perforating system that is suitable for a specific reservoir.

In wells that contain tubing, operators use small-diameter through-tub-ing guns. These systems consist of either expendable gun systems that leave debris in the wellbore after detonation or retrievable gun systems with a mounting strip that can be recovered after detonation. Through-tubing guns can be used in underbalanced conditions, in which hydrostatic borehole pressure is lower than formation pressure. After detonation, formation flu-ids flow into the well, flushing debris from the newly formed perforation tunnels. The well can be immediately flow tested or put on production. With through-tubing guns, operators can add perforations to producing intervals, or open new zones without the expense of removing the tubing. If the guns are to be retrieved after perforating, the well is usually perforated in an overbalanced condition, in which the borehole pressure is higher than for-mation pressure. If the well is perforated underbalanced with casing guns, the operator must kill the well to retrieve the guns.

Perforating guns are conveyed in the well using a variety of methods. Tubing-conveyed perforating (TCP) guns are attached to tubing and run in the well using a drilling or workover rig. TCP guns offer benefits such as leaving the tubing in place after perforating underbalanced, along with the improved performance and flexibility provided by using hollow-carrier guns. Because wells can be perforated underbalanced, flow to surface may be ini-tiated immediately. Long intervals and widely separated zones can be simul-taneously perforated using this method; other techniques require multiple trips into the well. One drawback to the use of TCP guns is that a drilling or workover rig is required to run the guns into and out of the well. If the guns are to be retrieved, the well must be killed.

Wireline-conveyed perforating has several advantages. For instance, operators have flexibility in choosing a gun system, and operations can be performed with or without a rig on location. Because the wireline cable provides communication between the downhole gun and the surface, wire-line perforating offers acurate depth correlation. Through-tubing perforat-ing almost always relies on wireline for conveyance. Limitations of wireline perforating include gun length and weight and wellbore geometry. Slickline perforating, which is becoming increasingly popular, offers a cost-effective and efficient alternative to conventional wireline perforating and TCP guns. However, slickline units do not provide power from the surface to set off blasting caps, and slickline perforating does not offer the same level of depth-correlation accuracy as wireline perforating.

Although operators consider many factors when designing a perforating program, the reservoir generally dictates which system will be used. For instance, formations that are prone to producing sand perform better with high shot density and large holes (above). Operators often perforate with large-diameter TCP guns that produce many holes per linear foot. Depth of penetration for these types of formations does not affect well performance. Formations damaged during drilling and completion, however, perform bet-ter with deep penetrations that extend beyond the damaged zone. Deeper penetration, however, comes with the disadvantage of smaller diameter per-foration holes. Underbalanced perforating in wells with formation damage may also improve well performance.

The act of perforating may be over in an instant, but engineers and scien-tists realize its importance for the long-term viability of a well. They continue to develop perforating techniques based on improvements in equipment design and deployment systems. Engineers are also using advanced modeling and testing of existing perforating systems to improve results. The ultimate objective is to allow oil and gas to flow from the formation to the surface in a safe and secure manner.

> Casing and through-tubing guns. Perforating guns come in a variety of shapes and sizes. Casing guns (top) house large shaped charges and offer flexible phasing (orientation) and shot density options. Through-tubing guns (bottom) are designed to pass through tight restrictions while maximizing shaped charge size. For the retrievable through-tubing gun shown, only a metal strip where the shaped charges are attached remains after gun detonation.

Perforating Guns

Shaped charge

Shaped charge

Detonator

Detonator

Detonator cord

Detonator cord

Metal mounting strip

Gun housing

> High shot density casing gun after perforating.

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