Spring 2011

Offshore Pipelines

Managed Pressure Drilling

Formation Water

Dielectric Logging

Oilfield Review

11-OR-0002

The supply of safe, affordable and transportable energy is one of the fundamental prerequisites for global economic development. For more than a hundred years, hydrocarbon-based fuels—including oil, coal and gas—have made up the bulk of the world’s energy needs and today remain the only viable option for meeting up to 80 percent of the world’s energy demand forecast to 2030. For the exploration and production of oil and gas, this dependence represents two major challenges.

First, it is becoming much harder to ensure future sup-ply. The E&P industry is investing heavily to maximize pro-duction from existing reserves, while simultaneously developing new resources in more challenging environ-ments such as the arctic and deep water. It is also increas-ing exploration and production in unconventional reserves such as shale gas, shale oil and heavy oil.

Second, it has become imperative that we protect and preserve our environment. E&P activities must leave a smaller operational footprint and provide greater assurance against environmental damage, par-ticularly as the industry continues to explore more sensitive ecological environments.

Given this context, the industry is becoming increasingly dependent on technology as an enabler for future supply. Technologies deployed in E&P activities today offer excep-tional breadth and depth compared with the technologies of only a few decades ago. This is exciting from the per-spective of young professionals who are joining the E&P industry today, but technology, because of its complexities, can also create barriers to understanding.

Understanding the E&P Challenge—Defining the Basics

1

In this issue of Oilfield Review, we are launching a series of articles that details the underlying concepts and technologies on which the E&P industry is built. These “Defining …” articles are written to be accessible to a wider audience than the E&P professionals who typically read Oilfield Review.

The first article is “Defining Logging” (see “Discovering the Secrets of the Earth,” page 60). We chose this topic to lead the series because it reflects the origin of Schlumberger in subsurface logging. In the next few issues, we will intro-duce exploration, drilling, completions and production, before moving into subtopics such as resistivity logging and reservoir modeling.

I hope that you find these articles interesting and that they provide you with a more in-depth knowledge of the technical challenges and technological solutions that encompass the E&P cycle. In addition, it is important that we attract young professionals who are motivated to pursue these challenges for the long term because our industry has a major role to play in the sustainable energy future.

Paal KibsgaardChief Operating OfficerSchlumberger Limited

Paal Kibsgaard is Chief Operating Officer of Schlumberger Limited. Prior to his most recent position as president of Reservoir Characterization, he held a variety of global management positions including vice president of Engineering, Manufacturing and Sustaining; vice president of Personnel for Schlumberger Limited; and president of Schlumberger Drilling & Measurements. Earlier in his Schlumberger career, he was a GeoMarket* manager for the Caspian region after holding various field positions in technical sales and customer support. A petroleum engineer with a master’s degree from the Norwegian Institute of Technology, Paal began his career in 1992 working for ExxonMobil. He joined Schlumberger in 1997.

* GeoMarket is a mark of Schlumberger.

www.slb.com/oilfieldreview

Schlumberger

Oilfield Review1 Understanding the E&P Challenge—Defining the Basics

Editorial contributed by Paal Kibsgaard, Chief Operating Officer, Schlumberger Limited

4 Pipeline to Market

Pipelines provide an economical and reliable means of transporting oil and gas to market, and are as vital to thedevelopment of offshore oil and gas resources as are the wells and platforms they support. The pipeline industry mustmeet a broad range of technical challenges as it expands thiskey infrastructure.

14 Managed Pressure Drilling Erases the Lines

Increasingly complex wellbores make it ever more difficult tostay within prescribed bottomhole pressures using traditionaldrilling methods. Managed pressure drilling techniques offerdrillers a method for maintaining a BHP that is neither toohigh nor too low.

Managed pressuredrilling

Executive EditorMark A. Andersen

Advisory EditorLisa Stewart

Senior EditorsMatt VarhaugRick von Flatern

EditorsVladislav GlyanchenkoTony Smithson

Contributing EditorGinger Oppenheimer

Design/ProductionHerring DesignMike Messinger

IllustrationChris LockwoodTom McNeffMike MessingerGeorge Stewart

PrintingWetmore Printing CompanyCurtis Weeks

Oilfield Review is published quarterly andprinted in the USA.

Visit www.slb.com/oilfieldreview forelectronic copies of articles in multiplelanguages.

© 2011 Schlumberger. All rights reserved.Reproductions without permission are strictly prohibited.

For a comprehensive dictionary of oilfieldterms, see the Schlumberger OilfieldGlossary at www.glossary.oilfield.slb.com.

About Oilfield ReviewOilfield Review, a Schlumberger journal,communicates technical advances infinding and producing hydrocarbons to employees, clients and other oilfieldprofessionals. Contributors to articlesinclude industry professionals and expertsfrom around the world; those listed withonly geographic location are employeesof Schlumberger or its affiliates.

On the cover:

An engineer prepares a dielectric tool to run into a well. The caliper arm (right)pushes the articulated pad (left) securelyagainst the borehole wall. The pad’stransmitters send out microwaves thatreturn to multiple receivers also locatedon the pad. Transmitter-receiver spacing,electromagnetic-field orientation and fluids in the pores determine shape anddepth of the sensed region (inset).

2

Spring 2011Volume 23Number 1

ISSN 0923-1730

53 Contributors

55 New Books and Coming in Oilfield Review

60 Defining Logging:Discovering the Secrets of the Earth

3

24 Finding Value in Formation Water

Formation water analysis is a crucial step in hydrocarbonexploration and production. It provides input to petrophysicalevaluation, helps assess potential for corrosion, scaling andsouring, and aids in the understanding of reservoir connectivity.This article explains the causes of variation in formationwater chemistry—between formations and over time. Casestudies highlight methods for ensuring sample purity anddemonstrate applications of downhole and laboratory evalu-ation techniques.

36 Zapping Rocks

Dielectric logging tools provide supplemental information foranalyzing freshwater reservoirs and identifying movable hydro-carbons. A recently introduced tool offers a dielectric disper-sion measurement to evaluate rock texture in carbonates andshale effects in siliciclastics. Case studies from freshwater,heavy-oil and carbonate reservoirs illustrate applications ofdielectric data.

RXA4 R

XA3 RXA2 R

XA1

RXB1 R

XB2 RXB3 R

XB4

TA

TB

Mudcake probe

Abdulla I. Al-KubaisySaudi AramcoRas Tanura, Saudi Arabia

Dilip M. KaleONGC Energy CentreDelhi, India

Roland HampWoodside Energy Ltd.Perth, Australia

George KingApache CorporationHouston, Texas, USA

Richard WoodhouseIndependent consultantSurrey, England

Alexander ZazovskyChevronHouston, Texas

Advisory Panel

Editorial correspondenceOilfield Review5599 San Felipe Houston, Texas 77056 USA(1) 713-513-1194Fax: (1) 713-513-2057E-mail: editorOilfieldReview@slb.com

SubscriptionsClient subscriptions can be obtainedthrough any Schlumberger sales office.Clients can obtain additional subscrip-tion information and update subscriptionaddresses 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: subscriptions@oilfieldreview.comCurrent subscription rates are availableat www.oilfieldreview.com.

Distribution inquiriesTony SmithsonOilfield Review12149 Lakeview Manor Dr.Northport, Alabama 35475 USA(1) 832-886-5217Fax: (1) 281-285-0065E-mail: DistributionOR@slb.com

Oilfield Review is pleased to welcomeAlexander Zazovsky to its editorial adviso-ry panel. He is Completions EngineeringAdvisor and Research Consultant atChevron in Houston, where he is responsi-ble for managing and leading technologydevelopment and technical services pro-jects. Prior to joining Chevron in 2011, hewas an engineering advisor forSchlumberger in Sugar Land, Texas.Alexander received an MS degree inapplied mathematics, a PhD degree influid mechanics, and a doctorate of tech-nical sciences in petroleum engineering(Habilitation), all from Gubkin RussianState University of Oil and Gas inMoscow. He began his career in Moscow,where he worked at the Research Instituteof Nuclear Geophysics and Geochemistry,the Institute for Problems in Mechanics ofthe Academy of Sciences, the All-UnionOil Institute for Scientific Research(VNIIneft), and the Oil and Gas ResearchInstitute of the Academy of Sciences.Next, Alexander worked at the Laboratoired’Aérothermique du CNRS, Meudon,France, as an invited scientist before join-ing Schlumberger in 1993. He has beeneditor of several professional journals anda consulting editor of the Russian editionof Oilfield Review.

4 Oilfield Review

Pipeline to Market

The success of every prospect depends as much on an operator’s ability to move oil

and gas to market as it does on getting the product out of the ground. In many regions,

pipelines offer the most economical and dependable means of transporting hydro-

carbons from wellhead to refinery. Pipeline companies go to great lengths to safely

install and operate their transmission systems.

Alexander P. AlbertHouston, Texas, USA

Daniel L. LanierGeoscience Earth and Marine Services, Inc.Houston

Brian L. PerillouxWilliams Midstream Services, LLCHouston

Andrew StrongSouthampton, Hampshire, England

Oilfield Review Spring 2011: 23, no. 1. Copyright © 2011 Schlumberger.For help in preparation of this article, thanks to Kamran Akbarzadeh, Edmonton, Alberta, Canada; Michael Carney, Houston; Marsha Cohen, Terra et Aqua magazine, The Hague; Julie Gentz, The Williams Companies, Inc., Tulsa; Stelios Kyriakides, The University of Texas at Austin; Domitille Lucereau, La Défense, France; Frank McWilliams, Tata Steel International, Sugar Land, Texas; and Matt Pond, Corrosion Resistant Alloys, Houston.Integriti Platinum, PIPESIM and RealView are marks of Schlumberger.

In response to maturing production in established onshore and shallow-water basins, many E&P companies are extending their quest for reserves toward deeper offshore prospects. Drilling and completion confirm prospect viability, then set the stage for platform construction and place-ment. Even after the wells are tied in to the plat-form, the job is far from finished.

Some method of transporting the product to market must be put in place. In developed areas supported by an established infrastructure, this often calls for installation of a few kilometers of export line to tie a platform to an existing pipe-line. In frontier areas, operators must either lay extensive pipeline systems over several kilome-ters, or rely on ships—typically shuttle tankers from a floating production, storage and offloading (FPSO) vessel—to move the product to a receiv-ing terminal. From there, it is usually piped to a refinery. Until a means of transport is available, hard-won reserves are simply stranded, and oper-ators must leave those reserves in the ground.

Pipeline companies strive to keep pace with E&P companies as they move deeper offshore. To do so, the pipeline industry must design and install pipeline systems that can push high-tem-perature, high-pressure fluids uphill over long distances in a deep, dark, high-pressure, low-temperature environment.

Even in the face of such challenges, the pipe-line industry continues to break records. In 2000, a 64-km [40-mi] pipeline laid to service the Hoover-Diana project in the Gulf of Mexico, reached water depths of 1,450 m [4,800 ft]. By 2005, the Blue Stream project had installed 386 km [240 mi] of twin pipelines in depths of 2,150 m [7,050 ft] in the Black Sea. In 2008, 206 km [128 mi] of pipeline at the Perdido Norte project was laid between the Alaminos Canyon and East Breaks areas of the Gulf of Mexico, in record depths ranging from 1,067 m to 2,530 m [3,500 ft to 8,300 ft]. The Galsi pipeline, slated for construction in 2011, will stretch beneath the Mediterranean Ocean from Algeria to Sardinia, and is expected to set a new depth record of 2,824 m [9,265 ft]. Distance records are also being set. Between 2004 and 2007, the Langeled gas pipeline was laid between Norway and England; at 1,173 km [729 mi], it is the world’s longest subsea pipeline.

Whether it sets a record or not, each pipeline has unique characteristics. Product chemistry largely dictates metallurgy, while pipeline length and depth gradients dictate operating pressures and flow rates, both of which in turn influence pipeline diameter and wall thickness. These design considerations have a direct bearing on operation and maintenance practices. This article provides a broad overview of offshore pipeline con-struction, operations and monitoring activities.

1. For more on infield pipeline systems: Amin A, Riding M, Shepler R, Smedstad E and Ratulowski J: “Subsea Development from Pore to Process,” Oilfield Review 17, no. 1 (Spring 2005): 4–17.

2. Codes and practices for subsea pipeline design, construction and inspection have been published by a number of technical institutes, such as the American National Standards Institute, American Petroleum Institute, American Society of Mechanical Engineers, Det Norske Veritas, Institution of Gas Engineers and Managers, and United Kingdom Offshore Operators Association. A listing of various international codes can be found in the UK Health and Safety Executive: “Use of Pipeline Standards and Good Practice Guidance,” http://www.hse.gov.uk/pipelines/resources/pipelinestandards.htm (accessed November 25, 2010).

3. Connelly M: “Deepwater Pipelines—Taking the Challenge to New Depths,” Offshore Magazine 69, no. 7 (July 1, 2009): 94–97.

4. MacPherson H: “Unique Challenges in Managing Deepwater Pipeline Integrity,” PetroMin Pipeliner 5, no. 3 (July–September 2009): 14–25.

5. KCI Publications (ed): “Clad Pipes: Growing Market Increasing Requirements,” Stainless Steel World 20, (January–February 2008): 18–21.

Spring 2011 5

Design ConsiderationsPipeline systems consist of all the pipe, valves, pumps, meters and facilities through which pro-duction streams are transported. These systems can be divided into distinct segments (above). Infield lines are relatively small-diameter pipe-lines (less than 16 in.) consisting of flowlines, gathering lines and risers, which run between the wellhead and the production platform or FPSO.1 The infield lines transport a raw, unrefined well stream, usually consisting of a multiphase mixture of gas, oil and water from oil wells; or the lines transport gas, natural gas liquids and water from gas wells. Export pipelines, also called trunklines or transmission or sales lines, generally consist of larger diameter pipelines (ranging from 16 in. to 44 in.) for transporting processed fluids to shore from one or more fields. The processed stream, having undergone separation and initial treatment aboard a production platform or FPSO, usually consists of oil with minor amounts of water, or of gas and condensate. These pipelines typically tie in to onshore pipelines that transmit the fluids to refineries located farther inland.

Pipelines are built in accordance with strin-gent codes and standards.2 Design requirements for subsea pipelines must account for a variety of factors, including projected length, water depth

and temperature, the composition and flow rate of fluids carried by the pipeline as well as the topography on which the pipeline will be laid. These factors will ultimately impact the pipeline costs, manufacturing processes, pipe-lay tech-niques and operating strategies.

Pipelines are designed to withstand the inter-nal pressures generated by a specified rate of flow. However, in deep waters, internal pressure concerns are secondary to the need for pipelines to withstand external collapse pressures imposed by water depth—especially during the installa-tion phase when no fluids are being pumped through the pipeline. Resistance to hydrostatic collapse is governed by the ovality and the com-pressive strength afforded by the pipe’s metal-lurgy and wall thickness.3 Thus, while internal pressure dictates pipe thickness in conventional settings, hydrostatic pressure is the dominant influence on thickness in deepwater pipelines.

While burst and collapse pressures are prime drivers, pipeline design must also consider other factors. A study of Gulf of Mexico pipelines showed that the single most significant cause of damage to pipelines is corrosion.4 The composition and tem-perature of fluids transmitted through a pipe can affect its susceptibility to internal corrosion, thus metallurgy becomes a significant design consider-ation—not only for strength but for offsetting the

threat of corrosion. Infield lines transport unpro-cessed fluids; these fluids may contain hydrocar-bons mixed with a corrosive blend of water, carbon dioxide, chlorides or hydrogen sulfide [H2S], often at elevated temperatures. And conditions gener-ally change over time as reservoir depletion alters the fluid mixture.

The pipeline industry has developed a variety of approaches to mitigate corrosion problems. Some pipeline designs increase pipe wall thick-ness to compensate for the expected loss of metal caused by corrosion. Others use corrosion-resis-tant alloys (CRAs). These alloys combine metals such as stainless steel, chrome, nickel, iron, cop-per, cobalt, molybdenum, tungsten or titanium. CRAs resist corrosion more effectively than car-bon-steel pipe, and are chosen based on their resistance to specific produced fluid properties. Although resistant to corrosion, CRAs may not have the tensile and compressive strength of carbon-steel pipe.

CRA cladding can be used to line the inside of the pipe. In such cases, the carbon-steel outer pipe withstands the internal and external pres-sure, while the alloy cladding provides corrosion protection.5 CRA selection must also take into consideration the strength, toughness and weld-ability of the alloy.

> Pipeline segments. Infield lines (pink) run from the wellhead to the platform or other preliminary gathering and processing facility. Export, or sales, lines (green) run downstream from the platform.

Wellhead

Gathering line

Manifold

Riser

Platform

6 Oilfield Review

In combination with corrosion-resistant met-allurgy, chemical inhibition is often employed to mitigate corrosion: This technique introduces chemical additives into the production stream to reduce the fluid’s corrosiveness.

Pipelines are susceptible to external corrosion—for subsea pipelines, the primary culprit is seawater, an efficient electrolyte that promotes aqueous corrosion. All metals and alloys in this environment are subject to corro-sion, depending on their individual electrical potential and the pH of the seawater. The electro-chemical reaction that causes corrosion can be mitigated to an extent by cathodic protection.6 However, with increasing depth, water tempera-ture falls, decreasing conductivity, hence decreasing the effectiveness of anodes intended to protect the pipeline.

In addition, design specifications must pre-clude biochemical reactions. Sulfate-reducing bacteria in marine silts generate H2S, which can attack pipelines; other organisms, such as lim-pets or barnacles, can rasp or bore into unpro-tected metals. To ward off the ravages of the subsea environment and extend the life of pipe-lines, fusion-bonded epoxy (FBE) or other exter-nal coatings may be employed in conjunction with cathodic protection (above).

Pipeline design must also thwart fatigue—progressive, localized damage caused by cyclic loading of the pipe. One form of cyclic loading can be caused by vortex-induced vibrations (VIVs) as water currents flow above and below unsupported pipeline spans. These freespans result as the pipeline crosses dips and valleys in the seabed terrain or as water currents scour and

erode the seabed beneath unburied pipelines. VIV suppression devices, such as helical fin strakes and fairings, can be used to protect freespans from hazards created by ocean cur-rents (below left).

Thermally induced stress is another problem. The flow of hot crude oil through a pipeline can result in metal expansion, which may cause the pipeline to shift position. In a straight line between two fixed and immobile points, such movement could result in catastrophic failure in the pipeline system. However, engineers can com-pensate for expansion and contraction by plan-ning a gently meandering pipeline that permits lateral movement along the line; this configura-tion can even dampen the effects of movement caused by earthquakes and mudslides.

Pipe ManufactureThe pipe used for building pipelines is known as line pipe. Most line pipe is made of carbon steel; often specific alloys are chosen to attain crucial mechanical and metallurgical properties, and stainless steel may be used on occasion.7 The mechanical property requirements for pipeline steel are very stringent, demanding high strength, ductility, toughness, corrosion resistance and weldability in a single grade of steel. Line pipe design properties are achieved by carefully regu-lating alloy chemistry and thermo-mechanical processing during production. Quality control is monitored throughout the production process, from the steel mill to the pipe yard.

Line pipe specifications often call for special-ized processes, from the casting of steel slabs to the subsequent rolling of the plates into strips that are shaped into the pipe. Much of the pro-cess is computer controlled, then checked by a comprehensive array of nondestructive tests, including ultrasonic, magnetic particle, and X-ray evaluations of thickness and welds.

Line pipe is either seamless or seam welded. Seamless pipe can be manufactured up to about 16 in. OD. The seam-welded variety is commonly manufactured in sizes ranging from 16 in. to 64 in. OD.

Most seamless pipe starts as cast ingots or bil-lets that are heated in a rotary hearth furnace, then pierced by a center punch. The pierced ingot goes to a pierce rolling mill where it is lengthened as its diameter and wall thickness are reduced. A mandrel is inserted in the annulus of the hollow ingot to hold and shape the ingot as it passes through a series of rollers and then is passed to a specialized mill to achieve exact pipe shape, thickness and diameter.

Pipe

Second coatingFirst coating

> Fusion-bonded epoxy coating. To protect pipe from corrosion and mechanical damage, epoxy resin coatings are electrostatically applied to the steel pipe. The resin is applied at temperatures up to 110°C [230°F]; it then hardens thermoplastically. Typical thickness ranges from 350 um to 450 um. A second layer may be applied for additional protection. (Illustration courtesy of EUROPIPE GmbH.)

> Pipe strakes. Water currents flowing past unsupported spans create eddies on the trailing side of the pipe (inset). As the vortices break away from the pipe, they set up vibrations that can cause the pipe to fail through cyclic loading. VIV strakes can be strapped to the outside of the pipe (yellow) to break up the flow of the water current, forcing vortices well beyond the pipeline. (Illustration courtesy of Mark Tool & Rubber Co. Inc.)

Water current EddiesPipe

Spring 2011 7

Seam-welded pipes start with coils of steel, which are split into widths that conform to the requisite pipe diameter. They are then rolled and pressed to form plates of specific size and thick-ness. The plates are cold formed to create a tubu-lar shape whose seam is welded shut to create the pipe.

Finished pipes are subjected to hydrostatic testing, followed by a variety of mechanical tests that measure hardness, tensile strength and other properties. To protect against corrosion, the line pipe may be coated with a layer of epoxy. Each pipe is then individually numbered and issued a certifi-cate that documents its metallurgy, physical prop-erties and manufacturing history.

Pipeline RoutingSubsea pipeline routing must account for local geography and the attendant vagaries of mete-orologic and geologic hazards presented by hur-ricanes, tsunamis, subsea earthquakes, mudslides, strong currents and erosion. Pipeline routing has a direct bearing on the cost and feasibility of any production project. The route is ultimately a com-promise that considers:

-line while reducing the need for presweeping of rock or debris that could damage the pipeline

freespan remediation8

Pipeline route selection involves far more than simply running a straight line between two points. Route design must consider the topography and stability of the sediments on which the pipeline is to be laid, its impact on benthic communities, the effects of shipping, fishing, drilling and construc-tion activities and the presence of existing pipe-lines that may cross the path of the proposed pipeline.9 Furthermore, routes may be influenced by uneven or rugged seafloor topo graphy, which increase the potential for freespans and failure from VIV or bending stress (above right). Uneven terrain also contributes to severe terrain-induced pressure fluctuations as hydrocarbons are pumped up and down steep slopes.10

Long before a potential route is surveyed, a preliminary desktop survey is carried out. The desktop evaluation maps geopolitical boundaries, existing pipelines, offshore structures, environ-mentally sensitive areas, archeological sites, restricted areas and known geologic or oceanic hazards that may lie between the pipeline’s pro-posed starting point and its landfall. It lays out prescribed seabed coring intervals, and indicates

where bottom conditions or routing require-ments call for additional sediment samples. This preliminary assessment is instrumental in devel-oping a proposed pipeline route, identifying areas that require more-detailed evaluations and determining how the subsequent preinstallation survey will be conducted. Thus, for example, when a desktop assessment identifies a known ordnance dumping zone near the pipeline route, it would call for a visual survey to be conducted using a remotely operated vehicle (ROV).

Next, a seafloor survey contractor conducts a preinstallation survey and maps the locations of any shallow hazards, seafloor obstructions, archeological evidence and benthic communities along the proposed route. The preinstallation survey covers a wide swath, which includes an offset on either side of the proposed pipeline path to cover areas that pipe-lay barge anchors might disturb. This swath also creates a margin for fine-tuning the proposed route without need for resurveying each adjustment. In deep water, the standard swath is about 760 m [2,500 ft] wide.

The surveys assess geologic and man-made features on the seafloor and in the shallow sub-surface. Seafloor geologic hazards include boul-ders, fault scarps, gas vents, reefs and unstable slopes; subsurface geologic hazards include gas-charged sediments, abnormal pressure zones and buried channels. Man-made obstructions include pipelines, wellheads, shipwrecks, ordnance, com-munication cables, wellheads and debris from previous oil and gas activities.

Surveys play an important role in protecting the marine environment. They are useful in iden-tifying high-density accumulations of deepwater benthic inhabitants such as chemosynthetic communities, corals and hardbottom communi-ties. Chemosynthetic communities, in particular, are unlike most other life on Earth. They utilize chemical energy from hydrocarbons and create colonies of unusually high biomass compared with the surrounding sea bottom.11 These commu-nities are thought to be closely linked with geo-logic faults, natural hydrocarbon seeps and hydrocarbon-charged sediments.

6. Cathodic protection is a technique used to minimize the rate of corrosion of a pipeline or other metal structure. This technique does not eliminate corrosion; rather, it transfers corrosion from the protected structure to sacrificial anodes (plates or metal bars) that can be replaced. Cathodic protection relies on the electro-chemical nature of corrosion, whereby electrical current is discharged through sacrificial anodes that corrode instead of the pipeline.

7. Kyriakides S and Corona E: Mechanics of Offshore Pipelines, Volume I: Buckling and Collapse. Amsterdam: Elsevier, 2007.

8. Bai Y and Bai Q: Subsea Pipelines and Risers. Amsterdam: Elsevier, 2005.

9. Benthic communities consist of organisms that live near or on the bottom of a body of water.

10. Cranswick D: “Brief Overview of Gulf of Mexico OCS Oil and Gas Pipelines: Installation, Potential Impacts, and Mitigation Measures,” New Orleans: US Department of the Interior Minerals Management Service, OCS Report MMS 2001-067, August 2001.

11. MacDonald IR (ed): “Stability and Change in Gulf of Mexico Chemosynthetic Communities. Volume II: Technical Report,” New Orleans: US Department of the Interior, Minerals Management Service, OCS Study MMS 2002-036, 2002.

> Freespan. Uneven topography or seabed erosion by water scouring beneath a pipeline can cause freespans. To prevent pipeline problems associated with freespans, the low areas may be filled in with rock using vessels designed especially for this purpose.

Freespan

8 Oilfield Review

For their protection, bottom-dwelling com-munities generally require buffer zones of several hundred feet. Benthic dwellers can be adversely affected by pipe laying and attendant anchor-handling activities. Beyond the actual impacts of pipeline touchdown, anchors and associated ground tackle, there is also potential harm

caused by disturbance and resuspension of sedi-ment resulting from these activities. Survey results can be helpful in planning buffer zones. Government approval of pipeline permits is con-ditioned largely on what a seafloor survey reveals.

Surveys scrutinize the seafloor using a variety of instruments prescribed by government regula-

tion. Survey instrumentation is keyed to a differ-ential GPS navigation system to ensure positioning integration of the various data. Generally this instrumentation includes, at a minimum:

pipelines and other ferromagnetic objects

that permit detection and evaluation of seafloor objects and features within the survey area

determine the character of near-surface geologic features within the upper 15 m (50 ft) of sediment

echosounders for continuous water depth mea-surements, with multibeam backscatter data providing seabed textural information.

Follow-on investigations often involve under-water cameras, video, coring or additional geo-physical survey lines.

Should any of these instruments indicate the presence of shipwreck debris or concentrations of man-made objects such as bottles, ceramics or piles of ballast rock, the discovery will prompt an imposition of a buffer zone and cessation of fur-ther operations to prevent the site from being disturbed. Archeological discoveries require immediate notification of government authorities who will assess the site for its potential historical significance. Thus, surveys, by providing a means of detecting geohazards, benthic communities and archeological sites, allow pipeline operators to make adjustments along the proposed route to preclude damage of both the environment and the pipeline.

Pipeline Fabrication and ConstructionThe pipeline industry’s migration from shallow to deep water is exemplified by changes in vessel design and capabilities. Just as drilling rigs have evolved to handle greater water depths, pipe-lay vessels have followed a similar progression, from shallow-water lay barges to deep-draft ships and semisubmersibles.

Lay barges have long been employed for pipe-line installation in relatively shallow waters of the Continental Shelf. Early barges were conven-tionally moored and relied on multiple anchors—often 12 or more, depending on the size of the vessel (above left). As the pipe string was paid out over the stern, the vessel moved forward by reel-ing in anchor chain at the bow while easing it out over the stern. Once all the anchor chain was paid out, an anchor-handling vessel reset the anchors before the pipe-lay vessel advanced. Long anchor chains, however, decrease station-keeping precision, thus the depth in which con-

> Shifting anchors. A conventionally moored lay barge pays out pipeline over the stern as it advances by winching ahead on its forward anchors and easing out anchor chain at the stern. Some anchors, especially the lateral anchors, may be dragged sideways in the process, and eventually all anchors will be reset by an anchor-handling vessel.

Stern anchor

Chain

Anchor

Direction of travel

Bow anchors

Lateral anchors

Laid pipeline

> S-lay vessel. The Allseas Solitaire, the largest pipe-lay vessel in the world, is 300 m [984 ft] in length overall, excluding stinger. This vessel is capable of laying pipe from 2 in. to 60 in. OD, and has a holding force of 1,050 t, enabling it to lay the heaviest of pipelines. The framework extending over the stern controls the angle of the stinger, shown raised above the water (inset). (Photographs courtesy of Allseas.)

Spring 2011 9

ventionally moored lay barges can be used is limited to around 1,000 ft [305 m].12

Deep waters call for pipe-lay ships or semi-submersibles that employ dynamic positioning for station keeping. These vessels use multiple thrusters—propellers that swivel azimuthally to create opposing thrusts—to maintain their desired position. The dynamic positioning systems are usually driven by a computer system linked to a satellite-based geographic positioning system. Dynamic positioning requires significantly more fuel than conventional mooring, but increases the efficiency of the pipe-lay operation.13

Pipeline design—particularly diameter, thick-ness and metallurgy—dictates the maximum tension, compression and bending stresses that a pipe can sustain during installation. Likewise, to avoid stress limits that could cause the pipe to buckle during installation, the choice of installa-tion technique is crucial. The selection is largely governed by water depth; the most common are the S-lay, J-lay, pipe-reel and tow-in techniques.

The S-lay technique—so designated because the pipeline assumes an elongated S-shaped profile as it is lowered from the vessel to the seafloor—was originally developed for relatively shallow waters. An S-lay vessel is distinguished by a long stinger, a truss-like structure, which is equipped with rollers and a tensioner (previous page, bottom). The stinger is mounted off the stern to support the pipe as it leaves the vessel. On an S-lay vessel, individual joints of line pipe are laid out horizontally, welded together, X-rayed or ultrasonically inspected and coated with FBE as the pipeline is built on deck.

Stinger configuration affects the bending stresses that occur as the pipe is lowered to the seafloor. The pipe departs the stinger at the liftoff point, and contacts the seabed tangentially at the touchdown point (above right). The pipe experi-ences the greatest stresses at the overbend, where the pipe leaves the vessel, and in the sagbend, which extends upward from the pipeline touch-down point on the seafloor. The curvature of the overbend is controlled by the rollers on the stinger; sagbend curvature is controlled by the tensioner and vessel positioning.14

The S-lay method has evolved for operations in ultradeep waters through modifications of the stinger and tensioner system.15 Deep waters require a steep liftoff angle to accommodate the overbend segment, which can be achieved by a longer and more curved stinger. To date, this method has been used in waters as deep as 8,960 ft [2,731 m], and on such projects, the stinger length can easily exceed 450 ft [137 m].16

The J-lay method was developed for laying pipe in deep waters. J-lay vessels are distin-guished by a near-vertical fabrication tower (below). Lengths of pipe are positioned at the

uppermost station of the tower, where they are vertically joined together at automated welding stations. The pipe is then lowered to an ultra-sonic inspection station and a field coating sta-tion before it passes through the moonpool and into the water.17 On some vessels, a short stinger extends beneath the hull to support the pipe string, which takes on a J-shaped profile as it contacts the seabed. This profile puts less bend-ing stress on the pipe string in deep waters. However, the J-lay method becomes impractical for shallower waters, where depths of less than 200 to 500 ft [61 to 152 m] limit the shape of the

12. Cranswick, reference 10. 13. Kyriakides and Corona, reference 7.14. Kyriakides and Corona, reference 7.15. Kammerzell J: “Pipelay Vessels Survey Expands to

Include Worldwide Fleet,” Offshore Magazine 69, no. 11 (November 2009).

16. Flowlines from Cheyenne field, set in 8,960 ft [2,731 m] of water, were laid to the Independence Hub platform at Mission Canyon Block 920 in the Gulf of Mexico.

17. A moonpool is an opening in the vessel hull designed to permit the passage of equipment between the deck and sea. A moonpool may be found on reel-lay vessels and on certain J-lay vessels.

> S-lay configuration. Bow and stern thrusters hold the pipe-lay vessel in position while the pipeline is lowered onto the seabed. A long stinger projects from the stern, and its configuration controls the angle between the liftoff and touchdown points. (Illustration courtesy of Allseas.)

ThrustersStinger

Pipe overbend

Pipe sagbend

Touchdown point

Liftoff point

> J-lay configuration. Pipe is raised to the top of the vertical tower, and travels through welding, ultrasonic inspection and field-coating stations as it is lowered toward the water. The J-lay method is suitable for deep water because the pipeline is bent only once—at the seabed—and thus experiences less stress during installation. The J-lay method is less suitable for shallow waters because it imposes a bend that the pipe cannot accommodate. (Adapted from Kyriakides and Corona, reference 7.)

Touchdown point

Pipe sagbend

Suspendedpipe

Thrusters

Tensioners

Field coating

Welding station

10 Oilfield Review

pipe angle and impose severe bending stresses on the pipe.

Pipeline installation is also carried out by reel ship. At an onshore spoolbase, long sections of rigid steel pipeline, each about 1 km [0.62 mi] long, are welded together (above). The welds are inspected and coated with a resilient protective coating of flexible epoxy or polyethylene, then the pipe is spooled aboard a vessel-mounted reel. After reeling the pipe on board, the ship departs for the pipe-laying area.

There, the pipe is fed off the reel, straight-ened and anchored to the seabed. In deep waters, the pipe may need to be tensioned to minimize sag that would otherwise develop as the pipe is lowered from the surface to the seabed. If the sag bend becomes too severe, the pipe will buckle.

The ship then steams ahead at about one knot [1.85 km/h, or 1.15 mi/h], depending on weather conditions, as it slowly reels out the pipe. When all pipe has been led off the reel, a bull-plug is welded in place to seal the end of the pipe, then it is lowered to the seabed. A buoy is attached to mark the end of the pipe. The ship then proceeds to port to replenish the reel or to take on a new, fully loaded reel. Upon returning offshore, the end of the previous pipeline is retrieved from the seafloor, welded to the new line, and the process is repeated.18

A fourth approach, called the tow-in method, is used typically for insulated pipe-in-pipe or bundled pipe assemblies. This method first calls for welding, inspection, joint coating and anode installation at an onshore fabrication facility. The assembled pipe is then placed in the water and submerged. Buoyancy tanks and chain weights are usually attached to achieve neutral buoyancy. Seagoing tugboats or offshore support vessels then tow the pipe along a tightly controlled route that has been surveyed to identify potential sea-floor hazards.

The main advantages of the tow-in method are that it permits complex or specialized fabrication techniques to be carried out in controlled condi-tions at facilities ashore. However, the length of the pipeline is also constrained by the space limitations of the fabrication facility.19 This method is especially suitable for bundled pipe-lines, where several pipe sections or umbilicals are tied together and shrouded within a carrier pipe. However, the tow-in method carries increased risk that the pipeline could be damaged through contact with a submerged obstruction.

A combination of techniques may be employed over the course of the pipeline installation, par-ticularly if water depths change drastically along the proposed route. Perhaps the most challeng-ing problem arises when an offshore pipeline

makes landfall and must be installed in the often treacherous zone between land and sea.

To address the issue, a cofferdam can be extended from the beach for hundreds of feet, into near-shore waters. A dredge deepens the seaward approach to enable a pipe-lay vessel to reach the cofferdam. The cofferdam provides a stable framework in which a concrete conduit can be buried well below the depth of the existing beach floor.

This approach was used to land the Langeled pipeline at Easington, on the east coast of England (next page). The 44-in. gas line approaches shore in a pre-excavated offshore trench, dredged some 12 mi [20 km] from shore, starting in water 120 ft [37 m] deep. As required in shallow waters, to prevent anchor, trawl and dropped-object dam-age, the 6.5-ft [2-m] deep trench was backfilled to bury the pipeline. For the shore crossing, a temporary causeway had to be constructed dur-ing low tides using land-based heavy construction equipment. This causeway provided access through the intertidal zone for construction of a 787-ft [240-m] long sheet-piled cofferdam, built alongside the causeway. Starting at a tie-in pit located inland from the high-water mark, the cof-ferdam extended from the beach 200 ft [60 m] beyond the low-tide level.20

An unstable cliff face stood between the beach and a gas terminal. A tunnel-boring machine cre-ated a 1,247-ft [380-m] long concrete tunnel that provided a conduit through the cliff to permit access between the gas terminal, tie-in point and cofferdam. The tunnel and cofferdam were com-pleted in advance of the lay barge arrival. A 500-t winch was then used to pull the pipeline from the lay barge into the tie-in pit, and the pipe was tied in 43 ft [13 m] below the low-tide level. Pipe welds were inspected and coated as the offshore pipe-line was tied in to the onshore line. Once the tun-nel and pipeline were safely buried, the causeway and cofferdam were removed and the site was restored to its natural state, providing no visible evidence of landfall for a pipeline that carries nearly 20% of the UK’s demand for natural gas.

Operations and MaintenanceDeepwater pipelines operate in low water temperatures under high hydrostatic pressures. Despite this hostile setting, the life span of most pipelines is 20 to 40 years, in part because corrosion management strategies and attentive pipeline monitoring are helping to increase their longevity.

> Spoolbase. The Technip spoolbase near Mobile, Alabama, USA, is capable of handling and welding pipe up to 18 in. OD for reel lay. The fabrication building houses two independent welding lines with alignment, welding, nondestructive examination and field joint coating stations. Technip’s Deep Blue pipe-lay vessel, docked at the end of the queue (upper left), is reeling aboard pipe. The vessel (inset), is 677.5 ft [206.5 m] long, and is equipped with twin reels, 131 ft [40 m] in diameter, each capable of carrying 2,800 t of rigid pipeline ranging from 4 in. to 18 in. OD. Flexible pipeline can be carried below deck. (Graphics courtesy of Technip USA Inc.)

Reels

ThrustersMoonpool

DEEP BLUE

Spring 2011 11

A chief concern for deepwater pipeline engi-neers is the formation of solid compounds, such as asphaltenes, hydrates and wax.21 Under certain conditions, these compounds can increase fluid viscosity and restrict flow within pipelines. Pressure, temperature, fluid composition, pipe surface, flow regime, and shear can affect the deposition of waxes and asphaltenes. To precisely understand how these individual parameters affect deposition inside pipelines, Schlumberger engineers have developed a testing cell.

The RealView live solids test cell measures oil deposition in turbulent flow, with temperature control from 4°C to 150°C [39°F to 302°F] and pressure adaptability to 103 MPa [15,000 psi]. This deposition cell is suitable for testing sour, H2S-entrained fluids. In closed batch mode, the cell requires a sample volume of only 150 ml [9.15 in.3] per test run, but can accept up to one liter [61 in.3] for flow-through testing. The

RealView test cell consists of a cylindrical vessel with an axially centered heat source. The outer wall of the vessel is stationary, and the inner wall, or spindle, rotates to create either a turbulent or laminar flow regime in the annular space.

Controls on this live solids deposition cell enable precise and independent regulation of pressure, temperature, differential temperature and spindle speed. The deposits are collected and then quantified using high-temperature gas chromatography for wax deposit analysis. Simulated distillation, a technique that uses gas chromatography to simulate the distillation pro-cess in the laboratory, is employed for asphaltene deposit analysis. Deposit mass is then used to calculate a deposition rate. RealView live solids deposition studies can help operators evaluate the effects of chemical additives on deposits under representative conditions. The RealView experimental data can also be used in commer-cial software such as PIPESIM production system

analysis software to build wax- and asphaltene-deposition simulations. Armed with these results, operators can fine-tune flow rates in their pipe-line system, determine how frequently remedial procedures need to be conducted and select the optimal chemical treatment and dosage.

18. Kyriakides and Corona, reference 7.19. As of 2007, the maximum length of towed-in pipeline was

7 km [4.35 mi]. Kyriakides and Corona, reference 7.20. Vercruysse W and Fitzsimons M: “Landfall and Shore

Approach of the New Langeled Pipeline at Easington, UK,” Terra et Aqua 102 (March 2006): 12–18.

21. For more on asphaltenes: Akbarzadeh K, Hammami A, Kharrat A, Zhang D, Allenson S, Creek J, Kabir S, Jamaluddin A, Marshall AG, Rodgers RP, Mullins OC and Solbakken T: “Asphaltenes—Problematic but Rich in Potential,” Oilfield Review 19, no. 2 (Summer 2007): 22–43.

Hydrates are discussed further in: Birchwood R, Dai J, Shelander D, Boswell R, Collett T, Cook A, Dallimore S, Fujii K, Imasato Y, Fukuhara M, Kusaka K, Murray D and Saeki T: “Developments in Gas Hydrates,” Oilfield Review 22, no. 1 (Spring 2010): 18–33.

> Langeled pipeline landfall. The dredging vessel J.F.J. De Nul deepens the seaward approach toward a cofferdam extending from the beach. A temporary sand causeway provides access to the cofferdam, which has been constructed of metal pilings situated on the right-hand side of this causeway. The cofferdam stretches beyond the intertidal zone. (Photograph courtesy of Terra et Aqua magazine.)

12 Oilfield Review

Some pipelines require insulation or heating to meet proper thermodynamic conditions. Many pipelines rely on chemical injections of inhibitors or solvents, such as ethylene glycol, tri-ethylene glycol or methanol. Operators also routinely resort to a mechanical approach to remove build-ups from their pipelines.

Pipeline inspection gauges, or pigs, are plunger-like devices that clean the inner walls of the pipeline. Pigs are available in various sizes, shapes and materials, ranging from metal pipe scrapers and flexible brushes to plastic foam spheres. Most have an outside diameter nearly equal to the inside diameter of the pipe to ensure a fairly tight fit. Some pigs are equipped with sen-sors (above). These “smart pigs” are even capa-ble of detecting internal corrosion or locating leaks in pipelines.22

A pig is forced through the pipeline by exert-ing pressure on a gas or liquid to the back, or upstream end, of the pig. As the pig travels down-stream, it scrapes the inside of the pipe and sweeps any accumulated buildup or liquids ahead of it. These are collected, along with the pig, at the end of a segment of pipe known as a pig trap.

Routine pigging operations remove deposits in the pipe as a normal part of production opera-tions. The frequency of pigging varies with flow rates, operating temperatures and nature of the produced fluid, and may be carried out on weekly, monthly or less frequent intervals.

Monitoring at the Speed of LightOperators monitor the integrity of pipelines to ensure their continued performance, protect the environment and prevent product loss. There are two approaches to monitoring pipelines. Periodic inspection and surveying use mobile units such as pigs, ROVs or autonomous underwater vehicles (AUVs). Continuous monitoring involves perma-nently installed leak detection sensors.

A variety of sensor technologies has been adapted for subsea pipeline monitoring.23 These include the following:

dielectric constant of the medium surrounding the sensor. The capacitor is formed by two concentric, insulated capacitor plates. The sensor’s capacitance is directly proportional to the dielectric constant of the medium between the capacitor plates. Because the dielectric constants of seawater and hydrocarbons differ, direct contact with hydrocarbons will register as a change in measured capacitance.

excite molecules in the target material to a higher energy level. When those molecules

relax to a lower state, light is emitted at a dif-ferent wavelength, which is measured by a fluo-rescence detector.

drop between two or more pressure sensors installed in the pipeline.

-solved methane through a membrane and into a sensor chamber, where the dissolved meth-ane changes the electrical resistance, which generates a signal from the detector. A varia-tion on this method uses optical nondispersive infrared spectrometry. Using this method, the methane concentration is measured as the degree of absorption of infrared light at a cer-tain wavelength, in which the intensity of infra-red light at the detector is a measure of the methane concentration.

measure the pressure of a sound wave gener-ated by a rupture or leak as it is transmitted through a structure or water. By using more than two sensors to measure the arrival time of sound, it is possible to triangulate on the origin of the sound.

are reflected by impedance changes between different media. The impedance depends on sound velocity, density, salinity and tempera-

such as water and hydrocarbons, will have different acoustic impedance.

subsea system. Ideally, a monitoring system would continu-

ously detect and locate conditions that might forewarn operators of potential troubles any-where along the pipeline, then combine and interpret the outputs of multiple measurements in a meaningful, prioritized display. These capa-bilities have been incorporated into fiber-optic monitoring systems that are being installed in offshore and onshore pipelines worldwide.

Optical-fiber sensors have an established track record of reliability, and distributed tem-perature sensors (DTS) have been in use since the mid-1980s. This type of sensor uses the opti-cal fiber itself as both the sensing element and the data highway back to the controller. These sensors are based on optical time domain reflec-tometry (OTDR), a proven technique long used in the telecommunications industry. DTS systems are able to make precise temperature measure-ments every few meters along the optical fiber for distances up to 100 km [62 mi]. More-localized measurements use a technology known as fiber Bragg gratings, which performs highly precise

22. Cranswick, reference 10.23. Det Norske Veritas: “Selection and Use of Subsea Leak

Detection Systems,” Høvik, Norway, Recommended Practice DNV-RP-F302, April 2010.

24. For more on fiber-optic DTS: Brown G: “Downhole Temperatures from Optical Fiber,” Oilfield Review 20, no. 4 (Winter 2008/2009): 34–39.

> Smart pig. Pipeline inspection gauges were originally created to remove internal buildup and maintain flow. Modern pigs are sophisticated devices that closely measure a pipe’s internal surfaces, weld integrity, state of cathodic protection and corrosion. Using magnetic flux leakage and ultrasonic testing technology, this pig can detect metal loss and pipeline wall features in a single inspection run. This device runs in 16-in. pipelines and is approximately 3.6 m [11.8 ft] long. (Photograph courtesy of ROSEN Group.)

Spring 2011 13

measurements of parameters such as strain and temperature using optical gratings inscribed in the core of the optical fiber.24

The Integriti Platinum fully integrated pipe-line monitoring system uses fiber-optic technol-ogy to help pipeline operators monitor conditions along the length of the pipeline. Continuous tem-perature, strain and vibration measurements enable the detection of a wide range of events that may threaten a pipeline’s integrity. This fiber-optic system uses variations on the DTS theme: Distributed strain temperature sensors (DSTSs) have been developed for monitoring strain; distributed vibration sensors (DVSs) mea-sure vibrations or acoustic signals along the opti-cal fiber. The Integriti Platinum system can measure temperature variations of 2°C [3.6°F] across 100 km of pipeline and measure strain with a resolution of 40 microstrain at 10-m [33-ft] intervals. The integrated sensors can detect and locate small pipeline leaks that are below the threshold of traditional leak detection systems based on pipeline flow rate—typical gas leak response time is just 30 s. The system can be used for a number of monitoring applications.

Onshore pipeline operators have used the DVS capability to detect the approach of heavy equipment, thus warning of digging and con-struction activity taking place near their pipe-line. The vibration sensors are sensitive enough to detect human foot traffic. Offshore or onshore gas leaks may initially be detected by DVS, which identifies the characteristic noise of escaping high-pressure gas and issues an alert. This event can be followed by DTS or DSTS detection of localized Joule-Thomson cooling. Fluid leaks and flow assurance problems are detected by the tem-perature anomalies sensed by DTS or DSTS. Ground movement or pipeline strains affect optical-fiber strain and can be detected by fiber Bragg gratings or DSTS.

DTS technology is being used by Total in the Dalia field, offshore Angola (above right). One of the challenges for Total in developing this deepwa-ter field was to maintain the flow of produced flu-ids in the integrated production bundle (IPB) risers. The temperature of the relatively viscous oil (21 to 23 degrees API) is 45°C to 50°C [113°F to 122°F] when it leaves the reservoir. After reaching the seabed, where the water temperature is only 4°C [39°F], the fluid is piped 1,650 m [5,413 ft] to the FPSO facility through the IPB risers.

Accurate temperature monitoring in the bun-dles is essential for flow assurance. If the tem-perature in the risers falls below a critical level, waxes and hydrates may form and cause block-ages, which result in costly downtime. Successful

transfer requires that produced fluids arrive at the FPSO facility at a temperature greater than 34°C [93°F]. Even in the event of a shutdown, the fluid temperature must be maintained above 21°C [70°F].

To accommodate the optical fiber, each of the eight riser bundles was constructed with a stain-less steel tube that spirals around the bundle from surface to seabed then doubles back to surface to form a long loop. After the IPBs were installed off-shore, Schlumberger engineers pumped optical fiber into one end of the spiral tube to convey it down to the seabed and back to the FPSO.

The double-ended optical system interrogates the fiber from both ends of the loop. This method provides more precise temperature measure-ments than single-ended systems. Accurate, real-time readings are recorded at 1-m [3.3-ft] intervals along the length of the riser bundle. In the unlikely event of fiber breakage, each portion of fiber will continue to function as a single-ended system, which provides some redundancy until a new replacement fiber can be pumped down. A customized graphical user interface dis-plays the normal operating temperatures of the production pipe and the gas lift tubing, and alarms indicate the location of any temperature deviation. As well as helping to avoid blockages, the fiber-optic system facilitates efficient man-agement of the electrical heating system.

A different type of temperature challenge awaited Statoil at Gullfaks field in the North Sea, where production from satellite wells is con-nected to platforms by long subsea flowlines. To avoid blockages, the lines are heated above the critical temperature for wax and hydrate

deposition. However, operating at higher-than-necessary temperature is inefficient and wastes energy. As conditions vary along the flowline, knowledge of the temperature at every point along the production bundle is invaluable for flow assurance and minimizing energy consumption.

A condition monitoring system allowed Statoil to observe temperatures in the bundles so they could be efficiently operated just above the criti-cal temperature. The first system was installed in a 14-km [8.7 mi] flowline bundle comprising two flowlines, three hot-water heating lines, and a small-diameter conduit, all in an insulated sleeve. After the flowline bundle was installed and connected to the Gullfaks C platform, Schlumberger operators pumped a continuous fiber-optic temperature sensor down the conduit. This technology has helped to optimize operation of the heating system and reduce the amounts of wax and hydrate inhibitors required. The system helps minimize disruptive pigging operations to clear blockages, and when temperature anoma-lies resulting from extreme flow and pressure changes at restrictions in the flowline are detected, the system data can help optimize the pigging operations required to clear any block-ages, thus saving money and reducing downtime.

These monitoring systems make up just a frac-tion of the highly evolved and specialized tech-nologies required to install and operate a subsea oil and gas transmission system. Far from being dumb iron or brute, insensitive conduits, each subsea pipeline is, by necessity, formed of special-ized metallurgy, fabricated with great care, laid with utmost attention to subsea pressure and stress, and attentively monitored. —MV

> Dalia field production system. This field, operated by Total, is located 135 km [84 mi] off the coast of Angola in waters ranging from 1,200 m to 1,500 m [3,940 ft to 4,920 ft] in depth. Production from three main reservoirs is routed through infield lines and risers to an FPSO at the surface. (Illustration courtesy of Total.)

14 Oilfield Review

Managed Pressure Drilling Erases the Lines

For generations, prudent drilling engineers have maintained mud density in a well

such that its hydrostatic pressure was greater than the pore pressure of the formations

being drilled. Engineers today are learning the benefits of managing pressure at the

surface to manage drilling conditions downhole, thereby pushing back the limits

once imposed on them by wellbore stability and formation-fracture pressures.

Dave ElliottShell E&P The Hague, The Netherlands

Julio MontilvaShell E&PHouston, Texas, USA

Paul FrancisThe Hague, The Netherlands

Don ReitsmaJaye SheltonHouston, Texas

Vincent RoesTalisman EnergyCalgary, Alberta, Canada

Oilfield Review Spring 2011: 23, no. 1. Copyright © 2011 Schlumberger.For help in preparation of this article, thanks to Sonny Espey, Paul Fredericks, Wayne Matlock, Marie Merle, Mike Rafferty, Roger Suter and Eric Wilshusen, Houston.HOLD is a mark of Schlumberger.AUTOCHOKE and WARP are marks of M-I L.L.C.

Drilling operations exist in a world circum-scribed by high and low pressures. The unex-pected appearance of either can lead to delays, increased costs and even to failure. With increas-ing frequency, operators are arming themselves against the consequences of pressure-related surprises with techniques different from those used in the past. One such departure from tradi-tion is called managed pressure drilling (MPD).

Traditional drilling practices rely on main-taining hydrostatic pressure in the annulus to prevent formation fluids from entering the bore-hole. Ideally, when drilling fluid, or mud, is circu-lated down the drillstring and up the annulus, an equivalent circulating density (ECD) is created

that is greater than pore pressure, but is below the pressure necessary to fracture the formation being drilled.1 This pressure is often referred to by drilling experts as the fracture gradient. The pressure range above pore pressure and below fracture initiation pressure is the drilling margin, or pore-pressure–fracture-gradient window. If at any point the ECD goes outside these bounds, operators must set casing and begin drilling the next, smaller hole size.

The practice of maintaining a borehole pres-sure that exceeds the pore pressure gradient is called overbalanced drilling (OBD). It has been the method of choice for the majority of wells drilled since the early 20th century. But OBD has

Spring 2011 15

its drawbacks. Foremost among them is its dependence on the use of multiple casing strings to prevent fluid losses as the fluid density required to contain formation pressure is increased and ECD approaches fracture initia-tion pressure. In some instances, particularly in wells in ultradeep water, pore pressures may be high relative to formation strength even in the shallower sections of the well, which forces the operator to set numerous casing strings before reaching the target formation. The result can be a well whose diameter at TD may be too small to accommodate production tubing large enough to produce economic volumes of hydrocarbons (right). Additional strings of casing usually raise the final cost of the well significantly above ini-tial estimates.

Besides these considerations when drilling overbalanced, mud filtrate and mud solids can cause damage to the formation. When solids invade and are deposited in pore spaces, they may impair productivity and lower ultimate recovery. In addition, high overbalance during drilling can cause differential sticking and other problems related to hole cleaning.2 Efforts to free stuck pipe routinely result in hours or even days of NPT. In the worst cases, particularly in the presence of other aggravating conditions, such as cuttings beds packing around it, the drillstring may become permanently stuck and the hole may be lost or require a sidetrack (below, right).

The drilling fluids industry has developed chemical additives and practices to reduce the severity and frequency of mud-induced formation damage and stuck pipe. But in the 1980s, as oper-ators drilled horizontal sections to expose enough formation to make their wells profitable, they found it impossible to maintain ECD below the fracture gradient. That is because while the frac-ture gradient increases with TVD, it remains vir-tually unchanged from the heel to the toe of horizontal wells; however, as the wellbore length-ens, friction pressure losses increase. Pump pres-sure must then be increased to maintain

1. ECD is the effective density exerted by a 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 (psi) in the annulus between depth D and surface, and D is the true vertical depth (feet).

2. Differential sticking occurs when the drillstring cannot be moved (rotated or reciprocated) along the axis of the wellbore. Differential sticking typically occurs when high-contact forces caused by low reservoir pressures, high wellbore pressures, or both, are exerted over a sufficiently large area of the drillstring. The sticking force is a product of the differential pressure between the wellbore and the reservoir and the area that the differential pressure is acting upon. This means that a relatively low differential pressure applied over a large working area can be just as effective in sticking the pipe as can a high differential pressure applied over a small area.

> Conventional drilling. In response to increased pore pressure (kicks) in zones A and B when drilling overbalanced, the ECD (blue line) is increased by raising mud density, which causes BHP to approach the fracture initiation pressure (purple line). In response, a casing string must be set to protect the formation, which can result in additional casing points and subsequent narrowing of the wellbore diameter (black triangles). In deepwater wells, the window between fracture initiation pressure and pore pressure is often very narrow. In this instance, the operator was forced to set six increasingly smaller–ID casing strings, which resulted in a borehole too small to accommodate economic volumes of oil and gas.

Fracture initiation pressurePressure gradients

lbm/galUS

Resistivity pore pressure estimateSeismic pore pressure estimate

ECD

Zone A

Dept

h

Zone B

Kick

Kick

20-in.

16-in.

13 3/8-in.

113/4-in.

9 5/8-in.

7-in.

10 11 12 13 14 15 16 17

> Cuttings beds. Though they may occur in any well configuration, beds of cuttings, or solids (light brown), are particularly prevalent in deviated wells where cuttings and cavings settle to the low side of the hole. When the pumps are shut off, the BHA may become stuck in these beds as cuttings and cavings (not shown) slide down the annulus and pack off the drillstring. This phenomenon, known as avalanching, may also occur while pumps are on.

Cutting beds

16 Oilfield Review

sufficient circulation rates to lift cuttings to the surface via the annulus. Given sufficient length along a horizontal section, the ECD will result in a bottomhole pressure (BHP) that equals and then exceeds the fracture initiation pressure, with inevitable unacceptable levels of fluid loss.

In wells or sections of wells with very narrow drilling margins, operators have addressed the issue of fluid loss through underbalanced drilling (UBD), during which ECD is kept below the pore pressure of the formation being drilled. As a con-sequence, fluid from exposed formations are allowed to flow into the wellbore during drilling operations. This prevents drilling fluids from entering even underpressured zones.

But as the industry honed its ability to drill very long extended-reach wells, it was met with challenges other than fluid loss. Operators encountered various pressure-associated chal-lenges while drilling these wells, including well-bore instability and well control problems. Efforts to overcome these challenges gave rise to the development of MPD.3 MPD is used primarily to drill wells that do not lend themselves to either conventional overbalanced or under-balanced methods, such as in areas where flar-

ing is forbidden, or while drilling through high-permeability formations.

In wells with sufficiently large drilling mar-gins, pressure losses may also be manageable through the manipulation of drilling fluid proper-ties, flow rates and rates of penetration. Drilling fluids experts at M-I SWACO, a Schlumberger company, have developed a micronized weighting agent and a fluid system built around it. The WARP system uses a weighting agent composed of particles ground ten times smaller than conven-tional barite, with 60% being less than 2 um in diameter. And although accepted wisdom would dictate that such finely ground particles would yield a highly viscous fluid, because of the manu-facturing process, WARP fluid systems are char-acterized by low viscosities, low gel strengths and low sag potential.4

Because these characteristics minimize ECD while maintaining good cuttings transport ability, WARP fluid systems are particularly well suited to use with MPD on extended-reach wells. One major operator in the Gulf of Mexico has used the system to drill 13 of its 16 MPD wells.

This article discusses the development and practice of MPD and the techniques and equip-

ment required to execute it. Case histories from US and Australia onshore and offshore wells demonstrate its application in mature fields, high-pressure and high-temperature environ-ments and fractured formations.

Closed VesselsConventionally drilled wells are open systems. As a well is drilled, fluid is pumped down the drill-pipe, through the bit and back to the surface along the annulus between the drillstring and the borehole. The return line at the surface—which leads to the shale shaker and mud pits where drilling fluid is processed and stored in prepara-tion for reuse—is open to the atmosphere.

Though they are quite different, UBD and MPD methods use closed systems that deploy a rotating control device (RCD) to divert formation and drilling fluid flow to a separator. Among oper-ators who require two barriers between the well and the surface, the RCD and the drilling fluids are considered primary barriers, and the blowout preventer is a backup. MPD operations use the RCD to create a closed system and a drilling choke manifold and backpressure pump to con-trol downhole pressure. In that way, engineers can maintain a constant BHP during drilling operations while the mud pumps are on and while the pumps are turned off to make connections.

Once the downhole pressure environment has been defined by pore pressures, fracture pres-sures and wellbore-stability pressures—often through the use of real-time fingerprinting, with annular pressure decreases to induce flow or increases to induce losses—MPD is used to maintain an appropriate annular hydraulic pres-sure profile. Thus MPD allows operators to keep the ECD within a narrow pore-pressure–fracture-gradient window while still maintaining pres-sures conducive to wellbore stability. This is accomplished primarily through manipulation of backpressure on the annulus while taking into account factors that affect the ECD such as fluid density, fluid rheology, annular fluid velocity, cir-culating friction and hole geometry (above left).5

Maintaining a constant downhole pressure within the prescribed boundaries minimizes formation damage, prevents mud loss, inhibits formation fluid influx and often results in higher rates of penetration. MPD may permit the opera-tor to extend a casing setting point or even elimi-nate a casing string. It also offers operators the ability to instantaneously react to downhole pres-sure variations, which may be used to minimize formation influxes or mud losses without inter-rupting drilling. Additionally, because its density

>Managing pressure. Conventional drilling methods are predominantly concerned with containing formation fluid inflow during drilling. This overbalanced drilling (OBD) method uses drilling fluids to create an ECD that results in a BHP greater than pore pressure (purple line) but less than the fracture initiation pressure (red line) of the formation being penetrated. Underbalanced drilling (UBD) is focused on preventing drilling fluid loss to the formation and so maintains an ECD that is less than pore pressure but greater than pressure required to maintain wellbore stability. This allows the formation fluid to flow out of the formation, preventing drilling fluid from flowing into the formation. Managed pressure drilling (yellow) is aimed at overcoming drilling problems by using surface pressure to maintain a constant downhole pressure that prevents the flow of formation fluids into the wellbore while keeping pressure well below fracture initiation pressure. During drilling operations, the ECD of OBD and MPD may, at some depths, be equal.

Dept

h

Pressure

UBD

MPD

OBD

Pore pressure

Wellborestabilitypressure

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Spring 2011 17

remains unchanged, there is no need to circulate the mud during these events and so MPD prac-tices save rig time.6

Parts That Make the HoleMPD relies on the driller’s ability to maintain, either manually or automatically, a precise target downhole pressure. The key to this ability is the creation of a closed system, which is made possi-ble by the use of the RCD, sometimes called a rotating head. The RCD provides a seal around the drillpipe during rotary drilling operations and diverts drilling fluids to a drilling choke man-

ifold and to the mud pits (above). The choke allows drillers to adjust backpressure on the annulus while the pumps are on and the drilling fluid is being circulated. When the mud pumps

are turned off, for example during connections, a dedicated pump supplies required fluid to the system to compensate for the loss of ECD when the system goes from dynamic to static mode.

3. Malloy KP, Stone CR, Medley GH Jr, Hannegan D, Coker O, Reitsma D, Santos H, Kinder J, Eck-Olsen J, McCaskill J, May J, Smith K and Sonneman P: “Managed-Pressure Drilling: What It Is and What It Is Not,” paper IADC/SPE 122281, presented at the IADC/ SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, San Antonio, Texas, USA, February 12–13, 2009.

4. Taugbøl K, Fimreite G, Prebensen OI, Svanes K, Omland TH, Svela PE and Breivik DH: “Development and Field Testing of a Unique High-Temperature/High-Pressure (HPHT) Oil-Based Drilling Fluid With Minimum Rheology and Maximum Sag Stability,” paper

The AUTOCHOKE unit (right) uses a dynamically positioned shuttle assembly that slides inside the AUTOCHOKE body. The dynamic trim is connected to the shuttle assembly and slides inside the static trim to form a circular orifice. Hydraulic pressure from the AUTOCHOKE console (not shown) is applied to the backside of the shuttle assembly inside the hydraulic set point pressure chamber, and casing pressure is applied to the front side of the shuttle assembly. If the casing pressure is higher than the hydraulic set point pressure, the shuttle assembly moves back, increasing the orifice size, thus reducing the casing pressure. If the casing pressure is lower than the hydraulic set point pressure, the shuttle assembly moves forward, reducing the orifice size and raising the casing pressure. As the shuttle assembly moves back and forth, it regulates the flow of fluid or gas from the well by automatically adjusting the orifice size as it balances the two pressures.

Drive bushingassembly

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> RCD and automatic choke. The HOLD RCD (center) is mounted on top of the blowout preventer (red, left), providing a seal that converts the drilling well from a normally open system to a closed system. The drive bushing, installed into or removed from the RCD via the drillstring, contains the seal element, which provides the seal between the annulus and the drillstring. A high-pressure seal provides a barrier that prevents wellbore fluids from entering the bearing chamber of the RCD and contaminating the lubrication system, which would destroy the bearings. A visual indicator lets the driller know that the latching system holding the drive bushing seal element is locked in place. The mounting spool connects the RCD to the BOP stack and the receptacle of the bearing assembly and to the flowline carrying returns away from the drill floor.

SPE 96285, presented at Offshore Europe, Aberdeen, September 6–9, 2005.

Sag refers to particles of weighting material settling out of the drilling mud.

5. ECD is often converted to equivalent mud weight in lbm/galUS and is equal to the mud weight required to generate pressure at depth during static operations.

6. van Riet EJ and Reitsma D: “Development and Testing of a Fully Automated System to Accurately Control Downhole Pressure During Drilling Operations,” paper SPE/IADC 85310, presented at the SPE/IADC Middle East Drilling Technology Conference & Exhibition, Abu Dhabi, UAE, October 20–22, 2003.

18 Oilfield Review

This manipulation of backpressure in reac-tion to pressure variations caused by drilling operations is frequently referred to as dynamic pressure control. Downhole pressure is equal to surface pressure plus annular pressure, which is itself made up of a static component and a dynamic component.

Dynamic pressure includes friction pressure losses, and its value is a function of circulating conditions. Therefore, when the pumps are off, the dynamic pressure is equal to zero, and only the hydrostatic pressure of the fluid acts on the formation. Also, during drilling operations with the mud pumps on, dynamic pressure may fluctu-ate because of variations in the mud pump rate or mud density, or in response to events such as drilling motor stalls, cuttings loading and pipe rotation (above).7

With the ability to react to annular pressure variations, the operator can drill with a fluid that creates sufficient ECD to contain formations uphole from the bit, even though the well may become underbalanced when static. Using MPD techniques, the driller can safely stop the pumps while making connections even though the hydrostatic pressure of the mud column alone is less than the pore pressure of the formation.

When wells are drilled through relatively stable formations, with widely separated pore pressure and fracture initiation pressure, there may be sufficient margin to accommodate the dif-ference between dynamic and static downhole pressures. In these cases, reaction to changing conditions need not be overly precise. It is possi-ble to maintain constant BHP through manual manipulation of the choke, mud pumps and dedicated pump.

However, narrow drilling margins, high pres-sures and temperatures, highly permeable or fractured reservoirs and hole instability are situ-ations for which MPD is particularly suited. These conditions demand adjustments be made with an accuracy and frequency possible only through automated MPD.

In the early 2000s, engineers at Shell International E&P developed and tested an auto-mated MPD system that incorporated a hydrauli-cally operated choke manifold and connected a positive displacement pump to the annulus.8 Two computer systems—one to run a hydraulics simulator and another for user interface—and a programmable logic controller adjust the choke manifold. The intent of the automated MPD sys-tem was threefold: to automatically calculate in real time the backpressure required to maintain constant downhole pressure, to control the choke and pump that generate backpressure at all times and to provide automatic kick detection.

The resulting dynamic annular pressure con-trol (DAPC) system calculates in real time the backpressure, or set point, required to maintain a desired downhole pressure. It imposes this back-pressure on the annulus by continuously adjust-ing the hydraulically controlled choke and pump settings based on real-time data acquisition (next page).

The control system varies with each applica-tion but consists essentially of five parts:

database

controller

and controls.Drilling engineers use the hydraulics model

to calculate the surface pressure set point that will deliver the desired downhole pressure. Input to the model includes frequently changing data, such as pump rate; static values, such as well drillstring geometry; and slowly changing proper-ties, such as mud density and viscosity.

Data are delivered using the wellsite infor-

protocol and may be internally measured and logged in a historical database.9

operators to configure the system with limits on variables, which can be set up to issue warnings

-able for manual operation of chokes and valves. The control system, using a PID controller, deter-mines the optimal choke position to control the

> Fluid densities and BHP. To keep the BHP between pore pressure (black line) and fracture initiation pressure (blue line) when using conventional drilling methods below a casing shoe, the BHP resulting from the mud weight must be greater than pore pressure so that it may contain formation pressure when the rig pumps are off (solid red line) and less than fracture initiation pressure when the pumps are on (dashed red line). MPD allows the operator to use a drilling fluid that creates a hydrostatic pressure less than pore pressure when the pumps are off (solid green line). When pumps are off, formation pressure is contained by adding backpressure (short-dashed green line) to increase BHP without increasing mud density. When the pumps are on (long-dashed green line), backpressure is reduced to a point that results in a BHP above pore pressure but below fracture initiation pressure.

Conventional drillingHydrostatic pressureDynamic pressure

MPDHydrostatic pressureHydrostatic pressure + backpressureDynamic pressure + backpressure

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Spring 2011 19

7. Reitsma D and van Riet E: “Utilizing an Automated Annular Pressure Control System for Managed Pressure Drilling in Mature Offshore Oilfields,” paper SPE 96646, presented at Offshore Europe, Aberdeen, September 6–9, 2005.

8. van Riet and Reitsma, reference 6.9. WITS is an industry-standard communications format

used to transfer a wide variety of wellsite data from one computer system to another. A WITS data stream consists of discrete data record types, each of which can

backpressure.10 One PLC runs the PID controllers and another is used as a sensor interface and for choke positioning.

Shell tested the DAPC system in a well- simulation facility that included a fully equipped rig and vertical hole about 1,530-m [5,020-ft] deep, with 51/2-in. casing and a 27/8-in. drillstring run to bottom. The well was configured so that nitrogen could be injected into the annulus to simulate gas kicks. Downhole pressures were recorded in real time.

To determine optimal settings, a single opera-tional parameter was changed for each test. Results showed the system was able to signifi-cantly reduce pressure variations downhole, and through fine-tuning, engineers were able to fur-ther enhance that ability. Test results also indi-cated that faster cycling of the pumps caused larger pressure variations. Tripping and drilling tests showed the system was able to compensate for pressure variations over a wide range of conditions.

The team also simulated drilling problems such as choke plugging, hole bridging and fluid loss. In all cases, the system compensated for these events and maintained constant downhole pressures. Additionally, the controller was able to use the automated choke and pump to circulate out simulated gas kicks. This was achieved by increasing backpressure at the surface to com-pensate for the reduction in static pressure caused when nitrogen pumped into the annulus reduced the density of the fluid column.11

Taking it to MarsThe Shell DAPC system was first used in deep water at the company’s Gulf of Mexico Mars plat-form located about 130 mi [209 km] southeast of New Orleans in about 3,000 ft [914 m] of water. As in most deepwater fields, the difference

> Automated DAPC system. To maintain constant BHP during transition from drilling to making connections when the pumps are shut off, the DAPC system stabilizes the backpressure by pumping drilling fluid into the choke manifold regulated through choke AC-1. Backpressure is reduced or not applied when the pumps resume for drilling. The DAPC’s control system, which is directly linked to the real-time hydraulics analysis and continuous kick detection, stabilizes and controls the BHP through adjustment of the DAPC backpressure pump and chokes AC-2 and AC-3. A flowmeter (dashed oval) connected to the low-pressure side of the choke manifold provides flow-out data, which the pressure manager continuously monitors and compares to flow-in data for kick detection.

RCD

Gas vent

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be turned on and off by the rig operator and assigned sampling rates. WITS also enables computers at remote locations to send instructions to another computer to change parameters, including data type and sampling rate.

10. A PID controller is used in many industrial applications to calculate the difference between a measured variable and a desired set point such as surface pressure. The PID controller attempts to minimize differences between the two by adjusting the process inputs.

11. van Riet and Reitsma, reference 6.

20 Oilfield Review

between pore pressure and fracture initiation pressure is often small. In the case of Mars, the field had experienced considerable zonal deple-tion. This made controlling ECD even more criti-cal and more difficult because deep water developments typically use high-angle, very long wells to reach stranded or secondary reserves. Consequently, the wellbore must often pass repeatedly through low-pressure depleted zones and high-pressure virgin sands.

Furthermore, hydrocarbon extraction may change rock stress characteristics. Because the wells have been on production since 1996, reser-voir and nonreservoir rock formation strength has become reduced. Therefore, lowering mud density has resulted in wellbore instability. However, dur-ing attempts to sidetrack the Mars A-14 well, the use of high-density drilling fluids caused lost-cir-culation problems in depleted zones.

The A-14 well targeted the waterflooded M1/M2 reservoir that contained the majority of the field’s reserves. In May 2003, it had been shut in because of sand production; sidetrack opera-tions to reenter the M1/M2 reservoir were begun in 2004. The first attempt failed when the BHA was lost at 21,144 ft [6,445 m] MD, 16,340 ft [4,980 m] TVD, due to lost circulation and well-bore stability problems. An attempt to sidetrack from the previous casing shoe failed when the

> Conventional drilling and MPD in deepwater. Diagnoses of two failed sidetracks at the Shell-operated Mars platform led to a prognosis that conventional drilling (top) would result in an ECD that was within 0.05 lbm/galUS [0.006 g/cm3] equivalent mud weight (EMW) of the formation integrity test (FIT) (red dots, top) value. Using MPD methods (bottom), the EMW could be reduced (green) and, by adding 525 psi [3.62 MPa] annular pressure, the gap between the FIT (red dots) and the ECD would be expanded to 0.3 lbm/galUS [0.036 g/cm3] equivalent (red dots, bottom). (Adapted from Roes et al, reference 12.)

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Spring 2011 21

same problems prevented engineers getting an expandable liner to depth.

Shell turned to the DAPC system developed by its E&P research arm. At the Mars platform, the DAPC control system was modified to com-municate with a third-party choke controller system. The DAPC controller was therefore limited to determining the necessary back-pressure and communicating that to the choke controller system.

BHP was calculated in real time using a Shell hydraulics steady-state model that contained static data such as mud weight, BHA configura-tion, well geometry and directional data, and was updated by rig data every second. Though there was generally good agreement between model and measured BHPs, string rotation was not properly compensated for, which resulted in the actual equivalent mud weight of the BHP being about 0.2 lbm/galUS [0.024 g/cm3] higher than the model. To address this, the model was manu-ally adjusted with corrected values.

The well was drilled to TD using a mud density of 13.1 lbm/galUS [1.57 g/cm3], which is 0.3 lbm/galUS [0.036 g/cm3] less than the previous two attempts. This was made possible by using the DAPC to maintain a BHP set point equivalent to 13.7 lbm/galUS [1.64 g/cm3] (previous page). Using these specifications, there were no indica-tions of hole instability or lost circulation and the liner was run without incident.12

Following this success, Shell chose to use MPD on 11 more wells. In one field, after repeat-edly failing to reach TD using conventional methods, engineers reached target depth in six of six tries using MPD. The program was so success-ful in the maturing field, production facilities reached capacity.

MPD proved to be the solution in two more Shell-operated deepwater fields and six more wells with similar challenging relationships between fracture initiation pressure, pore pres-sure and wellbore stability. Shell is also applying the technique in other challenging circum-stances including cementing wells that prove dif-ficult because of depletion, safely penetrating high-pressure, high-temperature (HPHT) sec-tions and for drilling wells that are otherwise impossible to drill within existing HSE standards.

High Pressure, Depletion and CementMPD is particularly suited to wells targeting high-pressure formations. The subsurface in which these wells locations are found is often marked by uncertain pressures, complex lithology and indeterminate flowback, which is the volume of drilling fluid that flows from the annulus after

the mud pumps are shut off. Additionally, in highly pressured formations, apparent kicks, if mis diagnosed or mishandled, are more likely to become well control events than in normally pressured environments.

Typically, HPHT wells are further complicated by narrower drilling margins and little offset well information. Faced with one or both of these situ-ations, drillers must be prepared for the conse-quences of higher-than-anticipated pressures even when dealing with routine situations. For example, during traditional drilling operations, multiple prediction and detection methods help reduce uncertainty related to pressure. However, some operators are loath to rely on the practice of pore pressure prediction in HPHT wells.

Shell uses MPD equipment on wells charac-terized by a high degree of pressure uncertainty. By routinely and intentionally inducing flow dur-ing MPD operations—essentially using both UBD and MPD in different sections of the well— engineers are able to determine pore pressure in real time. Armed with accurate pore-pressure data, the operator can drill ahead while maintain-ing a constant bottomhole pressure to stay within the drilling window. Additionally, Shell manipu-lates the drilling fluid systems to strengthen the borehole, effectively altering the fracture gradi-ent and thus expanding the drilling margin.

Unusual flowback volumes are often an indica-tion of what is known as wellbore breathing or ballooning. This phenomenon occurs when drill-ing-induced fractures absorb a volume of drilling fluid. When the pumps are shut off and the ECD is reduced, these fractures close and expel the fluid, resulting in flowback at the surface. By recording the flowback volume before and immediately after drilling out of casing—a process known as finger-printing—drillers can establish a baseline flow-back volume to be expected from a particular well when the pumps are shut off (above). When the flowback volume exceeds the fingerprint volume, the excess is often mistakenly interpreted as a kick, a pressure-induced influx of formation fluids rather than wellbore breathing.

Drillers react to a kick by increasing mud density. However, doing so when the volume gain is due to wellbore breathing can have serious consequences; an increase in mud density may turn a slightly overbalanced condition into a severely overbalanced condition that causes even greater fluid loss.

By drilling with an MPD package and main-taining a constant BHP, engineers can eliminate not only the pressure fluctuations between dynamic and static drilling modes that cause

12. Roes V, Reitsma D, Smith L, McCaskill J and Hefren F: “First Deepwater Application of Dynamic Annular Pressure Control Succeeds,” paper IADC/SPE 98077, presented at the IADC/SPE Drilling Conference, Miami, Florida, USA, February 21–23, 2006.

> Fingerprinting flowback. This fingerprint of the flowback in one high-pressure, high-temperature (HPHT) well in Mexico was recorded during the second connection by the DAPC system before MPD operations. The volume of flowback, or gain, after the pumps are turned off (green shaded area) is complemented by the losses (gray shaded area) when the pumps are turned back on and the operator goes from static to dynamic drilling mode. (Adapted from Fredericks et al, reference 13.)

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22 Oilfield Review

wellbore breathing but also any possibility of mis-diagnosis (above). Moreover, the accuracy and speed with which they can react to pressure variations make automated MPD systems well suited to quickly identifying and addressing numerous common drilling hazards before they become issues.13

In some cases, once drilling hazards have been identified, MPD practices may be used with other technologies to overcome them. In the Shell-operated McAllen-Pharr field in Hidalgo County, Texas, USA, for example, the operator was faced with drilling through produced zones in which depletion prediction was complicated by difficult-to-map faulting. Additionally, zones that had been depleted to as much as 5,000 psi [34 MPa] below original pressure were often found between layers of overpressured virgin sands, which made isolating them with a drilling liner impractical.14

In nearby fields, as a consequence of raising mud weight in preparation for tripping out of the hole, the operator had experienced severe fluid losses when the liner setting point was reached. Liner or casing drilling—in which the drillstring is replaced by a liner or casing that can be left in

the hole, thus eliminating tripping and the need to raise mud density—was used to solve the prob-lem in those wells.

Liner drilling worked in these fields because the low permeability of the zones being drilled prevented flow into the wellbore even when the pumps were shut off and the equivalent mud den-sity fell below pore pressure. Uncertainty about pressure and an expectation of high permeability made use of this strategy alone untenable in the McAllen-Pharr field.

Shell turned to automated MPD equipment, adapting its system to onshore applications. Engineers decreased the size and weight of the choke manifold by reducing the number of chokes, valves and bypass lines, which also drove improvements to the hydraulic power system. The reduced manifold moved from a three-choke to a two-choke design, with one choke dedicated to backpressure management and the other to duty as both a backup and for automated pres-sure relief.15 A rig pump, rather than a dedicated pump, provided backpressure when the primary mud pumps were off.

The first well in the field drilled with the mod-ified unit, the Bales 7, was characterized by com-plex faulting and little offset data. This made it

difficult to predict the pore-pressure and fracture-gradient regimes in the target reservoir sands through which Shell intended to drill.

The operator’s plan called for a 75/8-in. casing shoe at about 8,700 ft [2,652 m] MD. A 2,100-ft [640-m] horizontal reach was then to be drilled conventionally in an S-shaped trajectory along a 19° tangent.16 Next, a 61/2-in. hole was to be drilled vertically using jointed pipe and auto-mated MPD to 10,360 ft [3,158 m]. From there the 61/2-in. section would be drilled to 11,065 ft [3,373 m] using casing drilling and MPD (next page). The entire 61/2-in. section was to be drilled statically underbalanced.

The ECD set point was 14.15 lbm/galUS [1.7 g/cm3] at the casing shoe, increasing to 14.9 lbm/galUS [1.8 g/cm3] at TD. On average, the system controlled the ECD to within ±0.12 lbm/galUS [0.01 g/cm3] of the set point by continuously managing the backpressure between 100 and 200 psi [0.7 and 1.38 MPa]. In the section drilled with conventional drillpipe, this included 16 pump transitions; during these times the pumps were turned off and on for 15 connections and one time to replace leaking seals in the rotary control device.

The second section of the 61/2-in. hole met with pore pressures of at least 1.5 lbm/galUS [0.02 g/cm3] higher than any encountered uphole. Combined with expected depletion levels, it was determined that fluid losses would be too great with a conventional drilling assem-bly, so engineers opted to casing drill to final TD.17 Static mud weight for the entire section was 15.7 lbm/galUS [1.8 g/cm3] and ECD was a con-stant 16.2 lbm/galUS [1.9 g/cm3].

Though gas flowed from the well during drill-ing and the flow volume increased with depth, BHP was held constant to within an average equivalent mud weight of ±0.18 lbm/galUS [0.02 g/cm3], including through 13 pump transi-tions. Using MPD to avoid losses while maintain-ing a constant ECD, engineers reached TD with a 31/2-in. casing drillstring.

Finally, engineers used automated pressure control practices to cement the production cas-ing, holding 90 psi [0.6 MPa] of backpressure while circulating bottoms up ahead of cementing. Once returns were stabilized, the pumps were shut down to install a cementing head and the BHP held constant by application of 200 to 210 psi [1.38 to 1.45 MPa] backpressure. After the spacer was pumped, the choke was used to maintain a constant 16.2 lbm/galUS [1.9 g/cm3] ECD during cementing. As a result, the well was successfully cemented with no fluid losses.

>No wellbore breathing. Pressure data recorded by DAPC during the fifth connection on the same HPHT well as in previous figure show no signs of wellbore breathing (orange line). As the rig pumps are cycled (green), the DAPC backpressure pump pressure and rate (black and purple lines) are increased or decreased automatically to maintain the ECD set point pressure (red line) and density (blue line) in both dynamic and static drilling modes. The absence of gains or losses due to flowback or wellbore breathing indicates the well is at equilibrium at this constant BHP. (Adapted from Fredericks et al, reference 13.)

Mexico HPHT wellConnection 5

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Spring 2011 23

While liner drilling the McAllen-Pharr wells using MPD equipment, gas was circulated through the gas buster. In order to minimize fluid losses, mud weight was occasionally adjusted. Shell used this melding of MPD, UBD and casing drilling to expand its casing drilling program to other fields in South Texas and to avoid the significant expense of using a liner as part of a contingency plan.18

Drilling the Impossible, the Very Hot and MoreUsing externally applied backpressure in a closed drilling system to maintain a constant downhole pressure is a relatively new approach to drilling through narrow drilling margins. Operators con-tinue to discover new applications for MPD as they seek answers to unique pressure-related drilling challenges.

For example, in maturing basins, operators often opt to drill sidetrack wells from existing wellbores to reach stranded reserves with which to shore up falling production. These efforts are often hampered, however, by high annular fluid losses as wellbores pass through depleted zones. Conventional drilling practices in this environ-ment frequently fail to access the stranded oil because of drilling issues such as stuck pipe or difficulty running casing.

While MPD would seem a likely solution, the challenge is further complicated because these

slimhole sidetracks are drilled traditionally using positive-displacement motors. These motors cre-ate continuous fluctuations in ECD as they move from sliding to rotating mode, making constant BHP nearly impossible. The solution for one oper-ator in the Gulf of Mexico was MPD in combina-tion with a new generation of rotary steerable tools and pressure-while-drilling sensors.19 Based on this company’s success, operators throughout the Gulf are reevaluating opportunities for extending life and profitability from mature fields through slimhole sidetracks.

In Australia, while drilling wells for a geother-mal project in the Cooper Basin, Geodynamics Limited found that the granite basement was unexpectedly overpressured by as much as 5,200 psi [36 MPa]. Additionally, the existing stress regime of the granite created conditions that led to kicks and fluid losses. In this first well, drilled using conventional techniques, the opera-tor incurred considerable NPT when it was forced to use a 4.0-lbm/galUS [0.5 g/cm3] mud density increase to control and kill a fluid influx from the overpressured basement.

The operator then turned to DAPC to main-tain the delicate balance between the overpres-sure and fracture gradient on the next two wells. On the second well, engineers used the system to control and kill a fluid influx in 90 minutes while raising the mud density by only 0.7 lbm/galUS [0.1 g/cm3]. They also used the system to main-tain a constant ECD by manipulating the back-

pressure between 220 and 295 psi [1.5 and 2.0 MPa] during drilling operations and 525 and 625 psi [3.6 and 4.3 MPa] during connections.20

The Proper Tool for the Proper JobDue to its flexibility and continuous flow and pressure control, MPD is often a safer and less costly drilling method than either under- or overbalanced drilling. This is especially true for environments with narrow or unknown drilling margins. MPD has been used, for example, in forestalling kicks while crossing the rubble zones in subsalt drilling. It has also been used to replace Coriolis mass flowmeters—which can be sensitive to entrained gas and vibration and highly susceptible to poor maintenance—for early kick detection.21

Getting the most value from MPD requires it be applied in drilling situations for which it is best suited. While it is often and correctly viewed as a way to successfully drill wells that would otherwise not reach their targets, it should be thought of neither as the answer to all drilling problems nor the method of last resort. The most appropriate candidates for MPD are for wells with offsets characterized by wellbore instability, excessive drilling fluid losses or those that will be drilled through pressured, virgin zones and depleted, or otherwise underpressured ones. Those parameters alone suggest the num-ber of wells that are good MPD candidates is quite considerable. —RvF

>Wellbore profile. The Bales 7 well was drilled as a high-angle well to the 75/8-in. casing point and then turned vertical. The production section was then drilled in two steps aimed at addressing varying pore pressure and fracture initiation pressure regimes that engendered fluid loss in some sections and gas influx in others. (Adapted from Montilva et al, reference 14.)

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13. Fredericks P, Sehsah O, Gallo F and Lupo C: “Practical Aspects and Value of Automated MPD in HPHT Wells,” paper AADE 2009NTCE-04-04, presented at the AADE National Technical Conference and Exhibition, New Orleans, March 31–April 1, 2009.

14. Montilva J, Fredericks P and Sehsah O: “New Automated Control System Manages Pressure and Return Flow While Drilling and Cementing Casing in Depleted Onshore Field,” paper SPE 128923, presented at the IADC/SPE Drilling Conference and Exhibition, New Orleans, February 2–4, 2010.

15. Montilva et al, reference 14.16. For more on extended reach drilling: Bennetzen B,

Fuller J, Isevcan E, Krepp T, Meehan R, Mohammed N, Poupeau J-F and Sonowal K: “Extended-Reach Wells,” Oilfield Review 22, no. 3 (Autumn 2010): 4–15.

17. For more on casing drilling: Fontenot KR, Lesso B, Strickler RD and Warren TM: “Using Casing to Drill Directional Wells,” Oilfield Review 17, no. 2 (Summer 2005): 44–61.

18. Montilva et al, reference 14.19. Njoku JC, Husser A and Clyde R: “New Generation

Rotary Steerable System and Pressure While Drilling Tool Extends the Benefits of Managed Pressure Drilling in the Gulf of Mexico,” paper SPE 113491, presented at the Indian Oil and Gas Technical Conference and Exhibition, Mumbai, March 4–6, 2008.

20. @balance: “Successful Use of Managed Pressure Drilling to Eliminate Losses and Control Influx in Hot Fractured Rock Geothermal Wells,” http://www.atbalance.com/NE_News_Geothermal.html (accessed December 1, 2010).

21. For more on subsalt drilling: Perez MA, Clyde R, D’Ambrosio P, Israel R, Leavitt T, Nutt L, Johnson C and Williamson D: “Meeting the Subsalt Challenge,” Oilfield Review 20, no. 3 (Autumn 2008): 32–45.

24 Oilfield Review

Finding Value in Formation Water

Operators usually consider formation water an undesirable byproduct of hydrocarbon

production. However, samples and analysis of that same water can provide vital

information for the field development plan, including optimization of completion

design, materials selection and hydrocarbon recovery.

Medhat AbdouAbu Dhabi Company for Onshore OperationsAbu Dhabi, UAE

Andrew CarnegieWoodside PetroleumPerth, Western Australia, Australia

S. George MathewsKevin McCarthyHouston, Texas, USA

Michael O’KeefeLondon, England

Bhavani RaghuramanPrinceton, New Jersey, USA

Wei WeiChevronHouston, Texas

ChengGang XianShenzhen, China

Oilfield Review Spring 2011: 23, no. 1. Copyright © 2011 Schlumberger.For help in preparation of this article, thanks to Sherif Abdel-Shakour and Greg Bowen, Abu Dhabi, UAE; Ahmed Berrim, Abu Dhabi Marine Operating Company, Abu Dhabi, UAE; Hadrien Dumont, Balikpapan, Indonesia; Will Haug, Cuong Jackson and Oliver Mullins, Houston; Chee Kin Khong, Luanda, Angola; Cholid Mas, Jakarta; and Artur Stankiewicz, Clamart, France.InSitu Density, InSitu Fluid Analyzer, InSitu pH, MDT, Oilphase-DBR, PS Platform and Quicksilver Probe are marks of Schlumberger.

At the mention of unexpected formation water in their wells, many oil and gas producers react with alarm. Unanticipated water production, particu-larly if it contains unwanted impurities, can significantly reduce the value of a hydrocarbon asset. It can accelerate equipment damage and

increase water handling and disposal costs. But capturing a certain amount of formation water is also valuable; water properties contain a wealth of information that can be used to significantly impact field economics.

1. Ali SA, Clark WJ, Moore WR and Dribus JR: “Diagenesis and Reservoir Quality,” Oilfield Review 22, no. 2 (Summer 2010): 14–27.

2. Interstitial water is the water between grains. For more on evaporites: Warren JK: Evaporites: Sediments, Resources and Hydrocarbons. Berlin, Germany: Springer, 2006.

Spring 2011 25

Formation water analysis plays a role in dynamic modeling of reservoirs, quantifying reserves and calculating completion costs, includ-ing how much will be spent on casing and surface equipment—capital expenditures (capex). Water analysis also helps operators estimate operating expenditures (opex), such as the cost of chemical injection. Quantifying water chemistry aids in the understanding of reservoir connectivity and in characterizing transition zones in carbonates, thereby impacting estimates of reservoir extent. It helps development planners determine whether new discoveries can be tied into existing infra-structure and is crucial for designing water injec-tion projects.

Formation water properties vary from one reservoir to another as well as within reservoirs. Water composition depends on a number of parameters, including depositional environment, mineralogy of the formation, its pressure and temperature history and the influx or migration of fluids. Consequently, water properties can change over time as the water and rock interact, and as reservoir fluids are produced and replaced with water from other formations, injected water or other injected fluids.

This article examines the causes of variation in water composition and describes the value of formation water analysis throughout reservoir life, from exploration to development and pro-duction. Examples from Norway, the Middle East, the Gulf of Mexico and China illustrate methods for collecting high-quality water samples and show how formation water analysis both down-hole and at surface conditions contributes to res-ervoir understanding and development.

Water CompositionMost reservoir rocks are formed in water, by the deposition of rock grains or biological detritus. The water that remains trapped in pores as the sediments compact and bind together is called connate water; the water in the reservoir at the time it is penetrated by a drill bit is called forma-tion water. Connate water reacts with the rock to an extent that depends on temperature, pres-sure, the composition of the water and the miner-alogy of the formation. Chemical and biological reactions may begin as soon as sediments are deposited. The reactions can continue and accel-erate as the formation is subjected to greater pressure and temperature during burial. The combined effects of these chemical, physical and biological processes are known as diagenesis.1 Although a great deal of effort has gone into studying the impact of diagenesis on rock forma-tions, relatively little has been made to under-

stand how it affects the original fluid within the rock—the water.

Connate water varies with depositional envi-ronment. In marine sediments, it is seawater. In lake and river deposits, it is freshwater. In evapo-rite deposits, the interstitial water is high- salinity brine (right).2 These water solutions con-tain ionic components, including cations such as sodium [Na+], magnesium [Mg2+], calcium [Ca2+], potassium [K+], manganese [Mn2+], strontium [Sr2+], barium [Ba2+] and iron [Fe2+ and Fe3+]; anions such as chloride [Cl–], sulfate [SO4

2–], bicarbonate [HCO3–], carbonate [CO3

2–], hydroxide [OH–], borate [BO3

3–], bromide [Br–] and phosphate [PO4

3–]; and nonvolatile weak acids. The water may also contain dissolved gases, such as carbon dioxide [CO2] and hydrogen sulfide [H2S], nitrogen, organic acids, sulfur-reducing bacteria, dissolved and suspended solids and traces of hydrocarbon compounds.

Concentrations of these components may vary as water is expelled by compaction and as it reacts with formation minerals. Some minerals react easily. For example, the clay mineral glauconite has approximately the following composition: K0.6Na0.05Fe3+

1.3Mg0.4Fe2+0.2Al0.3Si3.8O10(OH)2. If the

connate water is undersaturated in the compo-nents of the clay, it will interact with the mineral grain by ion exchange, leaching ions from the glauconite into the aqueous solution. Other min-erals, such as quartz [SiO2], have higher resis-

tance to dissolution and remain as grain matrix. If the water is saturated with the rock’s ions, miner-als can precipitate and form new grains or grow on existing grains. Water properties such as pH and ion concentration are some of the factors that control or influence water-rock interactions.

Even after equilibrium is reached, water-rock interactions continue. However, changes in tem-perature, pressure, depth and structural dip can disrupt equilibrium, as can the migration and accumulation of oil and gas, which force the water deeper as the lighter hydrocarbons rise through a formation. The influx of water from other sources, such as meteoric water, aquifers, injected water and other injected fluids, can also cause water properties to change (below).

> Salinity variations. Salinity of connate water varies with depositional environment, increasing from the freshwater of rivers to seawater and briny evaporite systems. Formation water, the result of water mixing and other physical and chemical processes, can have a wide range of salinities. (Data from Warren, reference 2.)

Average river water

Water Type Salinity, Partsper Thousand

0.11

Formation water 7 to 270

Seawater 35Evaporite systems 35 to 350

>Water movement and processes that can influence the evolution of formation water. Composition of formation water originally filling a sandstone layer can be modified by the addition of water from other sources (arrows), such as meteoric water and water expressed from compacting shales and salt. The water can also be altered by the influx of migrating hydrocarbons. Sealing faults and other flow barriers can create compartments with different water compositions. On the other hand, conducting faults can facilitate flow.

Basement

Faults

Rain (meteoric water)

Sea

Shale

Hydrocarbonaccumulation

ShaleSalt

Sandstone

26 Oilfield Review

Production of formation water is another cause of disequilibrium; dissolved minerals and gases may come out of solution as the fluid is brought to the surface—especially in reaction to sulfates introduced into the formation through drilling fluid invasion or injection of seawater. These losses of the dissolved components alter the composition of the produced or sampled water, so water recovered at the surface may not represent the actual formation water in place. For this reason it is important to collect and analyze formation water under in situ conditions, and to continue to do so as reservoir conditions change.

Applications of Water AnalysisFormation water is rich with information about the rock in which it resides, and it can provide crucial input to analyses during every stage in the life of a reservoir. Early in field life, analysis of for-mation water establishes the salinity and resistiv-ity of the water for petrophysical evaluation.3 Archie’s water saturation equation, from which oil saturation and reserves are most frequently com-puted from logs, requires formation water resistiv-ity as an input. That value is often computed from resistivity and porosity logging measurements made in a water zone, where the water may not have the same composition as the reservoir forma-tion water in other zones. Analysis of formation water samples from the oil leg is considered one of the most reliable ways to obtain water salinity and resistivity for saturation calculations.

Before the material for casing or production tubing is selected, it is vital to evaluate the cor-rosivity of the gas, oil and water to be produced. Free gas in the formation may contain corrosive constituents—such as H2S and CO2—and these same constituents may be dissolved in the forma-tion water. Wells producing such fluids at concen-trations exceeding certain limits require casing with special metallurgical formulations that will resist corrosion, or treatment with corrosion-inhibiting chemicals.4 Furthermore, pipelines and surface facilities must be capable of handling the produced water with its accompanying gases (see “Pipeline to Market,” page 4). To design pro-duction tubing, flowlines and surface facilities, engineers must know the chemical composition of the formation water. The water pH and salinity values used in metallurgical calculations for selection of tubulars must include values for downhole conditions of reservoir pressure and temperature and water composition.5

As reservoir fluids are produced, the accom-panying pressure reduction may cause the release of gas from solution and the precipitation and deposition of solids in the reservoir pores and on production tubing and downhole equip-ment. For example, as pressure decreases, forma-tion water liberates CO2 gas, water pH increases and the solution becomes supersaturated with calcium carbonate [CaCO3], which can result in

scale deposition that may eventually choke off flow (left).6 Precipitation can be predicted through modeling or laboratory experimentation if forma-tion water chemistry is known.

Scale can also form when waters of different compositions mix.7 For example, precipitation of barium sulfate [BaSO4] or strontium sulfate [SrSO4] solids is a common problem when sea-water, which contains sulfates, is injected into formations that contain barium or strontium. It also occurs when sulfates from drilling-fluid invasion interact with the formation water, and is the primary reason behind recent industry practices using low-sulfate drilling fluids. Such scale may be deposited in the formation or in production tubing.8 Partially blocked tubing can sometimes be cleaned with workover tools that deploy abrasives and jetting action. However, if the scale is too thick, there is little that can be done except to pull the tubing and replace it—at significant cost.

Effective scale management is an important issue for field development planning and can have a direct impact on production viability, especially in marginally economic fields.9 The formation water’s potential to create scale when mixed with injected water must be assessed if any part of a field is to be produced with pressure support from injected fluids. In several cases, operators have had to change plans—for example, halting sea-water injection and finding another, more costly source for injection water—based on knowledge of formation water properties.10

In assessing scaling potential, one of the greatest uncertainties may be the formation water composition and downhole properties. Some companies have adopted water monitoring as routine practice for scale-prone fields. For example, Statoil monitors the composition of water produced from the majority of its oil and gas wells, and uses crossplots of the ratio of ion concentrations to assist in defining producing water zones.11 Sampling frequency depends on the need: In cases of high scale potential, water is sampled every one to two weeks.

An additional use of water modeling in development planning is the optimization of well-stream mixing and process sharing: when production streams from several wells, espe-cially subsea wells, are combined before being piped to intermediate separators or processing facilities. To minimize risk of pipeline scaling and corrosion, operators must fully understand the chemical interaction of produced water from different sources before committing to large capital expenditures.

> Scale buildup in production tubing. Scale causes reduced flow rates and can, eventually, completely block production.

Spring 2011 27

Formation water composition plays a role in “souring,” a process in which H2S concentration increases in the reservoir.12 In many cases, souring is attributed to microbial activity; injected seawa-ter provides a source of sulfate-reducing bacteria (SRB) and the formation water supplies nutrients in the form of low–molecular weight organic acids known as volatile fatty acids (VFAs). The conse-quences of reservoir souring are potentially costly. Increased levels of H2S increase safety risks for oilfield personnel, decrease the sales value of pro-duced hydrocarbons and increase corrosion rates in downhole equipment and surface facilities. An estimated 70% of waterflooded reservoirs world-wide have soured.13 Understanding water proper-ties and modeling their changes throughout reservoir life help chemical engineers predict H2S generation and make informed decisions regard-ing materials selection and facility design. Low-contamination water samples, therefore, are essential to establish the level of VFAs in the for-mation water.14

Variations in formation water composition can also reveal compartmentalization—or lack of hydraulic communication between adjacent reservoir volumes—if the reservoirs have been isolated long enough for their formation waters to have reached different equilibrium states. Understanding reservoir connectivity is impor-tant for estimating the extent of aquifer sup-port—the natural water drive present in many reservoirs—and for planning development well locations, formulating injection-related recovery

programs and detecting injection-water break-through. Analysis of formation water, and in par-ticular, comparison of its natural isotopic composition with that of injection water, has been used for monitoring waterfloods.15 Isotopes act as tracers in the water to help reservoir engi-neers identify high-permeability layers, fractures and other causes of interwell communication.

Sampling WaterWater samples can be collected by several meth-ods. Samples of produced water can be obtained at the wellhead or from surface separators, but these may not be representative of formation water if gases have evolved or compounds have precipitated. However, these samples are useful and are typically collected for production surveil-lance. Surface samples are used to monitor changes in water properties over time, to identify breakthrough of injection water and to compare with samples from other producing wells to understand reservoir connectivity. Acquiring such samples is less expensive than downhole sampling and can be done more routinely. Water samples can also be retrieved from preserved core.16 However, samples recovered by this tech-nique have undergone pressure and temperature decrease, and therefore may not be representa-tive of actual formation water.

During the exploration and appraisal stages, when an operator builds an understanding of the reservoir fluids and uses the data for modeling, it is vital to have representative water samples.

Representative samples can be collected by a wireline formation tester equipped with a probe or dual packer, a pumpout module, downhole fluid-analysis capabilities and sample chambers. The downhole water-sampling process begins with a cleanup stage, in which fluid—initially a mixture of mud filtrate and formation water—is drawn from the formation through the probe into the tool.17 As pumping time increases, the propor-tion of mud filtrate, or contamination, decreases, and the proportion of pure formation water in the flowline increases.

If the optical or resistivity properties of the filtrate are significantly different from those of the formation water, optical fluid analyzers or resistivity sensors located in the tool flowline can measure the difference and thereby monitor con-tamination in real time. In the early stages of cleanup, the water is not pure enough to collect, and it is returned to the borehole. When the con-tamination is below a designated level, the fluid is directed into pressurized sample chambers, which are brought to the surface and transported to a laboratory for analysis.18

The quality of samples acquired downhole depends on the method of sampling and the type of drilling mud used in the sampled zones. In zones drilled with oil-base muds (OBMs), high-quality water samples can usually be obtained because the mud filtrate is not miscible with the formation water. Formation water and OBM typi-cally have different optical and resistivity proper-ties, allowing them to be distinguished by optical

3. Warren EA and Smalley PC (eds): North Sea Formation Waters Atlas. London: The Geological Society, Geological Society of London Memoir 15 (1994).

4. For more on corrosion, see Acuña IA, Monsegue A, Brill TM, Graven H, Mulders F, Le Calvez J-L, Nichols EA, Zapata Bermudez F, Notoadinegoro DM and Sofronov I: “Scanning for Downhole Corrosion,” Oilfield Review 22, no. 1 (Spring 2010): 42–50.

5. Williford J, Rice P and Ray T: “Selection of Metallurgy and Elastomers Used in Completion Products to Achieve Predicted Product Integrity for the HP/HT Oil and Gas Fields of Indonesia,” paper SPE 54291, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, April 20–22, 1999.

6. Ramstad K, Tydal T, Askvik KM and Fotland P: “Predicting Carbonate Scale in Oil Producers from High Temperature Reservoirs,” paper SPE 87430, presented at the Sixth International Symposium on Oilfield Scale, Aberdeen, May 26–27, 2004.

7. Mackay DJ and Sorbie KS: “Brine Mixing in Water-flooded Reservoir and the Implications for Scale Prevention,” paper SPE 60193, presented at the Second International Symposium on Oilfield Scale, Aberdeen, January 26–27, 2000.

8. Bezerra MCM, Rosario FF, Rocha AA and Sombra CL: “Assessment of Scaling Tendency of Campos Basin Fields Based on the Characterization of Formation Waters,” paper SPE 87452, presented at the Sixth International Symposium on Oilfield Scale, Aberdeen, May 26–27, 2004.

For an overview of scaling causes and mitigation: Crabtree M, Eslinger D, Fletcher P, Miller M, Johnson A and King G: “Fighting Scale—Removal and Prevention,” Oilfield Review 11, no. 3 (Autumn 1999): 30–45.

9. Graham GM and Collins IR: “Assessing Scale Risks and Uncertainties for Subsea Marginal Field Developments,” paper SPE 87460, presented at the Sixth International Symposium on Oilfield Scale, Aberdeen, May 26–27, 2004.

10. Graham and Collins, reference 9. Andersen KI, Halvorsen E, Sælensminde T and

Østbye NO: “Water Management in a Closed Loop—Problems and Solutions at Brage Field,” paper SPE 65162, presented at the SPE European Petroleum Conference, Paris, October 24–25, 2000.

11. Ramstad K, Rohde HC, Tydal T and Christensen D: “Scale Squeeze Evaluation Through Improved Sample Preservation, Inhibitor Detection and Minimum Inhibitor Concentration Monitoring,” paper SPE 114085, presented at the SPE International Oilfield Scale Conference, Aberdeen, May 28–29, 2008.

12. Farquhar GB: “A Review and Update of the Role of Volatile Fatty Acids (VFA’s) in Seawater Injection Systems,” paper NACE 98005, presented at the 53rd NACE Annual Conference, San Diego, California, USA, March 22–27, 1998.

Mueller RF and Nielsen PH: “Characterization of Thermophilic Consortia from Two Souring Oil Reservoirs,” Applied and Environmental Microbiology 62, no. 9 (September 1996): 3083–3807.

13. Elshahawi H and Hashem M: “Accurate Measurement of the Hydrogen Sulfide Content in Formation Water Samples—Case Studies,” paper SPE 94707, presented at the Annual Technical Conference and Exhibition, Dallas, October 9–12, 2005.

14. Elshahawi and Hashem, reference 13.15. Carrigan WJ, Nasr-El-Din HA, Al-Sharidi SH and

Clark ID: “Geochemical Characterization of Injected and Produced Water from Paleozoic Oil Reservoirs in Central Saudi Arabia,” paper SPE 37270, presented at the International Symposium on Oilfield Chemistry, Houston, February 18–21, 1997.

Danquigny J, Matthews J, Noman R and Mohsen AJ: “Assessment of Interwell Communication in the Carbonate Al Khalij Oilfield Using Isotope Ratio Water Sample Analysis,” paper IPTC 10628, presented at the International Petroleum Technology Conference, Doha, Qatar, November 21–23, 2005.

Smalley PC and England WA: “Reservoir Compartmen-talization Assessed with Fluid Compositional Data,” SPE Reservoir Engineering (August 1994): 175–180.

Ramstad et al, reference 11.16. Smalley and England, reference 15.17. Mud filtrate is the portion of the drilling fluid that invades

the formation during the creation of mudcake on the borehole wall. The filtrate is driven into the formation by the pressure difference between the drilling mud and the formation fluid.

18. 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.

28 Oilfield Review

fluid analyzers and resistivity sensors. Water-base mud (WBM) filtrate, on the other hand, has opti-cal properties similar to those of the formation water, so the two are difficult to distinguish by color. Also, WBM is miscible with formation water and can mix and react with it, leading to contami-nated and unrepresentative water samples unless special care is taken to pump for a long time to collect uncontaminated samples.

The Quicksilver Probe focused extraction technology can collect virtually contamination-free formation fluids, which is especially impor-tant when sampling formation water in the presence of WBM filtrate.19 The tool’s articulated probe, which contacts the formation at the bore-hole wall, draws filtrate-contaminated fluid to the perimeter of the contact area, where it is pumped into a discharge flowline. This diversion preferentially allows pure reservoir fluid to flow into the sampling flowline. The probe can be run as a module combined with the InSitu Fluid Analyzer tool in the MDT modular formation dynamics tester.

Ideal sampling consists of collecting a single-phase sample and keeping it in single phase as it is brought to the surface and transported to the

laboratory. The Oilphase-DBR single-phase multi-sample chamber (SPMC) uses a nitrogen charge to maintain downhole pressure on the reservoir fluid sample between the downhole collection point and the laboratory. This practice ensures that gases and salts remain in solution during the trip from downhole to the laboratory, which may not be possible with standard sample chambers.

Single-phase samples can also be obtained from drillstem tests (DSTs). Usually, water is not intentionally sampled during a DST, but some operators make special efforts to study water composition and will collect DST water samples for laboratory analysis.20

Formation water samples can be obtained later in field life during production logging opera-tions. However, obtaining formation samples prior to production is crucial for recording the baseline composition. The Compact Production Sampler captures conventional bottomhole sam-ples in producing wells. It can be run in any sec-tion of the PS Platform production logging string, conveyed by either slickline or electric line.

Once the samples have been retrieved, they are transported to a laboratory and recondi-tioned to downhole conditions before analysis,

described in a later section. The results are entered in a multiphase equilibrium model—various models are available commercially—to predict downhole pH and the potential for corro-sion, scale and hydrate formation.

Because of the lack of a pH measurement on reconditioned samples, chemical engineers use equilibrium modeling to predict pH under reser-voir conditions. However, uncertainties in the thermodynamic models for formation waters at high temperatures and pressures, as well as uncertainties associated with the possible pre-cipitation of salts, can propagate errors into scale and corrosion models. Furthermore, unless tools such as the SPMC are used, changes in pres-sure and temperature as the water sample is transported uphole may induce phase changes that are not always fully reversible during the reconditioning process.21

Since pH is a key parameter in understanding water chemistry and plays a major role in predict-ing corrosion and scale deposition, obtaining reli-able pH measurements on formation water at downhole conditions has been a priority for oil-field fluid specialists.

> Downhole pH measurement. Equivalent to a downhole litmus test, the InSitu pH module (left) uses a mix of pH-sensitive dyes and detects their color change as a function of pH. The spectroscopic detector measures optical density at two wavelengths: 570 nm and 445 nm. Laboratory experiments conducted as part of this technology development showed that pH is a predictable function of the ratio of optical density at 570 nm wavelength to that at 445 nm (top right). The color of the water-dye mixture ranges from yellow at a pH of 2 to purple at a pH of 10 (bottom right).

pH

Optic

al d

ensi

ty ra

tio (5

70:4

45)

2

0.1

1.0

10

4 6 8 10

ModelThree-dye mix

Experiment

Tool wall

Fluid flow

Dye injector

Spectroscopicdetector

Lamp

Spring 2011 29

Measuring pH In SituSchlumberger researchers developed a method for measuring pH downhole using pH-sensitive dyes.22 The InSitu pH reservoir fluid sensor works on the same proven principles as other downhole optical fluid analyzers designed for hydrocarbon analysis.23 One difference, though, is that the InSitu pH module injects pH-sensitive dye into the tool flowline, where it mixes with the fluid being pumped from the formation (previous page). The fluid mixture changes color according to the water pH, and optical sensors quantify the color change by detecting optical density at mul-tiple wavelengths. The wavelengths of the optical channels in the InSitu pH device have been selected to detect the colors expected when waters of pH from about 3 to 9 react with a dye mixture selected for this range. The measure-ment is similar to the well-known litmus test for indicating pH, but the science and applications were adapted to the high-pressure, high-temper-ature conditions encountered downhole.

At early pumping times in WBM systems, the flowline fluid is predominantly filtrate, but as pumping continues, the contamination level—the concentration of mud filtrate—decreases, producing a water sample more representative of formation water. If the WBM-filtrate pH is signifi-cantly different from formation-water pH (typical ranges are pH of 7 to 10 for WBM, pH of 4 to 6 for formation waters), then the pH of the mixture changes as contamination decreases (top right). Monitoring this change helps interpreters quali-tatively track water-sample purity in real time before collecting the water sample. The pH mea-surement using this method is estimated to be accurate to within 0.1 pH units.

An operator utilized this measurement tech-nique in two wells offshore Norway, each pro-posed to be tied back to different existing floating production platforms.24 Knowledge of both hydro-carbon and water composition is crucial for the implementation of tieback development plans. In particular, water analysis is important for flow assurance in the seafloor pipelines, and tieback requires water compatibility with the process equipment on the main platform and with waters flowing through it from other wells.

Well 1, an exploration well, was drilled with WBM through an oil reservoir and into an underly-ing water zone. During cleanup of the water zone, several series of dye injection followed by pH mea-surement showed a clear change of pH over time, indicating reduced contamination of the fluid in the flowline. Laboratory analysis of a tracer added to the drilling fluid confirmed low WBM contami-nation of 0.2% in the collected sample.

Well 2, an appraisal well drilled in a gas- condensate field, was drilled with an OBM system to facilitate high-quality water sampling. Before collecting samples at three depths, the tool mea-sured pH, each time with multiple readings. At the shallowest measurement station, the fluid analyzer indicated the tool flowline contained a mixture of oil and formation water. However, the oil and water segregated within the tool, and the dye mixed only with the water, allowing the pH of the water slugs to be measured. The pH values did not vary over time because the OBM filtrate did not contaminate the formation water.

Laboratory analysis of the water samples acquired from these wells quantified concentra-tions of major components and physical proper-ties at surface conditions. Chemical engineers used these results as input for models to predict pH at downhole conditions.

For the sample from Well 1, the simulated pH value matched the downhole pH value within 0.03 units, giving reservoir engineers confidence in the downhole measurement, the condition of the sample and the modeling method (below).

In Well 2, the sample from the shallowest level had similar downhole and simulated pH val-ues, different by only 0.03 units, again validating the downhole measurement, the condition of the

sample and the model. The middle sample, 3.8 m [12.5 ft] deeper, showed a significant mismatch of 0.39 pH units between the simulated and mea-sured values—a discrepancy several times greater than the typical measurement accuracy. Confidence in the downhole measurement at this station comes from the averaging of 60 data

>Monitoring water cleanup in an Egyptian well before sample collection. As the tool pumped fluid from the formation into the flow line, pH measurements indicated the change in water composition. Early in the cleanup process, the fluid mixture had a high pH, indicating predominantly WBM filtrate. After about 6,000 s of pumping time, the pH leveled off to a low value, signaling that the fluid had cleaned up to an acceptable level of purity for sample collection.

pH

Pumping time, s0 2,000 4,000 6,000 8,000

7.2

7.0

6.8

6.6

6.4

> Downhole and laboratory formation water measurements. The clean formation water samples were analyzed in the laboratory. Chemical engineers used the ion concentrations and physical properties measured from the liquid and the composition of the gas as inputs (not shown) to models to predict pH at downhole conditions. Comparison of these predictions with downhole measurements shows reasonable matches in all cases except for the sample from Well 2 at X,Y29.8 m. The mismatch may indicate a compromise in the integrity of the sample during transfer from downhole conditions to the laboratory.

1 Y,Y08.5 53.8 6.26 6.29

5.756.14139.0X,Y29.8

5.855.82134.0X,X26.02

2

5.826.02142.0X,Y49.92

Well Depth, m Temperature, °C Downhole pH Modeled pH

19. For more on the Quicksilver Probe method, see: Akkurt R, Bowcock M, Davies J, Del Campo C, Hill B, Joshi S, Kundu D, Kumar S, O’Keefe M, Samir M, Tarvin J, Weinheber P, Williams S and Zeybek M: “Focusing on Downhole Fluid Sampling and Analysis,” Oilfield Review 18, no. 4 (Winter 2006/2007): 4–19.

20. O’Keefe M, Eriksen KO, Williams S, Stensland D and Vasques R: “Focused Sampling of Reservoir Fluids Achieves Undetectable Levels of Contamination,” paper SPE 101084, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Adelaide, South Australia, Australia, September 11–13, 2005.

21. It may have taken millions of years for the water to equilibrate with the host formation. Once equilibrium is disturbed, it may not be regained in time for laboratory analysis.

22. Raghuraman B, O’Keefe M, Eriksen KO, Tau LA, Vikane O, Gustavson G and Indo K: “Real-Time Downhole pH Measurement Using Optical Spectroscopy,” paper SPE 93057, presented at the SPE International Symposium on Oilfield Chemistry, Houston, February 2–4, 2005.

23. Andrews RJ, Beck G, Castelijns K, Chen A, Cribbs ME, Fadnes FH, Irvine-Fortescue J, Williams S, Hashem M, Jamaluddin A, Kurkjian A, Sass B, Mullins OC, Rylander E and Van Dusen A: “Quantifying Contamination Using Color of Crude and Condensate,” Oilfield Review 13, no. 3 (Autumn 2001): 24–43.

24. Raghuraman et al, reference 22.

30 Oilfield Review

points with a standard deviation of 0.02 pH units—well within the expected measurement accuracy. The discrepancy between the in situ measurement and the value obtained by model-ing based on laboratory results may indicate a compromise in the integrity of the sample during transfer from downhole conditions to the labora-tory, emphasizing the benefit of the real-time measurement. The pH of the third sample from Well 2 is within 0.2 units of the simulated value, which is a more acceptable match.

These tests demonstrated the capability and accuracy of the real-time downhole pH measure-ment. The tool is able to take multiple measure-ments at each station to verify water purity before sample collection. In addition, it can ana-lyze pH at any number of depths without acquir-ing samples.

Water AssumptionsDownhole water pH measurements have also been used to resolve formation evaluation chal-lenges in a Middle East carbonate field.25 In a giant offshore field, Abu Dhabi Marine Operating Company (ADMA-OPCO) hoped to identify unde-pleted thin pay zones and track movement of the oil/water contact (OWC) in the main reservoir. The main reservoir has undergone decades of production with water injection, but some thin zones have not been tapped yet, and they are appraisal targets.

Most wells in the field, including the four wells in this study, were drilled with WBM using seawater as the base. The WBM and formation water cannot be distinguished using resistivity, but the formation water has low pH, from 5.0 to 5.6, compared with that of the WBM (greater than 7.0). The WBM and formation water also

have markedly different strontium concentra-tions, allowing them to be differentiated through laboratory analysis, which was the standard prac-tice before the availability of real-time pH mea-surements. In Well A, a water sample was collected by traditional methods and sent for laboratory analysis; that sample provided a basis for comparison with the results from the three other wells.

Well C penetrated the main reservoir and sev-eral thin zones believed to be untapped. At one station, a pH measurement was performed after just a few liters of fluid had been pumped from the formation. The fluid was expected to be rich in WBM filtrate, and indeed, it exhibited a down-hole pH of 7.3. Samples of the WBM were col-lected for laboratory analysis at the surface.

Resistivity log analysis suggested this thin, 20-ft [6-m] layer had high mobile oil saturation and could be a potential pay zone. Pressure tests at three stations in the interval indicated low mobility but were inconclusive on fluid density.

Downhole fluid analysis at the location with the highest mobility detected tiny amounts of oil flowing with water in the flowline. After about 280 L [74 galUS] of formation fluid had been pumped through the tool, dye injection followed by pH measurement yielded a pH of 5.1. From previous experience with downhole measure-ments in the field, interpreters concluded the water was formation water, and samples were col-lected. Subsequent laboratory analysis of the strontium concentration confirmed the interpre-tation that this sampling depth was in the oil-water transition zone.

Furthermore, the small fractional flow of oil detected in the downhole fluid analysis implies that the oil saturation is only slightly higher than the residual oil saturation, and that the sampling depth is close to the OWC. This example demon-strates the benefits of downhole fluid analysis in characterization of complex limestone transi-tion zones, especially in thin intervals where pressure and resistivity log interpretations can have uncertainties.

At the top of the main reservoir zone, fluid content estimates—calculated using an assumed value for formation water salinity—indicated high oil saturation (above left). However, pressure measurements across the interval suggested a formation fluid density equivalent to that of water, contradicting the interpretation of high oil saturation.

Downhole fluid analysis performed in the middle of this zone, after several hundred liters of fluid had been pumped from the formation,

Oil

Moved Hydrocarbon

Moved Hydrocarbon

Calcite

DolomiteWater

Water

Resistivity-Based Fluid Analysis Volumetric Analysis

50 100% %0 0

Oil

Formation Pressure, psi

0.2 2,000ohm.m

0.14,430 4,530 1,000

1.082 g/cm3 (water)

1.111 g/cm3 (water)

1.140 g/cm3 (water)

Deep

0.2 2,000ohm.m

Rxo

0.2 ohm.m 2,000

Medium

Resistivity

mD/cP

Pretest Mobility

> Contradictory interpretations in a potential oil-bearing zone. High predicted oil saturation (left, green shading) near the top of this zone is in contrast to the pressure measurements (right), which exhibit a gradient indicative of water (blue dots). Pink dots are measurements in low-mobility zones and were excluded from the gradient calculation. In situ measurement of pH (not shown) supported an interpretation of injection water breakthrough in this interval.

Spring 2011 31

indicated only water in the tool flowline. Real-time measurements of pH returned a value of 6.2—lower than that expected of WBM, but higher than that of the anticipated formation water. Because so much fluid had been pumped from the formation before taking the pH mea-surement, WBM contamination of the water was expected to be low. Fluid analysts suspected that the fluid was not formation water, but water from a nearby injection well. This interpretation was corroborated by laboratory analysis of three water samples collected at this depth.

The injection-water breakthrough had gone undetected during initial openhole logging because the water had not been analyzed, and default values of formation water salinity caused the log interpretation to wrongly predict that the zone contained high volumes of mobile oil. The true salinity of the water in this zone is about one-sixth that of the default formation water, dra-matically changing the interpretation. Correctly identifying water origin by measuring its pH in situ can have significant implications in terms of completion and production planning to minimize water production.

Whence the Water?Abu Dhabi Company for Onshore Operations (ADCO) used the downhole pH measurement in a production well to delineate the oil/water con-tact, characterize the oil-water transition zone and identify the sources of water in various lay-ers.26 The low resistivity contrast between the WBM and the formation fluid precluded using resistivity to track filtrate contamination. Instead, ADCO selected two other methods for monitoring contamination: in situ pH and a colored tracer in the WBM that allows quantitative estimates of contamination before sample collection.

The first sampling station was at X,X51 ft, near the bottom of the suspected oil-water transi-tion zone. This was confirmed by the optical ana-lyzer, which showed only water and no oil flowing at this depth. Monitoring the pH and optical responses of the colored tracer during the cleanup phase showed a reduction in WBM con-tamination with pumping time. The decrease in contamination manifested as downward trends

in both the pH and in the optical density of the tracer-doped mud (above). The pH dropped from 6.47 at high contamination to 5.7, which engi-neers interpreted as the pH of the nearly clean formation water.

At the next sampling station, 10 ft [3 m] above the first, the optical analyzer detected only water until pumping time reached 7,443 s. At that time, oil appeared in the flowline, and by 12,700 s, the oil fraction had increased to 90% (below).

25. Xian CG, Raghuraman B, Carnegie AJ, Goiran P-O and Berrim A: “Downhole pH as a Novel Measurement Tool in Carbonate Formation Evaluation and Reservoir Monitoring,” Petrophysics 49, no. 2 (April 2008): 159–171.

26. Raghuraman B, Xian C, Carnegie A, Lecerf B, Stewart L, Gustavson G, Abdou MK, Hosani A, Dawoud A, Mahdi A and Ruefer S: “Downhole pH Measurement for WBM Contamination Monitoring and Transition Zone Characterization,” paper SPE 95785, presented at the SPE Annual Technical Conference and Exhibition, Dallas, October 9–12, 2005.

> Contamination monitoring in an ADCO well. As the tool pumped fluid from the formation at X,X51 ft, the optical sensor detected a decrease in the fraction of blue-colored WBM with pumping time, indicating a reduction in mud contamination of the formation water. Measurements of pH at four times show a drop from 6.47 to 5.7 as the fluid in the flowline cleans up.

WBM

con

tam

inat

ion,

%

Pumping time, 1,000 s

100

80

60

40

20

Hd

5.8

6.0

6.2

6.4

00 2 4 6 8 10

ContaminationpH

Oil/water contact

90% oil, 10% formation water

100% formation water X,X51 ft

Time, 1,000 s

pHOil

pH Oil %

5.5

6.5

100

50

0

6.0

4 86 10

Dept

h, ft

X,X41

X,X51

X,X??ontact

X,X41 ft

Time, 1,000 s

pHOil

pH Oil %

05.5

6.5

100

50

0

6.0

4 8 12

> Constraining the oil/water contact. Measurements at two depths, X,X41 ft and X,X51 ft, narrow the OWC to somewhere between them. At the deeper station, optical fluid analysis detected water only, and pH measurements indicated the presence of formation water. At the transition-zone station, 10 ft higher, optical fluid analysis detected water initially, but eventually oil arrived and increased in volume fraction to 90%. The pH measurement at this station showed the water to be a mixture of formation water and filtrate, confirming the presence of mobile formation water. Therefore, the OWC is constrained to the 10-ft interval between these two stations.

32 Oilfield Review

Without a pH measurement to characterize the type of water, there is no way to know if the water is WBM filtrate or formation water. The presence of pure WBM filtrate implies the formation water is immobile, while the presence of any formation water implies that formation water is mobile at this depth.

A pH measurement taken at 6,452 s, slightly before the arrival of the oil, gave a value of 5.77, indicative of a WBM–formation water mix. Optical measurement of the colored tracer con-firmed this interpretation. This implies that oil and water are both mobile at this depth. Therefore, the oil/water contact must be between the two measurement stations, narrowing it to between X,X41 and X,X51 ft.

In another ADCO example, a well was drilled to determine the source of water appearing in nearby oil-producing wells. The new well, drilled with OBM to simplify water sampling, penetrated six limestone zones. The shallowest, Zone 1, con-tained only oil; Zone 2 contained oil and water, and the bottom four zones were water bearing. ADCO wanted to know if the water produced from the second layer was coming from the flank of the reservoir through Zone 3, or from the deeper zones.27

Of the water zones, Zone 5 was too tight to flow, but in the other three the formation tester measured downhole pH and collected pressur-ized samples for laboratory analysis.

The downhole pH measurements indicated that the water in Zone 4 was significantly differ-ent from that in the other zones, and modeling based on laboratory findings confirmed this (above left). However, to identify which layer was supply-ing water to the oil-producing zone required com-parison with the produced water. There were no pH measurements on the previously produced water, but laboratory analysis on stock tank sam-ples provided ion concentrations for the waters from the existing producers, and these were com-pared with concentrations from the waters sam-pled in the new well.

Scientists used a graphical method called a “Stiff diagram” to compare the compositions of the various water sources.28 Each plot shows the relative concentrations of anions and cations for a particular water sample, scaled in milliequiva-lents per liter (meq) (left).29 All samples of the produced water showed a similar pattern. However, samples from the new well exhibited differences. The samples from Zones 2 and 3 had patterns resembling those of the produced water, while Zones 4 and 6 contained waters with dis-tinctly different compositions.

> Fluid sampling data. In a well drilled with OBM to facilitate water sampling, ADCO collected fluids from five of six carbonate zones. The water in Zone 4 is clearly different from that in the other water-filled zones. The water from Zone 6 may be different from the water in Zone 3; these data were combined with those shown below and on the next page to determine the source of water produced from Zone 2.

1 Oil Oil sample HighHighOWC delineationOil and water2

Water 6.5 6.61 mD to 10 mDpH, water sample3Water Less than 1 mD 7.3 7.8pH, water sample4Water Too tight to flowNone5Water 6 6.3Less than 1 mDpH, water sample6

Zone Fluid Measurement Permeability Downhole pH Modeled pH

> Comparing water compositions. Stiff diagrams allow visual identification of similarities and differences between water samples. Concentrations of cations are plotted to the left of the vertical axis, and concentrations of anions are plotted to the right. Compositions of water samples from the producing wells (top) are all similar, whereas compositions of samples from the new well (bottom) show large variability. The waters from Zones 2 and 3 are similar to the produced water, but the compositions of samples from Zones 4 and 6 are different in most cations and anions.

Na+K/1,000 Cl/1,000

Sulfate/10Ca/100

–10 –8 –6 –4 –2 2 4 60

Carbonate/10

meq

Mg/10

Na+K/1,000 Cl/1,000

Sulfate/10Ca/100

–10 –8 –6 –4 –2 2 4 60

Carbonate/10

meq

Mg/10

Oil producers Zone 2Zone 3Zone 4Zone 6

Oil producers

Spring 2011 33

Isotopic analysis corroborated the composi-tional information. A plot of hydrogen and oxygen isotope ratios for samples from the new well con-firmed that the water from Zone 3 was similar to that in Zone 2. Also, the waters from Zones 4 and 6 were quite different from each other and from those of Zones 2 and 3 (above). Strontium isoto-pic ratios were also different.

These analyses showed that Zone 3 is the source of water produced in Zone 2—the oil- producing layer—allowing ADCO engineers to conclude that water sweep is from the flanks of the reservoir, and there is no water support from Zones 4 and 6, below the reservoir.

Laboratory Measurements on Live WatersTraditional laboratory analysis is usually per-formed on “dead” or stock tank water, and this analysis may be useful for production surveil-lance. However, during the initial exploration and appraisal stages, when the operator builds an understanding of the reservoir fluids and uses that data for modeling water chemistry at reservoir and pipeline conditions, it is critical to work on representative live-water samples.

Through downhole fluid analysis, specialists are able to perform direct measurements on live fluids—fluids that still contain dissolved gas— at reservoir conditions. Furthermore, sample- collection technology, which has the ability to monitor contamination and maintain water sam-

ples at elevated pressure, allows operators to bring live fluids to the surface and transport them intact to a laboratory.

In the laboratory, the collected water samples are reconditioned to downhole temperature and pressure, encouraging any gases and solids that have come out of solution to redissolve. The sam-ples are flashed—the sample bottles are opened and the fluids are exposed to surface pressure and temperature—before laboratory analysis. Laboratory specialists measure the gas/water ratio (GWR) and perform gas chromatography to analyze the composition of the liberated gas. They also analyze ion composition, pH and low–molecular weight organic acids in the water phase. A more rigorous process employed by some operators involves partitioning the flashed water sample into three parts. Acid is added to one part of the sample to preserve cations, which are then analyzed by inductively coupled plasma (ICP). Sodium hydroxide is added to the second part to preserve organic acids, which are then

analyzed by ion chromatography. The third por-tion is kept untreated and is used to measure density, pH, conductivity, alkalinity (by titration) and anions by ion chromatography.

For the most part, commercial laboratories have not been equipped to directly analyze live water at reservoir conditions, but some are mak-ing advances in this direction. Schlumberger sci-entists have developed a new laboratory technique for measuring pH of live formation water samples at reservoir temperature and pressure.30 The sam-ple remains in the pressurized bottle in which it was brought to the surface. A heated jacket brings the bottle to reservoir temperature. As the water sample flows through a pressurized flowline—which is similar to the tool flowline—it mixes with the same dye used in the downhole measure-ment, and the fluid mixture passes through a spectrometer that analyzes the color.

Comparison of the laboratory pH measure-ment with the real-time in situ pH measure-ments made on the same formation water allows

27. Carnegie AJG, Raghuraman B, Xian C, Stewart L, Gustavson G, Abdou M, Al Hosani A, Dawoud A, El Mahdi A and Ruefer S: “Applications of Real Time Downhole pH Measurements,” paper IPTC 10883, presented at the International Petroleum Technology Conference, Doha, Qatar, November 21–23, 2005.

28. Stiff HA: “Interpretation of Chemical Water Analysis by Means of Patterns,” Transactions of the American Institute of Mining and Metallurgical Engineers 192 (1951): 376–378. [Also published as paper SPE 951376 and reprinted in Journal of Petroleum Technology 3, no. 10 (October 1951): 15–17.]

Zone

Zone 3 Zone 2

Zone 6

Zone 4Zone 2

87Sr/86Sr

Zone 3

Zone 4

Zone 6

2

3

4

5

6

0.7074 0.7076 0.7078 0.7080

–10

10

–5 5δ18OSMOW

δDSM

OW

δ = Rsample × 1,000Rstandard

– 1

SMOW

Rsample = ratio of heavy to light isotope in the sample

Rstandard = ratio of heavy to light isotope in standard mean ocean water (SMOW)

> Isotopic analysis of water samples from the new ADCO well. Many elements have isotopes, or atoms with different atomic weights. The most common form of hydrogen (with one proton) has an atomic weight of 1, and is written as 1H. A less common isotope, 2H, with one proton and one neutron, is usually written as D, for deuterium. Similarly, oxygen has three isotopes, 16O, 17O and 18O. Isotopes have similar chemical properties but different physical properties. For example, they “fractionate” during evaporation and condensation, leaving water enriched in heavy isotopes. Comparing ratios of hydrogen and oxygen isotopes is a common method to distinguish waters from different sources. In the ADCO case, analysis shows that the water in Zone 4 is different from those in the other zones (left). Comparison of strontium [Sr] isotope ratios (right) is another technique for highlighting differences between water sources. Here, waters from Zones 4 and 6 are significantly different from those in Zones 2 and 3.

29. An equivalent is the amount of a material that will react with a mole of OH– or H+. A milliequivalent is an equivalent/1,000.

30. Mathews SG, Raghuraman B, Rosiere DW, Wei W, Colacelli S and Rehman HA: “Laboratory Measurement of pH of Live Waters at High Temperatures and Pressures,” paper SPE 121695, presented at the SPE International Symposium on Oilfield Chemistry, The Woodlands, Texas, USA, April 20–22, 2009.

34 Oilfield Review

fluid analysts to validate the integrity of the sample. A good match indicates the sample is still representative of the formation water. Sample validation in this manner is an imple-mentation of the “chain of custody” concept.31 The laboratory setup also allows chemists to measure the live-water pH as a function of tem-perature and pressure and flag the onset of scale precipitation. These additional measure-ments can be used to better constrain and tune water-chemistry models.

Chevron tested this technique on formation water samples from two Gulf of Mexico wells.32 In Well A, the zone of interest is a thick, permeable water zone—a potential supply for injection water—thousands of feet above the reservoir. The company wanted to assess the corrosion potential of the water and evaluate its compatibility with the reservoir formation water. Downhole mea-

surements of pH were made and samples were collected at two depths. Laboratory measure-ments matched the downhole measurements to within 0.08 pH units, giving Chevron chemists confidence that the reconditioned live samples were representative of formation water.

Comparison with predictions from two differ-ent simulators indicated a good match (within 0.15 units) for one sample. For the second sam-ple, the discrepancies were larger, not just between predicted and measured values, but also between the two commercial models used for the simulation (0.24 to 0.65 units). The reasons for the differences in predicted values from the two simulators are due to the different thermody-namic databases upon which they are based, as well as the different approaches to using the inputs in modeling. The differences highlight the

uncertainties that can arise when flashed water analysis is used as input to simulators and under-score the importance of direct measurements on live waters to constrain and tune the models.

In Well B, the zone of interest is a water-rich interval beneath the oil target; it is considered to be a potential source of water cut sometime in the future life of the field. The pH of this water may have sizeable impact on equipment design, selection and costs.

Live-water pH measurements were performed at the in situ temperature of 242°F [117°C] and pressure of 19,542 psi [134.7 MPa], and then at pressures down to 8,000 psi [55 MPa] to test the sensitivity of the measurement to pressure (left). Fluid analysts monitored the optical signal dur-ing this change in pressure and did not detect any solid precipitation from scale onset or gas evolution that would have caused light scatter-ing. This indicates that the water stayed as a sin-gle phase all the way from reservoir pressure down to 8,000 psi. The ability to measure pH and track scale onset with pressure and temperature in this setup makes it a potentially powerful method to collect data for tuning and improving confidence in water chemistry simulator models.

Other Fluid MeasurementsDownhole fluid analysis currently can quantify many fluid properties in situ, including pressure, temperature, resistivity, density, composition, gas/oil ratio, pH, fluorescence and optical den-sity. Although most of these fluid property mea-surements were originally designed with hydrocarbons in mind, several of them—in addi-tion to pH—may be applied to analysis of forma-tion water.

Recently, a downhole fluid density measure-ment was tested as an alternative to pH for detecting WBM contamination and oil/water contacts. The InSitu Density sensor is a tiny vibrating rod—a mechanical resonator—in the tool flowline. The resonance frequency of the rod decreases as the fluid density increases. The den-sity measurement is useful when the pH of the WBM is similar to that of the formation water. Another advantage is that density measurements may aid in fluid typing in cases that are problem-atic for pressure-gradient interpretation of fluid contacts, such as thin beds, low-permeability for-mations and poor-condition wellbores.

The InSitu Density device has been used for downhole water analysis in WBM-drilled wells off-shore Vietnam, Norway and China.33 Appli cations include monitoring contamination cleanup before collecting water samples, analyzing formation

> High-pressure, high-temperature (HPHT) laboratory measurements of pH. Schlumberger scientists performed pH measurements on live waters at reservoir pressure and temperature (19,542 psi and 242°F) and at a range of pressures down to 8,000 psi (bottom). The optical spectrum of the aqueous system was measured using probes connected to an HPHT scanning cell (top right). Optical signal monitoring (top left) indicated that water stayed in single phase down to 8,000 psi with no scale onset. The pH measurement is calibrated only to 10,000 psi: The scarcity of thermodynamic data in the literature makes calibration difficult and uncertain at pressures greater than that. In this figure, calibration parameters for 10,000 psi are used for the data at pressures of 10,000 psi and greater, which are indicated by a dashed line.

pH

Pressure, psi8,000 12,000 16,000 20,000

6.3

6.2

6.1

6.0

5.9

5.8

Spring 2011 35

water for future reinjection with seawater, evalu-ating of reservoir vertical connectivity and assess-ing flow assurance in pipelines and flow streams to be tied back to processing equipment on a main platform.

In an exploration example from offshore China, pressure pretests in five sands yielded inconclusive fluid-typing results in all but the deepest zone, Sand E, which had a pressure gra-

dient indicative of oil. Only one pressure reading could be obtained from each of Sands A, B and C, so it was impossible to compute gradients in those zones. The gradient from the two pressures measured in Sand D corresponded to the mud density, indicating whole-mud invasion. Optical analysis of fluids pumped from the five sands gave additional but surprising information: Sands A and C produced water, and Sands B and D pro-duced oil. Real-time downhole fluid density mea-surements on these same fluids corroborated the optical and pressure analyses and helped deter-mine the free-water level in Sand B (above).

The number of fluid analysis measurements that can be made in situ is increasing. Current capabilities have been likened to having a down-hole fluids laboratory.34 Undoubtedly some of the

new measurements will find applications to for-mation water analysis, increasing the ability of oil and gas companies to understand their reser-voirs, optimize completions, select materials and monitor water injection.

Extending the array of downhole measure-ments will likely force high-pressure, high- temperature laboratory techniques to keep pace. Currently, high-accuracy pH measurements can be made both in situ and at similar conditions in the laboratory. In the future, additional analyses will extract even more information and value from formation water. —LS

> Looking for fluid contacts. Fluid densities interpreted from gradients in pressure measurements (left) in five sands indicated oil only in the deepest zone, Sand E (below 2,200 m). Pressure measurements (dots) are color-coded based on quality: green is high and yellow is satisfactory. In Sand D, around 2,100 m, the gradient suggests a fluid heavier than water, such as drilling mud. Optical characterization (middle, Depth Track) of the fluids pumped from Sands A and C identified these intervals as water-prone layers (blue shading in Depth Track); Sands B and D contain oil (green

shading in Depth Track). Measurements from the InSitu Density tool give precise density values (gray shaded) for these fluids, values that can be extended along pressure gradients. In an expanded view (right), gradient analysis helps interpreters understand reservoir architecture. The intersection of the water gradient in Sand C (lower blue line) with the oil gradient in Sand B (green line) identifies the free-water level in Sand B at 1,693.5 m. The nonintersection (dashed circle) of the water gradients confirms the lack of communication between Sand B and Sand A.

Formation Pressure, psi

Pretest Quality Pretest Quality

Gamma Ray

Sand ASand A

Sand B

Sand C

Sand B

Sand C

Sand D

Sand E

Dry Test

0

2,200 3,200

gAPI 250

1,600

1,600

1,700

1,700

1,800

1,900

2,000

2,100

2,200

Lost Seal

Depth, m

FluidFraction

Formation Pressure, psi

Gamma Ray

Dry Test

0

2,200 3,200

gAPI 250

Lost Seal

Depth,m

FluidFraction

1.3545 g/cm3 (mud)

1.0124 g/cm3 (water)

1.0195 g/cm3 (water)

0.8859 g/cm3 (oil)

0.7807 g/cm3 (oil)0.8929 g/cm3 (oil)

0.8859 g/cm3 (oil)

1.0124 g/cm3 (water)

Free-water level: 1,693.5 m

1.0195 g/cm3 (water)

Pretest Quality

Formation Pressure, psi

Gamma Ray

Dry Test

0

2,200 3,200

gAPI 250

Lost Seal

1.3545 g/cm3 (mud)

0.7807 g/cm3 (oil)

31. Betancourt SS, Bracey J, Gustavson G, Mathews SG and Mullins OC: “Chain of Custody for Samples of Live Crude Oil Using Visible-Near-Infrared Spectroscopy,” Applied Spectroscopy 60, no. 12 (2006): 1482–1487.

32. Mathews et al, reference 30.33. Mas C, Ardilla M and Khong CK: “Downhole Fluid

Density for Water-Base Mud Formation-Water Sampling with Wireline Formation Tester,” paper IPTC 13269, presented at the International Petroleum Technology Conference, Doha, Qatar, December 7–9, 2009.

34. Creek et al, reference 18.

36 Oilfield Review

Zapping Rocks

By zapping a formation with microwave energy, dielectric logging tools can analyze

freshwater environments and identify movable hydrocarbons. The measurements

made by these tools are especially useful in characterizing heavy-oil reservoirs. After

a long period of niche application, a new tool is breathing life into this technology.

This resurgence is aided by a recently developed dispersion technique that evaluates

carbonate rock texture and shale effects in sandstones.

Romulo Carmona Petróleos de Venezuela, S.A.Caracas, Venezuela

Eric Decoster Rio de Janeiro, Brazil

Jim HemingwayHouston, Texas, USA

Mehdi HizemLaurent MosséTarek RizkClamart, France

Dale JulanderChevron U.S.A. Inc.Bakersfield, California, USA

Jeffrey LittleBakersfield, California

Tom McDonaldPerth, Western Australia, Australia

Jonathan MudePetroleum Development OmanMuscat, Sultanate of Oman

Nikita SeleznevCambridge, Massachusetts, USA

Oilfield Review Spring 2011: 23, no. 1. Copyright © 2011 Schlumberger.Dielectric Pro, Dielectric Scanner, EPT, FMI, HRLA, LithoDensity, MR Scanner, Platform Express, and Rt Scanner are marks of Schlumberger.

Petroleum technologists enjoy finding new meth-ods to poke, prod and probe the Earth. One such technique, dielectric logging, involves zapping a formation with microwaves to determine rock and fluid properties. Although not widely used within the petrophysics community, dielectric informa-tion answers a number of difficult interpretation questions. The success of a recently introduced dielectric tool is generating considerable interest because it provides information that isn’t readily available from standard logging suites.

Introduced to the oil and gas industry in the late 1970s, dielectric logging did not find univer-sal acceptance. Lack of acceptance of new tech-nologies is not unusual. Technologies often need time to evolve, gain a level of appreciation by users and, finally, be assimilated. The first com-mercial microwave oven, for example—a radi-cally new technology at the time—was introduced in 1947. It was taller than the average man and weighed more than three times as much. Not sur-prising, domestic sales were nonexistent. But

1. Serra O: Well Logging Handbook. Paris: Editions Technip, 2008.

2. Dispersion is the variation in dielectric permittivity and conductivity when measured at different frequencies.

3. Serra, reference 1.4. Named for James Clerk Maxwell, this set of partial

differential equations unifies the fundamentals of electricity and magnetism. There are four basic equations, but multiple iterations can be developed from them. For a full derivation of the equations related to electromagnetics and dielectric response: Serra, reference 1.

5. Depending on the reference source, microwaves are generally considered electromagnetic waves with wavelengths from 1 m to 1 mm, which corresponds to a frequency range of 300 MHz to 300 GHz.

Spring 2011 37

today, compact units that little resemble those early industrial-grade models are standard equip-ment in kitchens around the world.

Radically new technologies fall into different categories of acceptance. Some fully supplant older technologies. Others supplement existing methods without replacing them. In the example of the microwave oven, although it may be possi-ble to prepare a complete multicourse meal with one, rarely is it the primary method of meal prepa-ration. However, as a means for reheating food, a microwave oven is usually a better option than previous methods, such as a conventional oven. Clearly, it is a supplemental technology.

Similarly, a dielectric tool is a supplemental technology for the oil and gas industry. These tools were originally developed to analyze forma-tions with freshwater, low-salinity water or where water salinity was unknown. They respond pri-marily to the water in the pore network and mea-sure water-filled porosity. From water-filled porosity, resistivity-independent fluid saturations can be derived. Log analysts also combined dielectric measurements with data from deeper-reading tools to identify zones with hydrocarbon mobility, which is crucial information for evaluat-ing heavy-oil reservoirs.

Unfortunately, data quality for early- generation tools was frequently compromised by hole rugosity—a common condition in the environments in which these tools offered the greatest benefit—and measurement accuracy was difficult to quantify. After sparking initial interest within the petrophysics community, dielectric tools never reached a level of universal acceptance for formation evaluation. The intro-duction of nuclear magnetic resonance (NMR) tools in the 1990s virtually ended the use of microwave-based dielectric tools, except in some specialized applications.1

The recently introduced Dielectric Scanner multifrequency dielectric dispersion service is designed to overcome limitations of earlier tools. It has the ability to measure water-filled porosity, and, in conjunction with other porosity measure-ments, fluid saturations. Its collocated trans-mitter-receiver arrays probe the formation at multiple depths of investigation and offer stand-alone oil mobility assessment in heavy-oil reservoirs. In addition, the tool offers a new measurement—dielectric dispersion—with which petrophysicists can determine rock textural prop-erties and shale effects.2

This article presents the basic theory of dielectric measurements applied to petrophysics, including a description of the new dielectric dis-persion technique. Case studies describe textural

analysis of carbonates, evaluation of formations with variable- or low-salinity formation water and heavy-oil applications.

Microwave Frequency LoggingThree parameters define a rock electrically: magnetic permeability, electrical conductivity and dielectric permittivity.3 Reservoir rocks com-prise mostly nonmagnetic minerals, thus their magnetic permeability is negligible. Because the rock matrix has little conductivity, the electrical conductivity of the formation, the inverse of resistivity, is primarily a function of the fluids that fill the pore network and the connectivity of the pores. Formation conductivity is generally measured with induction and laterolog devices and is a crucial input, along with porosity, in Archie’s water saturation equation.

Dielectric permittivity is not a measurement that is generally considered when evaluating reser-voir rocks. It is defined as the frequency-dependent capacity of a medium to store energy from an applied field and is a function of the degree to which a material becomes polarized in the presence of an electric or electromagnetic field. A material’s dielectric permittivity, ε, can be expressed as its dielectric constant, which is the permittivity nor-malized to the lossless environment of a vacuum. The dimensionless dielectric constant is not really a constant because it is a function of the frequency of the electromagnetic field. It is computed from dielectric data using Maxwell’s equations.4

For most minerals and fluids found in reser-voir rocks, with the important exception of water, dielectric permittivity is quite low (above). For water, the absolute dielectric permittivity, ε*, comprises three terms: a real term related to polarizability, a complex term related to conduc-tivity at a given frequency and a second complex term related to dipolar relaxation (below).

Because of the large difference between matrix and water permittivities, a reservoir rock’s dielec-tric permittivity measured in the microwave range is primarily a function of the water filling the pores.5 The permittivity values of oil and the matrix are similar, and as a result, the presence of hydrocarbons makes it impossible to invert for

> Dielectric constants for common minerals, rocks and fluids.

Petroleum 2.0 to 2.4Gas 1.0

Water 56 to 80

Gypsum 4.16Anhydrite 6.35

Sandstone 4.65Dolostone 6.8Limestone 7.5 to 9.2

Shale 5 to 25Dry colloids 5.76Fresh water 78.3

Minerals, rocks, fluids Relative dielectric constant(relative to vacuum)

> Dielectric permittivity plot for water. The absolute dielectric permittivity, ε*, for bulk water comprises a combination of real and complex terms and is a function of the frequency of the electromagnetic field. The real component, εr (blue), is linear to about 1 GHz and then decreases as the frequency of the electromagnetic field increases. The complex conductivity term (black) depends on the frequency of the electromagnetic field, ω, and is normalized for the permittivity of vacuum, ε0. The conductivity component decreases as the frequency increases, especially across the frequency range used in downhole dielectric tools. The second complex term, iεx (purple), is related to dipolar relaxation and peaks around 20 GHz. It has minimal effect on the total permittivity measured by downhole tools because they operate in a frequency range below about 1.1 GHz.

Dipolar

Atomic Electronic

Bulk water 25°C

1.1 GHz 20 GHz Infrared Ultraviolet

Frequency

rε

xε

σωε

= + +i*r i x

0

0

ε ε εσωε

38 Oilfield Review

both water-filled porosity and total porosity using dielectric data alone. However, in conjunction with an independent porosity measurement, dielectric data can quantify fluid saturations.

A second factor affecting a rock’s dielectric permittivity and conductivity is the manner in

which its different constituents are mixed together. This factor is generally small when mea-sured at a frequency of about 1 GHz but domi-nates the measurement at lower frequencies. For this reason, rock texture and shale content can cause frequency-sensitive dispersion in both permittivity and conductivity measurements.

Schlumberger introduced the first commer-cial downhole device capable of measuring dielectric properties using microwaves, the EPT electromagnetic propagation tool, in the late 1970s.6 It operated at a single frequency of 1.1 GHz and measured attenuation and phase shift of waves traveling through the formation. Mathematical inversions were then applied to the attenuation and phase shift to derive petro-physical properties—including dielectric per-mittivity, conductivity and water-filled porosity (left). Petrophysicists determined fluid satura-tions by comparing this water-filled porosity to the total porosity.

After the introduction of the EPT tool, other service companies developed dielectric tools, each designed to operate at a company-chosen frequency. Because of the frequency dependence of dielectric information, data recorded at differ-ent frequencies often yielded different results and comparing the results between wells could be problematic. The differences can be attribut-able to the measurement’s sensitivity to rock tex-ture, clay content and fluid salinity. These sensitivities, however, were not well understood.

Water-filled porosity from the earliest tools was computed following the tpo method, which is based on the propagation time of the electromag-netic waves as they passed through the rock (below left). This calculation involved a simple transform that resembles the Wyllie equation used to compute sonic porosity. It requires knowl-edge of the water salinity and temperature to esti-mate the propagation time in formation water.

Formations, however, consist of more than just water. There are pore fluids—water, oil and gas—and minerals in the rock matrix. Relationships between each of these constituents, as they exist in the formation, can alter the electromagnetic waves. The tpo method was not adequate for com-puting water-filled porosity and, therefore, various mixing laws have been proposed to account for the interaction of the electromagnetic field with the various elements in the formation.7

The complex time average (CTA) method, com-bining both phase-shift and attenuation measure-ments, was an early technique for calculating petrophysical properties of a mixture. Two inde-pendent equations can be written, one for phase shift and one for attenuation of the signal, to deter-mine the volume of water in the pore network.

An alternate approach, the complex refrac-tive index (CRI) method, is based on Maxwell’s equations. Because of the time-dependent sinu-soidal nature of an electromagnetic field, the time derivative of Maxwell’s equations can be greatly simplified.8 It is reduced to two terms that

>Microwaves to petrophysics. The dielectric tool transmits an electromagnetic wave (red sine wave) with a frequency ω into a formation where, as a result of interactions with the fluids and minerals, its amplitude is attenuated and the velocity of the wave changes. The velocity change corresponds to a measureable phase shift. The change in amplitude, Α, and the phase shift of the wave (black sine wave) after it has passed through the media are measured at the receiver; they are functions of the initial frequency, ω, dielectric permittivity of the media, ε, the conductivity of the media, σ, and the transmitter-to-receiver spacing, r. The change in amplitude and phase shift are then inverted to output permittivity, conductivity and water-filled porosity, φ.

Transmitter ReceiverChange in amplitudePhase shift

Frequency,

} {φ

ƒ –1

ConductivityWater-filled porosity

PermittivityAmplitude change ΑPhase shift

Transmitter-to-receiver spacing, r

VacuumMedium

= ƒ r, , , )(Receiver voltageω ω

σ

σ

ε

ε

> Evolution of dielectric petrophysics. An early porosity transform for dielectric tools, the tpo method (top), looks similar to the Wyllie equation used to compute porosity from acoustic data. The transfrom is valid only for lossless traveltime, which is not representative of the downhole environment. The complex time average (CTA) method (middle) provides water-filled porosity from attenuation, traveltime and water saturation in the flushed zone. It includes corrections for losses, but is not as accurate as the complex refractive index (CRI) method (bottom). The CRI method uses the dielectric permittivity, ε*, measured at downhole conditions. Matrix, hydrocarbon and water permittivities, used in the equation, are also adjusted for downhole conditions. Water saturation is solved for using a total porosity, φT, provided by another source, such as the crossplot porosity from density and neutron tools.

φtpo tpma

tpwo tpma=

––

= lossless traveltimetpo = traveltime through the matrixtpma

tpwo = lossless traveltime through water

tpo methodEPT

= water saturation in the flushed zoneSxo

= attenuation through water = attenuation (tool measurement)

tpma = traveltime through the matrixtpw = lossy traveltime through watertph = lossy traveltime through hydrocarbon

tpl = lossy traveltime (tool measurement) CTA method

= porosityφ Sxotpw tph tpmaSxotpl = + +1– 1–

Sxo=

( ) ( )

w

Α

Α

wΑ

Α

= water saturationSφ = total porosity

CRI method = dielectric permittivity*

S S( ) ( ) )(* **

= + +1– 1– oil

= permittivity of the matrix = permittivity of water = permittivity of hydrocarbonoilw

ww

w

T m

m

wT

T

ε ε ε ε εεεε

φ φφ

φ φ

φ

Spring 2011 39

define the absolute dielectric permittivity, a real-number permittivity term and a complex frequency-dependent conductivity term.9 The complex number term consists of the angular fre-quency of the applied electromagnetic field and a conductivity that can be expressed as a real number. A single equation transforms the propa-gation time and attenuation into physical quanti-ties—permittivity and conductivity. Because matrix minerals and hydrocarbons are poor con-ductors and generally act as insulators, the con-ductivity signal is dominated by the water in the region sensed by the tool—the flushed zone. Solving for the dielectric conductivity provides the conductivity of the fluids that fill the pores in the near-wellbore region.

Mud filtrate from the invasion process enters the flushed zone and alters the properties of the fluids that were originally in place. This invasion is not uniform or easily quantified. Early methods for computing dielectric properties, such as the tpo method, assumed fixed values of fluid conduc-tivity. Directly solving for the conductivity of the fluid in this region, which is possible with the CRI method, provides more-accurate results for the water-filled porosity measurement. For this and other reasons, the CRI method has become the generally accepted technique for computing pet-rophysical properties from dielectric data.10

In addition, textural parameters of rocks, which are difficult to quantify from the tools used in conventional logging suites, can be derived from the dispersion of dielectric data made at mul-tiple frequencies. At frequencies around 1 GHz, tex-tural parameters have limited effects on outputs derived from the CRI method. An exception, how-ever, is high-salinity environments, which can enhance textural dispersion even with frequen-cies in the 1-GHz range. At lower frequencies, tex-tural effects significantly impact dielectric permittivity measurements—this is especially true in carbonate reservoirs.11 Several dispersion models have been developed to account for the frequency-dependent phenomenon.

A dispersion analysis, discussed below, has been developed that uses multifrequency dielec-tric outputs to quantify the cementation expo-nent, m, which is one of two crucial texture-related inputs in Archie’s water saturation equation. For carbonates, values for these parameters are gen-erally derived from core data, which are then applied to offset wells. The method used for mea-suring these parameters from core is a lengthy and expensive process. With continuous outputs of m for Archie’s equation from dielectric dispersion

information, petrophysicists can better evaluate carbonates using downhole data. Accurately char-acterizing texture in this rock type is important because an estimated 60% of the world’s remain-ing oil is found in carbonate reservoirs.

Dielectrics and Dipoles Materials that become polarized when exposed to a static electromagnetic field are referred to as dielectrics.12 A material’s susceptibility to polar-ization is directly related to its dielectric permit-tivity. There are three primary polarization

mechanisms that can be related to petrophysical properties: electronic polarization, molecular ori-entation and interfacial polarization (above). To understand how electromagnetic waves interact with various media, consider a porcelain mug, filled with coffee and placed in a microwave oven. The mug is essentially unaffected by the micro-waves as they pass through it, but the coffee in the mug heats rapidly. Accidently leaving a metal spoon in the mug can be disastrous because of the interaction of microwaves with good conductors such as metal.

6. A Russian dielectric tool predated the EPT tool by 10 years but had limited availability.

7. For more on the various mixing laws: Seleznev N, Boyd A and Habashy T: “Dielectric Mixing Laws for Fully and Partially Saturated Carbonate Rocks,” Transactions of the SPWLA 45th Annual Logging Symposium, Noordwijk, The Netherlands (June 6–9, 2004), paper CCC.

8. For assumptions made and the full derivation from Maxwell’s equations: Böttcher CJF and Bordewijk P: Theory of Electric Polarization: Dielectrics in Time-Dependent Fields, vol 2, 2nd ed. New York City: Elsevier Scientific Publishing Company (1978): 10–19.

9. A third complex number can be ignored for downhole applications.

10. The CRI method was proposed in Wharton RP, Hazen GA, Rau RN and Best DL: “Electromagnetic Propagation

> Polarization mechanisms. Several mechanisms related to a material’s polarizability affect dielectric measurements. For electronic polarization (top), balanced atomic structures may shift in the presence of an electromagnetic field, E, but the effects are minimal. In contrast, water molecules exhibit orientational polarization (middle) because they are dipolar. In the initial state, these easily polarizable water molecules are found as randomly oriented dipoles. When exposed to an electromagnetic field, they attempt to align with the direction of the field. Interfacial polarization for reservoir rocks (bottom) is influenced by the presence of charged clays, brine and oil in the pore network and the matrix minerals. Minerals and elements in the rock that might not be polarizable in isolation often behave differently in a mixture, exhibiting a larger permittivity value than any of the constituent components. This phenomenon is an example of the Maxwell-Wagner effect.

E = 0PolarizationType

Electronic

Orientational

Interfacial

MatrixSalt ionsWater

Oil

8+ 8+

Center of + and –

Center of –Center of +

8++

+

E

Logging: Advances in Technique and Interpretation,” paper SPE 9267, presented at the 55th SPE Annual Fall Technical Conference and Exhibition, Dallas, September 21–24, 1980.

For a comparison of the CTA and CRI methods: Cheruvier E and Suau J: “Applications of Micro-Wave Dielectric Measurements in Various Logging Environments,” Transactions of the SPWLA 27th Annual Logging Symposium, Dallas (June 9–13, 1986), paper MMM.

11. Kenyon WE: “Texture Effects on Megahertz Dielectric Properties of Calcite Rock Samples,” Journal of Applied Physics 55, no. 8 (April 15, 1984): 3153–3159.

12. Melrose DB and McPhedran RC: Electromagnetic Processes in Dispersive Media. Cambridge, England: Cambridge University Press, 1991.

40 Oilfield Review

These materials respond to electromagnetic energy differently because of their atomic and molecular properties and their intrinsic conductivi-ties. Rather than becoming polarized when struck by microwaves, metal objects, such as the spoon, may experience an induced current. This is because there are free electrons in the metal that move when it is exposed to the electromagnetic field. Resistance to current flow can generate extreme heat and the induced current may arc if a conduc-tive path is unavailable. Because they are electrical conductors, most metals have a dielectric permittiv-ity that can be a negative value. For this reason, metals are not generally classed as dielectrics.

The porcelain mug, on the other hand, is nom-inally affected by the electromagnetic field, and it becomes only slightly polarized. The origin of its polarization lies in the electronic clouds surrounding the nuclei of the atoms. When the electric field is applied, the electrons’ trajecto-ries shift. This phenomenon is called the elec-tronic polarization. The resulting dielectric constant, in the range from 5 to 7, is similar to that of reservoir rocks.13

The coffee, or more specifically, the water portion of the coffee, exhibits an entirely different behavior in the presence of the electromagnetic field. Water molecules—composed of two hydro-gen atoms and one oxygen atom—are asymmetri-cal: the centers of their positive and negative charges do not coincide. This asymmetry results in a permanent dipole moment for water mole-cules. Because of its much greater susceptibility to polarization, water’s dielectric constant is around 80—an order of magnitude higher than that of porcelain.

In the absence of an electric field, individual water dipoles point in random directions, so the net moment per unit volume is zero. However, when an electric field is applied, in addition to electronic polarization of the oxygen and hydro-gen atoms, the field tends to orient the individual dipoles, resulting in a net positive moment per unit volume. This effect is called orientational polarization. The collisions of the molecules in their thermal motion disorient the molecules and limit the net dipole moment per unit volume. Thus the magnitude of the orientational polariza-tion is a result of the type of polar molecule and its temperature.

Orientation of polar molecules under the influence of an applied field is not instantaneous. It requires a finite time due to the molecular moment of inertia and, as a result, there is resis-tance to realignment as the field reverses direc-tion. If the frequency of the applied field is sufficiently high, for instance in the microwave range, the polar molecules do not have enough time to orient along the field direction and the contribution of orientational polarization is diminished. The water molecules’ resistance to the rapidly changing polarity can be expressed as heat. This phenomenon is referred to as dipolar relaxation loss.

A dielectric phenomenon of saltwater, or brine, is that with increasing salinity, the conduc-tivity of a solution increases but the permittivity of the solution decreases. Adding salt to a solu-tion increases the number of water molecules nonrotationally bound to the NaCl molecules, thereby decreasing the orientational polariza-tion. At the same time, the concentration of ions

contributing to current conduction increases. A temperature increase has a similar effect on the solution properties: the solution conductivity will increase, and the solution permittivity will decrease due to the stronger effect of the thermal dipole disorientation.

As the electromagnetic wave passes through various media, it is altered by interaction with the media. The amplitude and the velocity of the wave decrease as a function of the amount of energy imparted, and the phase of the wave shifts. For materials with low dielectric constant values, such as the coffee mug or rock matrix, there are minimal effects on the returning elec-tromagnetic wave. In contrast, water’s high dielectric constant causes a large effect.

As early as the 1950s, petrophysicists experi-menting with microwaves recognized that the dielectric permittivity measurement from satu-rated core samples was controlled primarily by the amount of water in the pores and could be directly related to water-filled porosity. However, to compute the water fraction of a rock sample from dielectric measurements, the relationships between the dielectric properties of the constitu-ents that comprise the core sample must be known. Mixing laws were established under controlled laboratory conditions to model the effects of these relationships.

In the laboratory, dielectric properties can be measured by different methods employing vari-ous sample sizes and shapes. The measurement technique depends on the frequency of interest. For instance, the capacitive technique is typically employed for frequencies up to several MHz. The material is placed between the plates of a capacitor, and from the measurements of the capacitance the dielectric constant can be calcu-lated. This model works well if the wavelength is much longer than the space between the conduc-tor plates.

At high frequencies, it is difficult to measure the total voltage and current at the device ports. Because of the impedance of the probes and the dif-ficulty of placing the probe at the desired position, one cannot simply connect a voltmeter or a current probe and get accurate measurements. For frequen-cies in the GHz region, scientists developed tech-niques such as a transmission line or a microwave resonator. Transmission line methods are widely utilized because they allow for broadband measure-ments. The spanned bandwidth is limited, on the low end, by decreasing sensitivity to the sample’s dielectric constant with increasing wavelength. The maximum measurement frequency depends on the type of the transmission line, the forward model and the limitations of the acquisition system.

> Saturation from dielectric measurements. Petrophysicists generally use Archie’s water saturation equation, which requires inputs for porosity and resistivity. The dielectric method requires no resistivity. The simplified relationship shown here demonstrates how this is carried out. The dielectric porosity is a measurement of the water-filled portion of the porosity. When all the pore space is filled with water (left), the porosity from the dielectric tool, φDielectric, matches the total porosity measurement, φTotal, which must come from another source such as density-neutron crossplot porosity. Because their dielectric properties are similar, hydrocarbons are indistinguishable from the matrix for dielectric measurements. Thus, decreases in the porosity as measured by the dielectric tool that are not mirrored by the total porosity relate directly to increases in the volume of hydrocarbons (right).

30% Water, 70% Matrix 10% Water, 20% Oil, 70% Matrix

φφ φ

φTotal = 30%

Dielectric = 30%

Sw = 100%

Total = 30%

Dielectric = 10%

Sw = 33%

Spring 2011 41

Quantifying water-filled porosity from dielec-tric measurements is important because the ratio of the water-filled porosity to the total porosity represents the water saturation (previous page). The dielectric permittivity measurement can determine water saturation independent of a resistivity measurement—a critical and necessary input for Archie’s water saturation equation.14

Both freshwater and hydrocarbons have high resistivity values. Typical oilfield brines found in reservoir rocks have low resistivity. Archie’s equation is based on the assumption that a contrast exists between the resistivity of hydrocarbon-bearing formations and those filled with brine. It does not provide accurate satura-tion results in reservoirs with freshwater, low-salinity water or where the salinity of the formation water is unknown. In these environ-ments, the large contrast between the dielectric permittivity of hydrocarbons and water, regard-less of brine salinity, makes for an ideal satura-tion measurement.

Nuclear magnetic resonance (NMR) tools are also able to detect hydrocarbons in freshwa-ter environments by measuring the diffusion of the fluids.15 Because they do not rely on the resistivity of the fluids in the pore spaces to determine saturations, dielectric and NMR tools are often the primary means for quantifying hydrocarbon volumes in freshwater environ-ments or where the formation-water salinity is unknown. The dielectric tool measurement, however, must be combined with porosity from another source to provide hydrocarbon satura-

tions. The results do not depend on the hydro-carbon type or the pore network.

Dielectric and NMR tools have a shallow depth of investigation, which prevents them from fully supplanting traditional triple-combo logging suites. Whereas resistivity tools measure up to a few meters into the formation, the nature of NMR and dielectric measurements limits them to the first few centimeters from the wellbore wall: the flushed zone, where the virgin fluid has been invaded by mud-filtrate.

However, the shallow nature of the dielectric measurement provides important information about oil mobility. Comparing the saturation derived from dielectric measurements corre-sponding to the flushed zone with that of the virgin zone can help quantify the volume of oil flushed by water-base mud filtrate. This oil is movable and can be produced using primary production means; however, zones with oil that is not flushed generally require other methods, such as steam injection, water or CO2 floods or any of a multitude of enhanced oil recovery tech-niques to flush the oil from the rock. Ultimately, these data are best described as information that, when combined with other logging results, aides the petrophysicist in accurately character-izing the reservoir.

Dielectric tools, however, offer petrophysi-cists more than the ability to quantify water-filled

porosity and compute hydrocarbon volume. Using a newly developed measurement technique that relies on dielectric dispersion, the tools are also able to determine rock properties. This has been shown to be especially useful in carbonates but also provides insight for evaluating shaly sands.

Dispersion Because biological and sedimentological factors can produce a complicated pore network, car-bonates have a much more complex structure than siliciclastic rocks.16 The pore network may also be chemically altered through postdeposi-tional diagenesis.17 This makes evaluation of pet-rophysical properties of carbonates challenging— especially permeability and fluid saturations, which are not directly measured but derived from combinations of measurements using an appro-priate model.

Schlumberger researchers found that dielec-tric properties computed with a frequency of 1 GHz using the CRI technique were accurate for carbonate rock samples saturated with oil-brine mixtures (above). However, factors other than mineralogy and water content affect permittivity at lower frequencies.18 Permittivity dispersion measurements on two carbonate rocks with simi-lar porosity, mineralogy and water saturation high-lighted this frequency-dependent textural differ-ence. The observation of frequency dependence

13. Virtual Institute of Applied Science Encyclopedia: “Dielectric Constant,” http://www.vias.org/encyclopedia/phys_dielectric_const.htm (accessed February 11, 2011).

14. Poley JPh, Nooteboom JJ and de Waal PJ: “Use of V.H.F. Dielectric Measurements for Borehole Formation Analysis,” The Log Analyst 19, no. 3 (May–June, 1978): 8–30.

15. Akkurt R, Bachman HN, Minh CC, Flaum C, LaVigne J, Leveridge R, Carmona R, Crary S, Decoster E, Heaton N, Hurlimann MD, Looyestijn WJ, Mardon D and White J: “Nuclear Magnetic Resonance Comes Out of Its Shell,” Oilfield Review 20, no. 4 (Winter 2008/2009): 4–23.

16. For more on carbonate reservoir analysis: Al-Marzouqi MI, Budebes S, Sultan E, Bush I, Griffiths R, Gzara KBM, Ramamoorthy R, Husser A, Jeha Z, Roth J, Montaron B, Narhari SR, Singh SK and Poirer-Coutansais X: “Resolving Carbonate Complexity,” Oilfield Review 22, no. 2 (Summer 2010): 40–55.

17. Ali SA, Clark WJ, Moore WR and Dribus JR: “Diagenesis and Reservoir Quality,” Oilfield Review 22, no. 2 (Summer 2010): 14–27.

18. For more on the derivation of models used for textural inversion: Stroud D, Milton GW and De BR: “Analytical Model for the Dielectric Response of Brine-Saturated Rocks,” Petrophysical Review B 34, no. 8 (October 15, 1986): 5145–5153.

Baker PL, Kenyon WE and Kester JM: “EPT Interpretation Using a Textural Model,” Transactions of the SPWLA 26th Annual Logging Symposium, Dallas (June 17–20, 1985), paper DD.

Kenyon, reference 11.

> Dispersion in carbonates. Scientists found that, because of differences in rock texture, otherwise similar carbonates can have very different dielectric responses, especially at lower frequencies. Laboratory-measured values of permittivity of two different carbonate samples with similar porosity, permeability and saturating fluids are shown along with permittivity computed using the CRI method (black). The permittivity of Carbonate 2 (red) is similar to the results from the CRI method, but the permittivity of Carbonate 1 (green) is different. Neither sample provided an exact match—except around 1 GHz, which corresponds to the EPT tool’s operating frequency (red dashed line). Because other factors were equal, this frequency-related dispersion is associated with the different textures of the carbonate samples.

Frequency, MHz

EPT tooloperatingfrequencyPe

rmitt

ivity

102 103

50

40

30

20

10

15

45

35

25

Carbonate 1Carbonate 2CRI method

42 Oilfield Review

for dielectric properties led the scientists to develop a dielectric dispersion model to character-ize rock texture.

Researchers also experimented with permit-tivity and dielectric conductivity of siliciclastic core samples saturated with brines of different salinity.19 Although the permittivity of a dry sam-ple is constant over a wide range of frequencies, the permittivity values of the brine-soaked samples change with salinity, converging at fre-quencies around 1 GHz (above). The dielectric conductivities, however, are not linear, and the effect of the brine on the value of the conductiv-ity increases with the frequency of the applied electromagnetic field. Therefore, any variation in the dielectric permittivity with applied frequency must be related to either textural properties or fluid salinity.

Over the years, various models have been developed to quantify dispersion. The textural model utilizes geometric elements—platy grains—to account for differences in textural parameters. To validate the models, scientists acquired experimental dielectric permittivity and conductivity data using a wide range of fre-quencies for rocks with several distinct textures. They then used the dispersion model to fit their measurements. This inversion technique gener-ated results for dielectric permittivity and con-ductivity that more closely matched core measurements than with the traditional CRI technique (left).

> Effects of fluid salinity on dielectric measurements. Cores were saturated with four different brines ranging in resistivity from 4.890 to 0.051 ohm.m. Permittivity (left) and conductivity (right) were computed for a frequency range of 10 MHz to 10 GHz. The permittivity measurements converged around 1 GHz. For comparison, a baseline permittivity measurement was made on a dried core sample (blue). The core saturated with the highest salinity brine (green) displayed the highest dispersion and was the only one that did not converge at 1 GHz. Dielectric conductivity on the other hand, did not converge but increased with frequency for all four samples, demonstrating the dispersive effects of fluid salinity.

Frequency, MHz

Cond

uctiv

ity, S

/m

101 10210-2

10-1

100

103

Frequency, MHz

Per

mitt

ivity

101 102

10

20

30

40

50

60

1103

0.051 ohm.m0.211 ohm.m1.010 ohm.m4.890 ohm.mDried

= 15.6% φ φ = 15.6%

>Model comparison. Permittivity and conductivity (blue) from laboratory core measurements for a carbonate sample were compared to values computed using the CRI method (bottom, black) and the new dispersion textural model (top, red). The CRI method matches core-derived properties at 1 GHz; however, there is little agreement between the carbonate samples and the CRI method at lower frequencies, especially for conductivity. The textural model almost perfectly matches the core data. The example shown is one of several carbonate cores tested; all tested cores showed similar results. (Adapted from Seleznev et al, reference 19.)

Perm

ittiv

ity

Frequency, Hz

10106 107 108 109

20

30

Cond

uctiv

ity, S

/m

40

50

Frequency, Hz

0106 107 108 109

0.10

0.45

0.20

0.30

0.40

0.50

Perm

ittiv

ity

Frequency, Hz

10106 107 108 109

20

30

Cond

uctiv

ity, S

/m

40

50

Frequency, Hz

0106 107 108 109

0.10

0.45

0.20

0.30

0.40

0.50

0 40.455

0.40

Laboratory measurementTextural model

0 40.455

0.40

Laboratory measurementCRI method

Spring 2011 43

The textural method can be used to derive the cementation exponent, m, used in Archie’s water saturation equation. Cementation data computed using the textural model compared favorably with cementation exponents independently mea-sured from carbonate cores. Laboratory data were successfully modeled across a wide range of m-values from 1.7 to 2.9 (right). This technique has been used to explain carbonate texture–related resistivity variations that result in mis-leading saturation estimates (below right).

Dispersion effects are not limited to carbon-ate analysis; they can also be applied to shaly-sand evaluation. However, the dispersion models for shales are different from the one used for car-bonate analysis because the clays, which make up the shale, induce specific dispersion behaviors.

Shaly SandsQuantifying shaliness has been limited to corre-lations with gamma ray, sonic, neutron capture spectroscopy or differences in neutron and den-sity porosity logs. The results are not a direct measurement but are based on empirical infer-ences. The dielectric dispersion model directly quantifies shale effects such as those seen in laminated sand-shale sequences.20 This is espe-cially useful in freshwater shaly sands where the measured resistivity is determined in large part by the clay content. But applications of dielectric data for shaliness are not limited to just fresh-water. Because the dispersive response of a clay’s

> Cementation exponent for Archie’s water saturation equation. The cementation exponent, m, can be measured from core data, but it is a time-consuming process. The textural model, developed from dielectric dispersion analysis, was used to solve for m in a number of carbonate core samples. The crossplot of the values from both methods demonstrates close agreement over a wide range. The default value of 2 for Archie’s equation would not be appropriate for most of these samples for which the value ranges from 1.7 to 2.9. (Adapted from Seleznev et al, reference 19.)

Com

pute

d m

from

text

ural

mod

el

Laboratory measured m from cores

4.0

4.0

3.0

3.0

2.0

2.01.0

1.0

3.5

3.5

2.5

2.5

1.5

1.5

> Validating the dispersion model. Because of textural effects, computing Archie’s water saturation in carbonates using traditional techniques can yield incorrect results. In this example, the deep induction resistivity data (Track 5, red) are higher from X,764 to X,778 m (blue-shaded zone) than above or below. Water saturation computed using Archie’s equation (Track 3, red) with a fixed cementation exponent, m = 2, indicates the possible presence of oil (green shading) in this interval. The porosity from the dielectric tool (Track 6, blue) overlays the total porosity (black), which implies that there are no hydrocarbons. The dispersion-derived value for m (Track 2, blue) varies from 1.9 to 2.6 across this interval. Water saturation computed using this corrected m-value in Archie’s equation results in 100% water saturation (Track 3, black), which is more in line with expectations.

Salinity

Lith

olog

y

Depth,m

CaliperSaturation,

m = 2

Saturation,Corrected m

Gamma Ray

Dielectric Deep

Resistivity

Dielectric Shallow

Deep Induction Total Porosity

Dielectric Porosity

0 6

0

1.0 3.5

gAPI 100

0 100%

0 100%

16 1 ohm.m 1,000 50 % 0

50 % 01 ohm.m 1,000

1 ohm.m 1,000

in.50ppk

mOil

X,750

X,760

X,770

X,780

X,790

X,800

X,810

X,820

XX,770

19. Seleznev N, Habashy T, Boyd A and Hizem M: “Formation Properties Derived from a Multi-Frequency Dielectric Measurement,” Transactions of the SPWLA 47th Annual Logging Symposium, Veracruz, Mexico (June 4–7, 2006), paper VVV.

20. Laminated sands are characterized by intervals of stacked, thin sand and shale layers. The presence of the shale laminae results in lower bulk resistivity measurements and can mask the presence of hydrocarbons. Laminae thickness is generally below the resolution threshold of conventional logging tools.

44 Oilfield Review

dielectric properties directly relates to the phys-ics controlling its conductivity, the dispersion technique yields accurate clay estimation (left).21

As demonstrated with carbonates, the rela-tive permittivity computed from the CRI model may not match core-derived data at frequencies lower than 1 GHz. This dispersive behavior is also seen in shaly sands and sand-shale sequences but for different reasons. For these rocks, it corre-lates with the cation-exchange capacity (CEC) of the minerals in the formation, which relates to both the electrochemical polarization, also referred to as a double-layer effect, and to Maxwell-Wagner interfacial polarization. Both effects are present, and electrochemical effects dominate at lower salinity while interfacial polar-ization dominates at high salinities.

The CEC is the quantity of cations (positively charged ions) that a clay mineral can accommo-date on its negatively charged surface. Clays are aluminosilicates that have had some of their aluminum and silicon ions replaced by elements with a different valence, or charge. The presence of ions from clays enhances electrochemical interfacial polarization.22

Nonconductive elements found in the forma-tion, when mixed together, may exhibit dielectric conductivity that would not be present when these elements are in isolation. This is due to the geometric Maxwell-Wagner phenomenon, which is related to charge accumulation at the interface between brine and rock or brine and oil. Between these charged surfaces, the brine forms macro-scopic dipoles, which give rise to frequency-dependent macroscopic polarizations. When exposed to a low-frequency electromagnetic field, the dipoles reach equilibrium before the field changes direction. When exposed to a high-frequency field, the dipoles cannot follow the rapidly changing field, resulting in energy dissi-pation, increased electrical conductivity and reduced dielectric permittivity.23

In the Dielectric Scanner tool’s frequency range (20 MHz to 1 GHz), both electrochemical and geometric (Maxwell-Wagner) polarization mechanisms contribute to the overall dielectric dispersion measured in clay-containing forma-tions. The electrochemical response decreases

21. Myers MT: “A Saturation Interpretation Model for the Dielectric Constant of Shaly Sands,” paper 9118, presented at the Fifth Annual Society of Core Analysts Conference, San Antonio, Texas, USA, August 20–21, 1991.

22. Seleznev et al, reference 19.23. Toumelin E and Torres-Verdín C: “Pore-Scale Simulation

of KHz-GHz Electromagnetic Dispersion of Rocks: Effects of Rock Morphology, Pore Connectivity, and Electrical Double Layers,” Transactions of the SPWLA 50th Annual Logging Symposium, The Woodlands, Texas, USA (June 21–24, 2009), paper RRR.

> Interfacial polarization. Mixtures of sand and clay exhibit dispersive dielectric permittivity behavior depending on the clay type. The real permittivity measured in a smectite-water mix has a large frequency dependence—compare the real permittivity at 10 MHz with that at 1 GHz. For a kaolinite-water mixture, the effects are present, though less pronounced. There is little dispersion in the sand-water mixture. Because of the larger volume of bound water associated with smectite than with kaolinite, there is an associated decrease in permittivity with increased frequency. This correlation between dispersion and shale content and type can be used to compute the cation-exchange capacity (CEC) and quantify shale effects from dielectric data.

Frequency, MHz

Real

per

mitt

ivity

, εr

0

100

102 103101

200

300

400Smectite-water mixtureKaolinite-water mixture

Ottawa sand–water mixture

100

rΔε

> High-resolution hydrocarbon saturation. Differences in horizontal and vertical resistivities (Track 4) from a triaxial induction device, such as the Rt Scanner tool, can help interpreters identify anisotropy. However the laminations in the FMI fullbore formation microimager data (Track 1) are finer than the resolution of the induction tool or the density-neutron tools, as shown in the crossplot porosity (Track 5, black). This can result in an excessively high net-pay calculation. The vertical resolution of the saturation measurement from the Dielectric Scanner tool (Track 2, black) can be as small as 2.5 cm. The resolution difference is highlighted by comparing the Archie water saturation (Track 2, red) with the dielectric saturation (black). Incorporating dielectric data into the analysis results in a more accurate sand count and reserves estimate.

Lith

olog

y

Depth,ft

FMI ImageSw

Dielectric Vertical Resistivity

Horizontal Resistivity Dielectric Porosity

Crossplot Porosity

SwArchie

0 1 1,000ohm.m 50 0%

1 1,000ohm.m 50 0%

% 100

0 % 100

Oil

1,350

1,360

Hydrocarbon

Spring 2011 45

with increasing brine salinity. Maxwell-Wagner effects increase with increasing brine salinity. For a given brine salinity, an increase in the rock’s clay content causes an increase in its CEC value and an increase in its dielectric dispersion due to both the electrochemical and Maxwell-Wagner mechanisms simultaneously.

The relative importance of each mechanism is influenced by the brine salinity. For example, measurements of a vacuum-dried sample show no frequency dependence, but in sedimentary rocks, dielectric permittivity will increase with increased surface area and CEC. By relating dispersion from shale effects to the CEC, petrophysicists can quantify the shale content of reservoir rocks.

Attempts to determine clay volume as well as clay type are motivated by the need for a CEC input to water saturation equations. CEC deter-mines the effect of the clay on resistivity mea-surement as well as the bound water volume that needs to be excluded from the total porosity mea-surement so that water saturation and oil volume can be properly determined. Measuring CEC

directly rather than estimating it from clay type and volume is a simpler and more robust means of determining water saturation in shaly sands.

An added benefit of the dielectric measure-ment is the ability to directly measure shale con-tent and saturation at high resolution. Although techniques have been developed for measuring anisotropy with resistivity devices such as the Rt Scanner triaxial induction tool, this measure-ment does not have the vertical resolution of the dielectric tool. Nuclear porosity devices can pro-vide inputs for high-resolution saturation mea-surements, but the vertical resolution of these data is limited by physics and detector spacing. The dielectric measurement provides water-filled porosity at resolutions in the 2.5-cm [1-in.] range. The dielectric information allows petrophysicists to more accurately calculate reserves and esti-mate production than they currently can with resistivity and porosity from other sources, including new technology such as triaxial induc-tion tools (previous page, bottom).

The ability to measure shaliness and shale effects is crucial in characterizing anisotropic freshwater shaly-sand reservoirs. Interpreters identify the presence of hydrocarbons in anisotro-pic reservoirs by observing the difference between horizontal and vertical resistivities, such as those from the Rt Scanner tool. However, use of this technique is not effective in freshwater environ-ments because of the lack of contrast between the resistivity of freshwater, shale laminations and oil. Log analysts can, however, determine high-resolu-tion anisotropy using the transverse and longitudi-nal measurements from the Dielectric Scanner tool. From these data, shale effects and oil satura-tion can be quantified.

The Dielectric Scanner ToolMeasurements from electromagnetic devices that operate at frequencies in the kHz range, such as an induction tool, are better known than dielectric measurements acquired at very high frequencies. Lower-frequency measurements are dominated by the conductivity of the formation, but as the frequency increases, dielectric effects begin to appear and then predominate. Very high-frequency measurements offer the ability to eval-uate conductivity and permittivity simultaneously. In addition, obtaining information about texture and shaliness using dielectric dispersion requires a high-quality measurement acquired at multiple frequencies. The Dielectric Scanner tool was developed to provide a full dataset necessary for these applications (left).

> The Dielectric Scanner tool. This recently introduced tool incorporates several features to improve data acquisition and provide greater measurement accuracy. Unlike previous generation tools that used fixed pads, the Dielectric Scanner tool uses the caliper arm to push the articulated pad against the formation. The pad’s curvature also helps improve contact with the borehole wall. The transmitters (TA and TB) and antenna sets (RXA1 to RXA4 and RXB1 to RXB4) operate at discrete frequencies from 20 MHz to 1 GHz. Transmitters and antennas are collocated cross-dipoles and can operate simultaneously in transverse (red arrow) and in longitudinal (blue arrow) polarization modes. Two open electric dipoles (open-ended coaxial-cable probes) measure mudcake properties and provide quality control. For more-accurate fluid property input, the tool measures both temperature and pressure at the point of measurement. Borehole compensation is used to eliminate unbalanced transmitter-receiver pairs. For each measurement cycle, 72 attenuation and 72 phase measurements are made for each of the four frequencies. Depth of investigation is 2.5 cm to 10.2 cm [1 in. to 4 in.] depending on transmitter-to-receiver spacing and formation fluid properties.

Caliperarm

Articulated pad

RXA4 R

XA3 RXA2 R

XA1

RXB1 R

XB2 RXB3 R

XB4

TA

TB

Mudcake probe

46 Oilfield Review

The tool has a fully articulated pad to position the transmitters and receivers against the bore-hole wall. The pad shape is cylindrical and the antennas are designed to be perfect magnetic dipoles. Each of the two transmitters and eight receivers can operate with longitudinal or trans-verse polarization.24 The measurement is per-formed at four discrete frequencies from 20 MHz to approximately 1 GHz. Each measurement cycle includes 72 transmitter-receiver amplitudes and 72 phase measurements. Multiple transmitter-receiver pairs allow for borehole compensation, and a quality-control algorithm can extract unbalanced pairs and eliminate them from the computation. Depth of investigation (DOI)— a function of the transmitter-receiver spacing, operating frequency and formation properties—varies from 2.5 cm to 10.2 cm [1 in. to 4 in.]. A 2.5-cm vertical resolution is achieved.

Electric dipoles on the pad face provide two modes of operation. In propagation mode, they make the shallowest transverse measurement and are used to estimate mud properties. In reflection mode, they measure the dielectric properties of the material directly in front of the pad: mud or mudcake.

Because the tool acquires data in both longitudinal and transverse polarizations, high-resolution anisotropy effects can be quantified. Longitudinal polarization probes the permittivity and conductivity in a plane that is orthogonal to the tool axis (above left). Transverse polarization probes both horizontal and vertical permittivity and conductivity.

Temperature and pressure measurements are also needed for compensation in the dielectric models. Under downhole conditions, pressure has an appreciable effect on the dielectric prop-erties of water.25 The temperature, salinity and pressure dependencies should all be included in a dielectric model to produce accurate interpre-tation of the logs at downhole conditions. Temperature is measured with the integrated mud sensor and a dedicated sensor is used to measure hydrostatic pressure.

The tool investigates three main areas: radial information, geologic structure information and matrix texture (left). The data from the various transmitter-receiver pairs at all frequencies are inverted to output permittivities and conductivities for several layers: the mudcake, the near flushed zone and the far flushed zone. Petrophysical proper-ties can be computed using the CRI model for each of the four frequencies. Dispersion processing with

> Tool operational modes. Dielectric tools generate electromagnetic waves and create a field whose electric components (E) and magnetic components (H) are perpendicular to one another. The polarization of the wave determines the direction of the created fields. Longitudinal (left) and transverse (right) polarization modes correspond to measurements in horizontal and vertical planes with respect to the tool. Each mode generates a specific field orientation and shaped sensed region (insets). The colored bands represent multiple depths of investigation, which are functions of the transmitter-receiver spacing and formation properties. The sensed regions of the two modes overlap (bottom middle); differences in the measurements from the two orientations help identify anisotropy.

Longitudinal Transverse

H

HE

E

Longitudinalsensed region

Transversesensed region

Combinedsensed region

> Dimensions of dielectric measurements. With its four operating frequencies (F0 to F3) and four pairs of transmitter-receiver spacings (R1 to R4), the Dielectric Scanner tool has three investigation ranges: textural, radial and structural. The operating frequencies were chosen to exploit interfacial, molecular and electronic polarization mechanisms, which are related to textural and shale effects. The radial investigation is facilitated by four pairs of transmitter-receiver spacings that model the near-wellbore region, which includes mudcake and invaded zones, and, depending on the depth of invasion, may extend into the transition and virgin zones. Structural investigation is made possible by polarization orientation. Measuring in the horizontal and vertical planes allows identification of formation anisotropy at high resolution.

Interfacial polarization

F0

R1

R2

R3

R4

105 106 107 108 109 1010

F1 F2 F3

Virg

in zo

ne Tran

sitio

n zo

ne

Inva

ded

zone

Mud

cake Molecular orientation

Electronic polarization

Radia

l inve

stiga

tion:

multipl

e spa

cings

Stru

ctur

al in

vest

igat

ion:

mul

tiple

pol

ariza

tions Textural investigation: multiple frequencies

Frequency, Hz

Formation homogeneity

Anisotropy

Spring 2011 47

inputs from multiple frequencies can be performed at different DOIs (above).

To facilitate integration of dielectric data with other logging tool data, engineers have developed the Dielectric Pro dielectric disper-sion interpretation software. Full data process-ing and interpretation are available using porosity, resistivity and saturation analysis from conventional tools. Conductivity and permittiv-ity at multiple frequencies can be computed. Crossplots of the data provide insight into dis-persion for both textural analysis and shaliness. Various interpretation models are incorporated into the workflows and provide alternative methods of analyzing the data. Radial process-ing can derive variations in formation conduc-tivity and permittivity for anisotropy analysis. But, the real test of dielectric logging comes from downhole applications.

Research to ReservoirPetroleum Development Oman (PDO) tested the Dielectric Scanner tool in several wells. PDO objectives included evaluating laminated sand-shale sequences, heavy-oil carbonates, shaly sands and ultrahigh-salinity carbonates.26 For one of the test wells, the objectives were to quantify the volume of residual oil—oil that has not been flushed by invading mud filtrate—independent of resistivity measurements and to integrate dielec-tric data with a full suite of openhole logging tools. PDO evaluated the tool’s ability to detect oil mobility and provide textural information in this test. The selected well was in a carbonate reser-voir. The mud filtrate salinity was approximately 180,000 parts per million (ppm) NaCl.

Because the dielectric tool measures the water-filled portion of the porosity, the difference between density-neutron crossplot porosity and dielectric porosity is the residual oil saturation. In this case, the difference was large, clearly

24. Longitudinal and transverse acquisition compare to endfire and broadside modes from the older generation EPT tools, which are modes that required completely separate sets of hardware.

25. Heger K, Uematsu M and Franck EU: “The Static Dielectric Constant of Water at High Pressures and Temperatures to 500 MPa and 550°C,” Berichte der Bunsengesellschaft für physikalische Chemie 84, no. 8 (August 1980): 758–762.

26. Mude J, Arora S, McDonald T and Edwards J: ”Wireline Dielectric Measurements Make a Comeback: Applications in Oman for a New Generation Dielectric Log Measurement,” Transactions of the SPWLA 51st Annual Logging Symposium, Perth, Western Australia, Australia (June 19–23, 2010), paper GG.

> The CRI method versus the dispersion textural model. The Dielectric Scanner tool has four operating frequencies and multiple transmitter-receiver spacings. For the CRI method (left), the inputs consist of total porosity, φT, matrix permittivity, εmatrix, temperature and pressure. The inversion takes the real permittivity measurement and the dielectric conductivity and outputs water saturation, water conductivity and dielectric constant for any combination of frequency and transmitter-receiver spacing. Shown is the shallow (SH) measurement. For reference and quality

control, the measurement uncertainty of the inputs can be computed and applied to the outputs as well. Inputs for the dispersion model (right) are similar but permittivity and conductivity at multiple frequencies are required for processing. Outputs include water saturation, conductivity, dielectric constant and textural parameters. The data can be inverted for different depths of investigation, which are functions of transmitter-receiver spacing and formation properties. (Adapted from Seleznev et al, reference 19.)

Mud

acak

e

Deep invaded zoneShallow invaded zone

Mud

acak

e

Deep invaded zoneShallow invaded zone

Water modelDielectric model

Dielectric

Input uncertainty

r, SH, F3water, SH

Parameter uncertaintyDielectric constantSH

SW, SH

Inversion

CRI Method Dispersion Model

Water modelDispersion model

Input uncertainty

Dielectric, SH, F0r, SH, F0,

Dielectric, SH, F1r, SH, F1, Dielectric, SH, F2r, SH, F2,

Dielectric, SH, F3r, SH, F3,

water, SH

SW, SH

SH, F3

SH, F3

water, SH

Parameter uncertainty

Dielectric constantSH

SW, SH

Textural parametersInversion

SH, F0

SH, F1

SH, F2

SH, F3

SH, F0,

SH, F1,

SH, F2,

SH, F3,

Deep, F0

Deep, F1

Deep, F2

Deep, F3

Deep, F0,

Deep, F1,

Deep, F2,

Deep, F3,

ε

matrix, temperature and pressureT,ε matrix, temperature and pressureT,ε

εεεε

εεεεε

εεεε

σ

σ

σ

σ

σσ

σσσσ

σσσσ

σσσ

φ φ

48 Oilfield Review

indicating the presence of considerable unmoved hydrocarbon (left). This quantification of resid-ual oil, independent of the resistivity measure-ment, met PDO’s first objective of the test.

To achieve the second objective, analysts com-puted the dielectric textural output for use in Archie’s water saturation equation. The dispersion analysis indicated that the cementation exponent, m, varied from 1.5 to 2.5 across the interval in question. PDO attributed the variability of m to textural and facies differences in the carbonate. The use of a more accurate m-parameter resulted in more precise hydrocarbon saturation determi-nation. General practice is to use a constant value for m, which, based on these findings, would yield inaccurate results.

Next, the dielectric data were integrated in an analysis and compared to water saturation com-puted from inputs that are typical for the field. In the upper section, where a high Archie saturation parameter, or n-value, is commonly used, there is good agreement between the two methods. This fixed value for n was obtained from a nearby field and is appropriate for oil-wet rocks (next page). Across a transition from an oil to a water zone, there is a difference between the output using this constant n-value and from that derived from dielectric measurements. This is most likely because the rock is less oil-wet in this zone than the oil-bearing zone. Rather than using the high n-value used in the upper section to compute water saturation with Archie’s equation, log ana-lysts learned that they should use a lower value.

Saturation SolutionShallow, heavy-oil reservoirs, which include some of the few areas where dielectric tools are in use today, can be found in a number of regions around the globe. Canada, the USA, Mexico, Indonesia and Venezuela are among a number of places with vast heavy-oil reserves.27 In California, USA, heavy-oil production has been underway since the 1890s. Most of this heavy oil is found at depths of less than 3,000 ft [1,000 m].

These shallow heavy-oil reservoirs are beset with interpretation difficulties associated with freshwater. Interpretation is further complicated because many of the reservoirs have been under steam- or waterflood for more than 50 years.28 The fluids encountered by newly drilled wells in these reservoirs may little resemble those originally in place, or may change drastically across seemingly homogeneous reservoir sections because of dif-ferences in operational histories.

>Middle East carbonate test. Log analysts incorporated Dielectric Scanner data with those from a LithoDensity–Array Porosity–HRLA logging suite. The porosity analysis (Track 5) includes total porosity (black) and dielectric porosity (blue). The difference between the porosities (green shading) represents residual hydrocarbons. The dielectric conductivity, converted to resistivity (Track 4, blue), was presented alongside the HRLA resistivities (red and black) and the shallow resistivity from the LithoDensity tool (green). Water saturation was computed from the dielectric data (Track 2, black) and Archie’s equation (red), which was corrected for variations in the m-exponent (Track 1, blue) derived from the dielectric data. Dispersion effects can be visualized by comparing the permittivity and conductivity differences computed from pairs of frequencies (Track 6). The difference between frequency responses is color coded (cyan, blue and red).

X10

X20

X30

X40

Lithology

Resistivity

Porosity

DispersionEffects

Array Laterolog

Perm

ittiv

ity

Cond

uctiv

ity

Total Porosity

Invaded Zone

Dielectric ScannerInvaded Zone

Dielectric ScannerWater-Filled PorosityHRLA TruePorosity

Residual OilSaturation

DielectricScanner

Saturation

ArchieSaturation

Archie Inputs, m = nDepth,

m

Caliper

in.6 16

0.2 2,000ohm.m

0.2 2,000ohm.m

0.2 2,000ohm.m

0.2 2,000ohm.m

0100 %

0 0100 100% % 050 %

050 %

0 3.5

Difference

Oil

Bound Water

Oil

WaterDolomite

Calcite

Illite

HydrocarbonF3–F2

F2–F1

F2–F3

F0–F1

F0–F1

F1–F2

Spring 2011 49

Beginning in the mid-1980s, petrophysical analysis of shallow, heavy-oil reservoirs in California often included the EPT tool to esti-mate hydrocarbons in place, and the use of the tool became routine in the 1990s. The tool mea-sured flushed-zone water-filled porosity. An added benefit of using dielectric tools in these

reservoirs, where there is little invasion from drilling mud filtrate and where the oil is virtually immobile, is that the information reflects that of the virgin zone. Whereas the EPT tool was ini-tially developed to analyze reservoirs where the formation water was known to be fresh, today dielectric tools are also used where formation

water salinity is unknown because of the altera-tions caused by injection of fluids for enhanced oil recovery.

Obtaining quality data from wells in California heavy-oil reservoirs has been problematic. In many reservoirs, the sand grains are held together by the viscous oil originally in place. Depleted zones often exhibit rugose wellbores because they become unstable after some of the oil is removed. The mandrel design of the EPT pad often resulted in measurements that were compromised by borehole rugosity. The articu-lated pad of the Dielectric Scanner tool was designed to improve contact with the borehole wall when the hole is in less than ideal condition.

Interpretation of EPT measurements is also influenced by changes in downhole conditions created by steamflooding. The temperature profile of steamflooded wells does not follow a typical linear gradient, which is assumed for interpretation of dielectric measurements. Because the EPT tool lacks an external tempera-ture sensor, it cannot correct the raw data for temperature, thus introducing errors in the mea-surement. To overcome this limitation and pro-vide additional environmental corrections, the Dielectric Scanner tool incorporates pressure, temperature and mudcake sensors in its articu-lated pad.

Chevron U.S.A. Inc. tested the Dielectric Scanner tool in its heavy-oil steamflood opera-tion in the Cymric field, located in the south-west margin of the San Joaquin Valley, California. One of the main producing intervals is the Tulare Formation, which is Pliocene to Pleistocene in age and mostly poorly consoli-dated fluvio-deltaic sandstone deposits bounded by shales. Producing sands are at depths from 50 ft to 1,600 ft [15 m to 490 m]. Average poros-ity is 34%, permeability is 2,000 to 3,000 mD and oil saturation averages 55% to 65%. The oil is 9 to 14 API gravity. Production commenced in the early 1900s and steamflooding was first introduced in the 1970s. Water saturation calcu-lations from resistivity data are challenging at Cymric because of alterations in the original formation water salinity caused by years of steam injection.

Chevron ran a Platform Express triple-combo logging suite along with the Dielectric Scanner tool in the Cymric well. The logging suite included an EPT tool so the company could compare leg-acy measurements with those from the new tool. Sidewall cores were taken throughout the pro-ducing interval.

27. Alboudwarej H, Felix J, Taylor S, Badry R, Bremner C, Brough B, Skeates C, Baker A, Palmer D, Pattison K, Beshry M, Krawchuk P, Brown G, Calvo R, Cañas Triana JA, Hathcock R, Koerner K, Hughes T, Kundu D, López de Cárdenas J and West C: “Highlighting Heavy Oil,” Oilfield Review 18, no. 2 (Summer 2006): 34–53.

> Improved water saturation computation. In this Middle East carbonate, standard inputs were used to compute water saturation (Track 5). A constant n-value, obtained from offset core data, was used in Archie’s water saturation equation. Water saturation was also computed from dielectric data (Track 6). There is good agreement in the upper interval (light-green shaded zone), confirming the n-value. The dielectric water saturation in the lower interval (light-blue shaded zone), which includes a zone that transitions from oil to water, is lower—indicating more oil—than that using the n-value appropriate for the upper interval. Results such as these can affect oil-reserve estimates, which impact equipment requirements and field development.

X25

X75

X50

Depth,m

CaliperArray Neutron

Porosity

Bulk DensityDielectricPorosity

DensityPorosity

Archie WaterSaturationGamma Ray

in.6 0.02 45 -15%2,000ohm.m

0.02 2,000 1.95 01000 40%

0 40%

% 0100 %2.95ohm.m

16

gAPI0 60

Dielectric WaterSaturation

g/cm3

Rxo HRLA Tool

Rt HRLA Tool

28. Little JD, Julander DR, Knauer LC, Aultman JT and Hemingway JL: “Dielectric Dispersion Measurements in California Heavy Oil Reservoirs,” Transactions of the SPWLA 51st Annual Logging Symposium, Perth, Western Australia, Australia (June 19–23, 2010), paper D.

50 Oilfield Review

The well intersected the oil/water contact at a depth of 830 ft [253 m] (above). Below that depth, the dielectric porosity closely matched the crossplot porosity from the LithoDensity pho-toelectric density and neutron porosity tools, which indicated the formation is filled predomi-nantly with water.

The sidewall cores were analyzed for porosity, permeability and fluid saturation. Log-derived water saturations from the shallow-reading dielectric tool matched the saturations from the sidewall cores. Although sidewall samples and dielectric log measurements represent the flushed

zone immediately around the wellbore, fluid satu-rations obtained from both methods are gener-ally equivalent to saturations in the virgin zone for this field.

The Dielectric Scanner tool’s articulated pad helps compensate for hole rugosity and washouts. The EPT tool is a mandrel device, meaning the pad is fixed on the tool body. A comparison was made between the two devices in the Cymric heavy-oil well. The caliper curve indicated rugos-ity and washouts and the articulated pad handled the borehole irregularities better than the man-drel design did.

The Platform Express flushed-zone resistiv-ity measurement appeared to indicate the pres-ence of mudcake. Mudcake builds up as filtrate displaces oil and pushes fluids deeper into the formation, which makes it an indicator of per-meability and oil mobility. But, in heavy-oil res-ervoirs, it is possible to use the multiple depths of investigation from the Dielectric Scanner tool to look for evidence of mobile oil. If all four depths of investigation deliver the same water-filled porosity, evidence of oil mobility is lack-ing. If they differ, then the data suggest oil mobility in the reservoir—a potential comple-tion target.

The porosity measurement from the EPT tool should overlay the Dielectric Scanner porosity, and this was the case in most of the intervals. However, in the two rugose sections, the EPT tool sensed higher water-filled porosity, which equated to 23 saturation units lower than the Dielectric Scanner results. If this difference was not from oil mobility, it could have been attrib-uted to preferential water or steam breakthrough. Data from the Dielectric Scanner tool did not indicate invasion or oil mobility.

Based on the caliper reading, the borehole at the zones in question was enlarged. Unconsoli-dated sands, such as in this well, may slough off and mud solids have a tendency to build up along the borehole wall. Hole instability and rugosity caused the conflicting results, not mudcake from invasion or the presence of formation water.

These zones could have been misinterpreted as containing movable hydrocarbons due to vis-cosity variations in the oil column, having lower oil saturations or experiencing early water break-through. The error in water saturation, which equates to 23% less hydrocarbon in place, might have caused an operator to bypass both potential pay zones. Increased confidence in the dielectric measurements helped Chevron make informed completion decisions.

Moved OilVenezuela’s Orinoco Belt contains the largest deposit of heavy-oil reserves in the world. The operator, PDVSA, found that the region had a complex depositional setting where thick homo-geneous intervals could rapidly transform into thin, discontinuous layers. The complex geology was further complicated by significant differ-ences in sand quality, which made log interpreta-tion more difficult.

Early water production convinced engineers of the need for greater understanding of the res-ervoir. The identification and elimination of zones with high water production potential were

> Overcoming rugosity. The articulated pad of the Dielectric Scanner tool, which follows the contours of the borehole, compensates for hole rugosity and washouts. The EPT tool is a mandrel device, meaning the pad is fixed in place; Chevron wanted to compare data from the two tools in their Cymric heavy-oil well. After logging the well, engineers observed an apparent mudcake (Depth Track, light-blue shaded zone) in the zone from 780 ft to 820 ft from the LithoDensity tool’s microlog sensor (olive gray shading). Mudcake, if present, can indicate permeability and moved oil. The water-filled porosity from the EPT tool (Track 5, red) from 810 ft to 820 ft was higher than it was in other intervals such as from 540 ft to 605 ft. This could indicate filtrate replacing original oil, and the engineers might have assumed primary production was possible in this zone. However, the improved design of the Dielectric Scanner pad overcame hole rugosity effects and the water-filled porosity (Tracks 4 and 5, blue) showed no increase across this interval. The log response from the LithoDensity tool indicating mudcake was attributed to refilling of a slumping formation with circulated cuttings.

% %%

Dielectric ScannerWater Saturation

Dielectric ScannerWater Saturation

Core Water Saturation

Core Porosity

Total Porosity

DensityStandoff Dielectric

Invaded Zone Resistivity

Quartz

Hydrocarbon

ResidualHydrocarbon

ResidualHydrocarbon

ResidualHydrocarbon

ResistivityStandoff

DensityStandoff Irreducible

Water Volume

Carbonate

Depth, ft

600

800

Clay

Water

100100

2.5

0.5 50ohm.m 5,000

0in.

00 0

%50 0

%50 0% 1000

Dielectric ScannerWater-Filled Porosity

Dielectric ScannerWater-Filled Porosity

%50 0

Invaded Zone Resistivity

0.5 ohm.m 5,000

2-ft Array InductionResistivity Deep

0.5 ohm.m 5,000ResistivityStandoff

2.5 0in.

Caliper8.5 18.5in.

%50 0

EPT Porosity

%50 0

Total Porosity

800

Spring 2011 51

crucial for proper development of the region. Formation resistivity is often used to identify water-producing zones, but engineers discovered that this method was not reliable because of sand quality variability, the presence of freshwater and previously flushed layers that contained sig-nificant quantities of immovable residual oil in conjunction with movable water.

This environment is ideal for incorporating dielectric propagation measurements with stan-dard logging suites, but operators were reluctant to use the tools because of frequent adverse bore-hole conditions, complicated mud-filtrate inva-sion effects and complex interpretation issues. PDVSA recognized the design differences of the new Dielectric Scanner tool and actively partici-pated in the field testing of the device.29

Early in the testing process, engineers observed that filtrate invasion from the water-base mud could complicate interpretation of dielectric data. In the heavy-oil reservoirs of the Orinoco Belt, invasion is usually shallow, on the order of a few inches. Engineers modeled the invasion response of the dielectric tool by creating synthetic logs with typical well charac-teristics: 35% porosity sandstone with simulated virgin to fully flushed conditions. Inputs for the simulation included 5 porosity units (pu) of irreducible water-filled porosity in the virgin zone compared to 15 pu of water-filled porosity in the fully-flushed zone.30 Mud-filtrate salinity for the simulation was 5,000 ppm.

The CRI model, used to compute the tool response, was applied to the four frequencies available from the Dielectric Scanner tool along with nine separate transmitter-receiver spacings. The simulation provided 36 apparent dielectric permittivities and 36 apparent conductivity mea-surements and generated a step-profile with increments that were approximately 1 ft long by 0.1 in. deep [30 cm by 0.25 cm].

Analysis of the synthetic logs generated for one of the lower frequencies showed that when there was no invasion, the apparent permittivity and conductivity were the same as those of the virgin zone. As filtrate pushed deeper into the formation, the deepest DOI values approached those of the shallowest reading. For the highest frequency, the situation was extremely complex. Apparent permittivities and conductivities lost linearity and DOI was not uniform (right).

29. Mosse L, Carmona R, Decoster E, Faivre O and Hizem M: “Dielectric Dispersion Logging in Heavy Oil: A Case Study from the Orinoco Belt,” Transactions of the SPWLA 50th Annual Logging Symposium, The Woodlands, Texas (June 21–24, 2009), paper AAA.

30. In this simulation, 5 pu of water represents a water saturation of 14%. After the formation is flushed by 15 pu of filtrate, this represents a water saturation of 43%.

>Modeling dielectric response. PDVSA’s Orinoco Belt has complex lithology and difficult interpretation issues. PDVSA and Schlumberger tested the Dielectric Scanner tool by first modeling the response to invasion in conditions anticipated in Orinoco wells. A total of 36 sets of attenuation–phase shift measurements using nine spacings and four frequencies (F0 to F3) were used in the study. For the analysis, each 1 ft [30 cm] of log interval represented 0.1 in. [0.25 cm] of invasion (inset). For simplicity, synthetic apparent dielectric permittivity and conductivities are shown for frequency F1 (top) and for F3 (bottom). There are two sets of permittivity and conductivity curves: longitudinal polarization (left set) and transverse polarization (right set). The modeled responses are for the longest spacing (red curves) to the shortest spacing (blue curves). For frequency F1 (top left), when the invasion depth is zero, shown at the top of each log, permittivity curves read the deep zone value (dashed black line). As the simulated invasion pushes into the formation and filtrate replaces oil, the permittivity curves from the longitudinal polarization eventually converge to the fully flushed reading, shown at the bottom of the log; however, the transverse data do not converge and only the shortest spacing data approach the flushed zone value. For the highest frequency, F3 (bottom left), the permittivity from both longitudinal and transverse polarizations initially read the deep zone value and, as the simulated invasion pushes deeper, the transverse measurements converge on the flushed zone value while the longitudinal permittivities exhibit an oscillatory response. Regardless of the direction of polarization, conductivity data behave better for F1 frequency (top right). At the outset, longitudinal and transverse data reflect the value of no invasion and converge at the flushed value at the bottom of the log. This is not the case for conductivity data from F3 (bottom right), where oscillatory responses are seen for both polarizations. These results do not lend themselves to quicklook analysis; however, a response model was created from this analysis to correct data from Orinoco wells. (Adapted from Mosse et al, reference 29.)

5

0

10

20

30

Sim

ulat

ed d

epth

, ft

Sim

ulat

ed d

epth

, ft

Permittivity, F1

Longitudinal Polarization

No invasion

Fully invaded

No invasion

Fully invaded

No invasion

Fully invaded

No invasion

Fully invaded

Transverse Polarization

Conductivity, F1

Longitudinal Polarization Transverse Polarization

40

15

25

35

45

5

0

10

20

30

40

15

25

35

45

0.1 in.

1 ft

Permittivity, F3

Longitudinal Polarization Transverse Polarization

Conductivity, F3

Longitudinal Polarization Transverse Polarization

52 Oilfield Review

Lessons learned from the simulation were applied to permittivity and conductivity data acquired in an Orinoco well. These results closely resembled the simulated logs, providing a petro-physical inversion scheme that could be applied to the well data. Based on these results, PDVSA used the Dielectric Scanner tool on other wells.

The results from one well in particular showed the benefit of using the dielectric mea-surement in conjunction with other logging tools. An appraisal well was drilled in an area that was first explored in the 1980s and had relatively poor well control. PDVSA expected to encounter thick reservoir sections with low resistivity. Based on previous experience, such intervals were often interpreted as having heavy residual oil flushed with movable water. Log analysts expected these zones to produce mainly water.

The logging program included a Platform Express suite with an HRLA high-resolution

laterolog array tool and an MR Scanner expert magnetic resonance service. In other wells in the region, geologists had observed high resistivity in the oil-bearing interval, but resistivity values deeper in the interval were not as high. This well encountered similar intervals exhibiting high and low resistivity.

Conventional interpretation of oil mobility relied on comparing deep and shallow resistivity measurements. In this case the results were inconclusive because of similarities in the forma-tion water and filtrate salinities. In the high-resistivity upper interval, the NMR log showed a bimodal distribution with a strong oil signature. With increasing depth, the apparent porosity and the resistivity were reduced, and the NMR data appeared to indicate no movable oil. Log analysts called on the Dielectric Scanner data to validate this interpretation.

Although the caliper log indicated significant borehole rugosity, the pad of the Dielectric Scanner tool maintained good contact with the formation. The dielectric data resolved the uncertainty associated with the deeper reservoir section (left). In contrast to the NMR data indi-cating little oil mobility across two intervals, a total 150 ft [45 m] of low-resistivity pay with significant movable oil was indicated. PDVSA included this new information in their produc-tion plan and reserves calculations. The inter-pretation based on dielectric data was later confirmed from sidewall core samples.

Because water production is such a major con-cern in the Orinoco Belt development program, it was important to identify and avoid water-produc-tive zones. The dielectric measurement not only revealed the zones that contained movable oil, but was helpful in also identifying zones where only water was mobile. Resistivity and spontaneous potential (SP) techniques, commonly used to iden-tify such zones, require some contrast between the resistivities of the filtrate and formation water. In this case, there was no contrast and it would not have been possible to confirm water and oil mobility without integration of the dielectric data.

The analysis was further confirmed by sam-pling the various intervals. From the deepest interval, only water was produced. Oil and water came from the transition zone. From both the low- and high-resistivity intervals, oil was produced. This matched the interpretation from the dielec-tric measurements. PDVSA reservoir engineers were able to determine the best intervals for both production and additional field development.

Final AnalysisDielectric measurements from downhole tools have been available to petrophysicists since the early 1980s. Recognized benefits from the infor-mation were overshadowed by measurement complexity and tool limitations.

The introduction of the Dielectric Scanner tool has combined better tool design with new process-ing techniques. The dielectric information provides clear benefits for carbonate reservoir interpreta-tion, shaly-sand analysis, heavy-oil reservoir evalua-tion and any formation where the water is fresh or the water salinity is unknown.

Sometimes it takes a while for a technology to evolve and find its niche. Just as not every kitchen in the world has or needs a microwave oven, not every oil well interpretation requires dielectric data. But in certain situations, and for the right environments, zapping a formation with micro-waves may offer just that extra bit of information the log analyst needs. —TS

> Applying the model. Armed with the information from the dielectric modeling exercise, PDVSA logged an Orinoco Belt well with Platform Express–HRLA, MR Scanner and Dielectric Scanner tools. Conventional methods of interpretation relied on differences in shallow and deep resistivity measurements to indicate oil mobility. These data (Track 5) are not conclusive, even when dielectric resistivities from different depths of investigation (red and blue curves) are included in the analysis. NMR data (Track 7) show a bimodal distribution, indicative of possible oil mobility, across much of the upper interval but not below X,650 ft. The differences between NMR data at the two blue-shaded zones are significant. The lower interval could be interpreted as containing nonmovable oil. Data from the Dielectric Scanner tool indicated a distinct difference between the deep and shallow porosity measurements (Track 6), corresponding to the moved oil (gold shading). The interpretation suggests a total of 150 ft [46 m] of low-resistivity movable oil. This was later confirmed with production tests after casing was in place. (Adapted from Mosse et al, reference 29.)

Caliper

SP

in.8

–100 0

0.2 2,000ohm.m

0.2 2,000ohm.m

0.2 2,000ohm.m

0.2 2,000ohm.m

0.2 2,000ohm.m

0.2 2,000ohm.m

01 in.

01 in.

01 in.

0 100%

0 100%

50 0 0.5 ms 5,000%

50 0%

50 0%

mV

18

Moved Oil

Water

Lith

olog

y

Residual Oil

ResistivityStandoff

8-in. Invaded Zone Resistivity

Dielectric Scanner Shallow Resistivity

Dielectric Scanner Shallow Water-Filled Porosity

Dielectric Scanner Deep Water-Filled Porosity

Total Porosity T1 Cutoff

T1 DistributionDielectric Scanner Deep Resistivity

HRLA True Resistivity

Array Laterolog Resistivity

Invaded Zone Resistivity

DensityStandoff

DielectricScannerMudcakeThickness

DielectricScanner ShallowWater Saturation

DielectricScanner Deep

Water Saturation

Depth,ft

X,450

X,500

X,550

X,600

X,650

X,700

X,750

X,800

Moved Oil

Residual Oil

Medhat Abdou is Vice President of Development forthe Abu Dhabi Company for Onshore Oil OperationsBab field development in Abu Dhabi, UAE. He has sev-eral publications in the areas of reservoir managementand reservoir simulation. His current interests includeenhanced oil recovery and field development of largeheterogeneous reservoirs. Medhat holds a BS degree inpetroleum engineering from Tripoli University in Libya.

Alexander P. Albert, based in Houston, is theSchlumberger North America Midstream andIndustrial Business Development Manager. Beforeassuming his current post, he was product championof next-generation nuclear measurements for theSchlumberger Wireline segment. He has held a varietyof positions in operations, management and marketingthroughout the US. Alex joined Schlumberger in 1998as a wireline field engineer after receiving a BS degreein mechanical engineering from Bucknell University,Lewisburg, Pennsylvania, USA.

Romulo Carmona is a Consulting Petrophysicist, for-merly with Petróleos de Venezuela, S.A. (PDVSA) from1982 to 2001. Before his retirement from PDVSA, heserved in a number of capacities related to geology,petrophysics and reservoir engineering. He has pub-lished numerous papers on the geology of Venezuela aswell as petrophysical field studies on the heavy-oilreservoirs in the Orinoco Belt. He obtained a BS degreein geological engineering from the Universidad Centralde Venezuela, Caracas, where he was a professor from1992 to 1995. He also taught at the UniversidadNacional Experimental De Los Llanos Ezequiel Zamora,Barinas, Venezuela, from 1978 to 1992. Romulo is associ-ated with the Colegio de Ingenieros de Venezuela, theGeologists Association of Venezuela and the SPWLA.

Andrew Carnegie is a Reservoir Engineering Advisorfor Woodside Petroleum in Perth, Western Australia,Australia. Previously he worked for Schlumberger for20 years and INTERA for four years. He holds BSc andPhD degrees, both in applied mathematics, from theUniversity of London.

Eric Decoster, based in Rio de Janeiro, is PetrophysicsAdvisor for Schlumberger Latin America, where heoversees new technology applications and integration.His career with Schlumberger spans 32 years, begin-ning as a wireline field engineer in the Middle East.Over the last 20 years, he has held various positions inmarketing and interpretation in the Middle East andLatin America. In 1997, he became principal petro-physicist for the government of Venezuela, focusing onthe development of interpretation techniques and newtechnology, including nuclear magnetic resonance andspectroscopy. In Venezuela, he carried out the initialfield test of the Dielectric Scanner* prototype. He haspublished several papers on the tool’s applications forreservoir characterization. Eric received an engineer-ing degree from the École Centrale de Paris, and amaster’s of engineering degree from the University ofWisconsin, Madison, specializing in flow throughporous media. He currently serves as Director of theSPWLA for Latin American.

Dave Elliott began his career with Shell InternationalExploration and Production B.V. as a well test supervisorin 1977. Since then he has held positions as plant, pro-duction and completion engineer, well test team leader,

safety management development coordinator and assetmanager. Most recently he has served Shell InternationalE&P as global underbalanced drilling/managed pressuredrilling (UBD/MPD) implementation manager, with afocus on global tight gas well technology. Dave is cur-rently UBD/MPD Projects and Technology Engineer andmember of the Shell global UBD/MPD team. He holds aBS degree in chemical engineering from SouthernAlberta Institute of Technology, Calgary.

Paul Francis is Business Development Manager,Eastern Hemisphere for @balance, a Schlumbergercompany. Prior to his current post, he held numerouspositions with Shell in the Netherlands and Oman. Healso worked as a hydrometallurgist for Anglo-AmericanResearch Laboratories in Johannesburg, South Africa.An SPE Distinguished Lecturer in managed pressuredrilling for 2011/2012, he earned a BSc degree in min-eral technology engineering and a PhD degree in col-loid and surface science, both from Imperial College,London. Paul is the author of numerous technicalpapers and articles.

Jim Hemingway, based in Houston, is a PetrophysicsAdvisor with Schlumberger. He began his career in 1980 asa field engineer, has held various log analyst and engineer-ing positions and has authored many papers on pulsed neu-tron logging and log interpretation. In 1997, he joined theFormation Evaluation department at the SchlumbergerSugar Land Product Center, Texas, USA, working on theRSTPro* tool and three-phase holdup interpretation tech-niques. In 2001, as new technology advisor, he moved toParis to teach new technology applications for formationevaluation. In 2005, he became nuclear technology advisor.Jim received a BS degree in chemistry from Emporia StateUniversity, Kansas, USA, and a BS degree in chemical engi-neering from Texas A&M University, College Station.

Mehdi Hizem, located at the Schlumberger RiboudProduct Center (SRPC) in Clamart, France, has beenthe Dielectric Scanner Project Manager since 2004.He began at SRPC in 1996, where he was assigned tothe production services platform. He then moved toHouston to work at the Integrated Products Centerwhere he worked on developing wireline downholetractor technology. He returned to SRPC in 2002,where he was in charge of wireless telemetry for down-hole testing and managed the Platform Express* 150project. Mehdi obtained a master’s degree in engineer-ing from École Centrale de Paris.

Dale Julander is a Senior Staff Petrophysicist atChevron U.S.A. Inc. based in Bakersfield, California,USA. He started his career in 1982 as a geophysicist forChevron in California working in the explorationdepartment and in seismic processing before transfer-ring to development geology in 1988. In the late 1980sand 1990s, he worked on several onshore and offshoreprojects focused on exploiting opportunities in theMonterey Shales and various Plio-Miocene sandstonereservoirs in California. He serves as the Supervisor ofthe formation evaluation staff for the San JoaquinValley Business Unit for Chevron U.S.A. Inc. Dale has aBS degree in geology from the University of PugetSound, Tacoma, Washington, USA, and an MS degree ingeophysics from the University of Utah, Salt Lake City,USA. He received the A.I. Levorsen Memorial Award in2004 for coauthoring the best paper at the PacificSection AAPG 79th Annual Meeting.

Paal Kibsgaard is Chief Operating Officer ofSchlumberger Limited. Prior to his most recent posi-tion as president of Reservoir Characterization, heheld a variety of global management positions includ-ing vice president of Engineering, Manufacturing andSustaining; vice president of Personnel for SchlumbergerLimited; and president of Schlumberger Drilling &Measurements. Earlier in his Schlumberger career, hewas a GeoMarket* manager for the Caspian regionafter holding various field positions in technical salesand customer support. A petroleum engineer with amaster’s degree from the Norwegian Institute ofTechnology, Paal began his career in 1992 working forExxonMobil. He joined Schlumberger in 1997.

Daniel L. Lanier is the Vice President of Geosciencesfor Geoscience Earth and Marine Services (GEMS),Inc., a Forum Energy Technologies Company based inHouston. Before his current role, he served as projectmanager and director of operations, specializing inidentifying and characterizing marine geohazards.Daniel, who joined GEMS in 2001, is a graduate ofTexas A&M University, College Station.

Jeffrey Little is Principal Petrophysicist andDepartment Head at Schlumberger Petrophysics Dataand Consulting services in Bakersfield, California. Hehas 29 years of industry experience, starting as a fieldengineer. He has worked in various field assignmentsincluding California land and offshore operations,deep desert operations in Syria and as high pressureand temperature specialist in the North Sea. Jeffreyhas been working in log interpretation and applicationdevelopment since 1995. He earned his BS degree inphysics from Colorado State University, Durango, USA.

S. George Mathews is the Schlumberger Oilphase-DBR*Laboratory Manager in Houston, where his responsibil-ities include business development and managementof the Fluids and Flow Assurance Laboratory. Previousto his current position and while at the Oilphase DBRlaboratory, he developed a method for measuring pH oflive formation water. He began his Schlumbergercareer in 2001 as a senior project engineer specializingin testing operations. Before that, he was an assistantmanager for design and projects at Gharda ChemicalsLimited in Mumbai. George received a bachelor’sdegree in chemical engineering from the NationalInstitute of Technology in Durgapur, West Bengal,India, and an MBA degree from Jamnalal BajajInstitute of Management Studies in Mumbai.

Kevin McCarthy is a Geochemist with SchlumbergerTesting Services in Houston. He joined Schlumbergerin 2008 at the Heavy Oil Regional Technology Center inCalgary. Before that, he held a variety of positions inother fields. He was a research assistant at TuftsUniversity in Medford, Massachusetts, USA, where heanalyzed aqueous and soil samples in support of theUS National Aeronautics and Space AdministrationPhoenix Mars Mission. He was a hydrologist consultingon water-management issues in Sarasota County,Florida, USA. At Woods Hole Oceanographic Institutein Massachusetts, he researched deep sea hydrothermalvents as a scientist diver in the manned submersibleALVIN. Kevin has a master’s degree in geochemistrywith a special focus on hydrogeology from the Universityof South Florida in Tampa, and a bachelor’s degree ingeology from Salem State College in Massachusetts.

Spring 2011 53

Contributors

Tom McDonald is currently SchlumbergerPetrophysics Domain Champion for West Australia,based in Perth, Western Australia. He started hiscareer with Schlumberger in 1981 as a wireline engi-neer in Midland, Texas. After a number of positions inthe western US, in 1990 he began working as a petro-physics log analyst in Oman and has performed similarwork in a number of other locations, including theUAE, Yemen, Vietnam, Papua New Guinea, Indonesiaand Angola. Tom obtained a bachelor’s degree in geo-logical engineering from the University of Idaho,Moscow, USA, and an associate’s degree in geophysicsfrom the Colorado School of Mines, Golden, USA.

Julio Montilva is Staff Drilling Engineer with ShellExploration and Production Company (SEPCo) inHouston. He began his career as an engineer withLagoven, a division of PDVSA, in Venezuela in 1997. In2002, he joined Shell Venezuela where he rose to theposition of head of well engineering before joiningSEPCo in 2007. Julio received a BS degree in chemicalengineering from the Universidad de Los Andes,Mérida, Venezuela, and a master’s degree in industrialprojects management from the Universidad RafaelBelloso Chacín, Maracaibo, Venezuela. He has authorednumerous International Association of DrillingContractors (IADC), SPE and American Association ofDrilling Engineers (AADE) technical papers.

Laurent Mossé is a Physicist with Schlumberger atSRPC in Clamart, France, and leads the interpretationand physics team of the Dielectric Scanner project.He began his career with Schlumberger in 2002, firstworking as a nuclear physicist for gamma-density toolsand developing extended temperature and boreholecorrections and cased-hole formation density algo-rithms. In 2004, he joined the Dielectric Scannerphysics and interpretation team, which he now leads.Laurent obtained a master’s degree in engineeringfrom École Supérieure d'Électricité (Supélec), Gif-sur-Yvette, France, and a PhD degree in physics from theAlternative Energies and Atomic Energy Commission(CEA), France. Before joining Schlumberger, Laurentworked for two years at the European Organization forNuclear Research (CERN), Geneva, Switzerland.

Jonathan Mude is a Petrophysicist with PetroleumDevelopment Oman (PDO), in Muscat, Oman, wherehe works with the maturation team in the ExplorationDirectorate. He began his career in the oil and gasindustry in 1995 as a log analyst in Nigeria withGeoQuest, a Schlumberger company. He moved toTotal Nigeria (formerly ELF) in 1998 and worked as apetrophysicist, focusing primarily on drilling, logging,database management and contract management. Heworked for Shell Nigeria as an operations petrophysi-cist from 2001 to 2008, and then moved to PDO.Jonathan holds a BS degree in petroleum engineeringfrom the University of Benin, Benin City, Nigeria.

Michael O'Keefe is Senior Reservoir DomainChampion for Schlumberger in London. Previously, hewas the product champion for downhole fluid analysis,based in Hobart, Tasmania, Australia. He joinedSchlumberger in 1990 as a wireline field engineer inAustria. Since then, he has had assignments in Norwayand Saudi Arabia as a production logging engineer,senior reservoir engineer and field-test coordinator.

Author of many patents and technical papers, Michaelis a recipient of the 2005 and 2006 Performed bySchlumberger Gold Medals and a member of thefocused probe development team that received the2006 Hart Meritorious Award for Engineering Excellence.He is also a 2010/2011 SPWLA Distinguished Lecturer.Michael earned a BEng degree (Hons) in electronicsengineering from the University of Tasmania, Australia.

Brian L. Perilloux serves as Vice President, Gulf CoastRegion, for Williams Midstream Services, LLC. He haspreviously served as director of Offshore Engineering& Construction for Williams and worked in the engi-neering consulting sector prior to joining Williams. His26 years of experience include managerial and techni-cal project development of many domestic and inter-national offshore and onshore facilities. A registeredProfessional Engineer in Louisiana, USA, Brianobtained a BS degree in mechanical engineering fromthe University of New Orleans.

Bhavani Raghuraman is Center Manager at theSchlumberger Princeton Technology Center, in NewJersey, USA. The Center specializes in the design andmanufacture of nuclear detectors and generators. Beforetaking her current position, she coordinated fluid andcore analysis related to product development projectsfor Testing and was, previous to that, a scientific advi-sor in the novel sensors program at Schlumberger-DollResearch in Cambridge, Massachusetts, USA. Bhavanibegan her Schlumberger career at Schlumberger-DollResearch in Ridgefield, Connecticut, USA. Among herseveral projects there, she developed the downhole pHmeasurement using optical spectroscopy, and thenmanaged the downhole fluid analysis program for sen-sor development on wireline, drilling and productionlogging platforms. She received BS and PhD degrees inchemical engineering from Mumbai UniversityInstitute of Chemical Technology.

Don Reitsma is Vice President of Engineering andTechnology for @balance, a Schlumberger company.Prior positions include European manager of theunderbalanced drilling global implementation teamfor Shell International E&P and senior applicationsengineer for Schlumberger. He has held engineeringposts in Yemen, Canada, China and Malaysia. Don hasserved as chair of the IADC Managed Pressure Drillingand Underbalanced Drilling Operations Committeeand cochaired the SPE Managed Pressure DrillingUnderbalanced Operations Technical Interest Group.He obtained an MSc degree in petroleum engineeringfrom the University of New South Wales, Sydney.

Tarek Rizk is the Wireline Product Champion forDielectric Scanner and Geology projects, located atSRPC, Clamart, France. He is responsible for productdevelopment, field introductions and deployment ofnew wireline projects. He joined Schlumberger in 2000as a wireline field engineer; during his career he heldseveral positions in both the Middle East and Asia.Tarek earned his BS degree in electrical engineeringfrom the University of Alexandria, Egypt.

Vincent Roes, based in Calgary, is Well EngineeringTeam Leader for Talisman Energy in Kurdistan. Priorto his current position, he was well engineer managerfor BG International Limited in Calgary. He hasworked around the world including assignments withShell in the Netherlands, the US, Argentina and Omanand with Esso Resources in Canada. Vincent holds adiploma in exploration technology from the Northern

Alberta Institute of Technology, Edmonton, Alberta,Canada, and a BSc degree in petroleum engineeringfrom the University of Alberta, Edmonton. He is theauthor of numerous IADC and SPE technical papers.

Nikita Seleznev is a Senior Research Scientist atSchlumberger-Doll Research, Cambridge, Massachusetts,USA. He conducts research in dielectric and resistiv-ity logging tools and techniques as well as petrophysicsof conventional and unconventional reservoirs. He hasbeen developing interpretation products that directlymeasure water volume and rock textural informationfor the Dielectric Scanner tool. He also contributed tothe development of the Carbonate Advisor* petro-physics and productivity analysis program. He joinedSchlumberger in 1998 as a wireline field engineer.Nikita received his PhD degree in petrophysics fromthe Delft University of Technology, the Netherlands.

Jaye Shelton began his oil industry career as acementer in 1974 with Halliburton Services beforemoving to district manager for Grant Oil Tool Companyin 1977. He joined Smith Services when that companybought Grant. Jaye is currently an Engineer TechnicalService Advisor III with Smith Services, aSchlumberger company. He earned a BS degree inagricultural sciences and business from Texas TechUniversity in Lubbock and is a member of the SPE, theAPI and the IADC Managed Pressure DrillingUnderbalanced Drilling subcommittee and work groupthat developed the API 16 RCD Specification for DrillThrough Equipment—Rotating Control Devices.

Andrew Strong, based in Southampton, Hampshire,England, is the Global Product Manager, SensingSystems for Teledyne Technologies Inc. Previously hewas domain champion, distributed measurements,with the Schlumberger Subsea segment. He is aChartered Engineer and Fellow of The Institution ofEngineering and Technology and has 25 years of expe-rience in optical fiber technology. He has beeninvolved in both telecom and sensing and has pub-lished a number of papers and patents in these fields.Andrew has a BSc (Hons) in physics with physicalelectronics from the University of Bath, England.

Wei Wei, has been a Geochemist with Chevron for fouryears; she is based in Houston. Wei received a bache-lor’s degree in chemistry from Beijing University,China, and a PhD degree in earth sciences fromScripps Institution of Oceanography, University ofCalifornia, San Diego.

ChengGang Xian, based in Shenzhen, China, is aPrincipal Reservoir Engineer and Reservoir DomainChampion for Schlumberger, providing technical sup-port for all reservoir engineering–related wireline log-ging activities in China. He began his Schlumbergercareer in 2001 at the Beijing Geosciences Center,working on reservoir simulation. He has also held posi-tions as a reservoir engineer in the UAE and Libya.Prior to joining Schlumberger, he worked at thePetroleum Economic and Information Center of theChina National Petroleum Corporation (CNPC) inBeijing. ChengGang obtained a doctorate degree inreservoir engineering from the China University ofPetroleum in Beijing.

54 Oilfield Review

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

Universe from Bit, The Computational Universe, Minds and Values in the Quantum Universe

The Concept of Information in Biology; What is Missing from Theories of Information; Information and Communication in Living Matter; Semiotic Freedom: An Emerging Force; Care on Earth: Generating Informed Concern

The Sciences of Complexity—A New Theological Resource?; God as the Ultimate Informational Principle; Information, Theology and the Universe; God, Matter, and Information: Towards a Stoicizing Logos Christology; What is the ‘Spiritual Body’? On What May Be Regarded as ‘Ultimate’ in the Interrelation Between God, Matter, and Information

. . . [The book] . . . is a collection of non-technical articles compiled by Paul Davies (a physicist) and Niels Henrik Gregersen (a theologian). . . . Each article explores the hypothesis that information is at the root of everything. And I mean everything—from atoms to, perhaps, a deity. . . . The pinnacle of th[e] ‘theological’ section, . . . is the proposal by Keith Ward that deity is a form of information-theoretic principle. . . . When the famous British geneticist J B S Haldane was asked if his research taught him anything about God, he replied “The Creator, if He exists, has an inordinate fondness for beetles.” The collection by Davies and Gregersen suggests, in line with my own views, that we could go deeper than Haldane: the ultimate answer might just turn out to be a Creator with an inordinate fondness for bits. Certainly, bits of information are present everywhere we look, and if you want to know more about this novel take on reality, then I highly recommend Davies and Gregersen’s erudite and entertaining collection.

Spring 2011 55

NEW BOOKS Coming in Oilfield Review

Bit design. At one time, bit selection and design were based on rough estimates, trial and error, basic assumptions and experience. This article looks at the tools available today that allow engineers to optimize bit design through complex, dynamic modeling and digital simulations of the interaction between all drill-ing components.

Geochemistry. As exploration and production companies seek to exploit gas shales and other challenging trends, the need to quantify the elements and processes controlling the generation of hydrocarbons becomes more acute. Geochemistry can help E&P companies improve exploration and production efficiency by characterizing the quality and distribution of petroleum-generating source rocks in sedimentary basins. This article describes basic geo-chemical tools and techniques that geoscientists use to evaluate source-rock quality, quantity and thermal maturity.

Conveyance. In the past, the primary method for getting logging tools downhole and data back to the surface was limited to gravity and various types of cables. Today, cables are still used for these purposes but a wide range of other means of con-veyance and data transmission systems provides engineers and petrophysicists with a variety of options. This article reviews several conveyance systems, including a recently introduced logging platform, tractors for logging and perforating, and data delivery systems that include wireless and memory options.

Environmental effectiveness. The oil and gas industry has made great strides in environmental stewardship. Technological solutions in all phases of the E&P cycle decrease emissions and waste and help protect land and marine animals and plants. This article examines advances in green technologies in the E&P industry.

Geothermal Energy: Renewable Energy and the EnvironmentWilliam E. GlassleyCRC PressTaylor and Francis Group6000 NW Broken Sound Parkway, Suite 300Boca Raton, Florida 33487 USA2010. 290 pages. US$ 119.95

The author, who is the executive director of the California Geothermal Energy Collaborative, discusses the strengths and weaknesses of geother-mal energy as well as techniques for implanting geothermal energy projects. He explores links between geothermal acquisition and consumption and the environment. Using real-world cases, Glassley discusses principles of geo-sciences and exploration concepts and methods as well as drilling operations, techniques and equipment.

This . . . book provides an up-to-date, comprehensive overview of basic knowledge and essential information pertaining to development of geother-mal energy. . . . Numerous charts, graphs, maps, photos, and equations are especially useful to support the text. Concise end-of-chapter summa-ries, reference lists, and sources for further information are also very helpful. . . . Glassley has written a remarkably concise yet in-depth book that is indispensible to advanced students and a wide range of profes-sionals interested in the many aspects of the science, applications, econom-ics, and potential contributions of geothermal energy to the world of the future. Highly recommended.

Choice

Information and the Nature of Reality: From Physics to MetaphysicsPaul Davies and Niels Henrik Gregersen (eds)Cambridge University Press32 Avenue of the AmericasNew York, New York 10013 USA2010. 398 pages. US$ 30.00

This book is a collection of articles from scientists, philosophers and theologians who discuss quantum, biological and digital information in a quest to under-stand nature. Going beyond mass and energy as the primary currency of nature, the authors also examine physical and biological approaches to information, including its philosophical, theological and ethical implications.

From Matter to Materialism . . . and (Almost) Back; Unsolved Dilemmas: The Concept of Matter in the History of Philosophy and in Contemporary Physics

The Climate Fix: What Scientists and Politicians Won’t Tell You About Global WarmingRoger Pielke, Jr.Basic Books387 Park Avenue SouthNew York, New York 10016 USA2010. 276 pages. US$ 26.00ISBN: 978-0-465-02052-2

In this book, the author examines the intersection of politics and the science of climate change. Pielke argues that when environmental and economic objectives are in opposition, economics always wins. As a precondition for both to succeed, climate policy must be made compatible with economic growth because energy growth is inevitable. He focuses on policy adaptation to climate change and calls for a broad-based world climate policy.

Contents:

Pielke . . . provides a road map on the intersection of politics and science by dissecting the debate and provid-ing diagnoses. The author explains in nine engaging chapters certain steps to be taken, such as expanding energy access while increasing energy security through technological inno-vation. Pielke summarizes by saying that removing politicization and fear factors will ultimately lead to a path of decarbonziation that benefits society and the world as whole. Highly recommended.

Choice

Oilfield Review56

Street-Fighting Mathematics: The Art of Educated Guessing and Opportunistic Problem SolvingSanjoy MahajanThe MIT Press55 Hayward StreetCambridge, Massachusetts 02142 USA2010. 152 pages. US$ 25.00

Mahajan suggests that in problem solving, as in street fighting, rules can cause paralysis; he describes and demonstrates tools for educated guessing and problem solving for disciplines from mathematics to management. Originally a short course taught by the author at the Massachusetts Institute of Technology (MIT) in Cambridge, Street-Fighting Mathematics is intended to give readers the mathematical tools to solve life’s partly defined problems.

Contents:

Bottom line: This is a very cre-ative book. It contains an eclectic set of topics . . . [and] is replete with tricks, short cuts, and thought-provok-ing questions. . . . [M]y working definition of an applied mathemati-cian is someone who is comfortable working on the interface between mathematical rigor and physical intuition, moving back and forth as required, frequently corrugating that interface with nonlinear distur-bance[.] This book is a fine example of such a philosophy and would be an excellent supplement in standard (and still necessary) ‘mathematical meth-ods of physics’ and ‘methods of applied mathematics’ courses.

American Journal of Physics

The Evolutionary World: How Adaptation Explains Everything from Seashells to CivilizationGeerat J. VermeijThomas Dunne Books, an imprint of St. Martin’s Press175 Fifth AvenueNew York, New York 10010 USA2010. 336 pages. US$ 27.99

In this exploration of evolutionary theory, Vermeij presents the way a changing world has shaped our species and our cultures. His discussion of natural selection and human behavior looks at evolution as a concept that explains and connects a multitude of seemingly unconnected facts and phenomena. The author writes that having an understanding of how evolu-tionary theory has had a bearing on worldwide economic systems, disaster preparedness and community develop-ment will help us learn how such systems work and what challenges lie ahead.

Contents:

A transcendent view of evolution as adaptation, not only accounting for the origin of species but as the force that can explain the accumulation of knowledge, economies and civiliza-tion itself. . . . an exhilarating narra-tive that will surely invite debate.

Kirkus Reviews

Hidden Costs of Energy: Unpriced Consequences of Energy Production and UseThe National Research Council Committee on Health, Environmental, and Other External Costs and Benefits of Energy Production and Consumption The National Academies Press500 Fifth Street NWWashington, DC 20001 USA2010. 473 pages. US$ 47.00

This book describes the effects of energy production and use—such as damage from air pollution from electric-ity generation, motor vehicle transpor-tation and heat generation—as hidden costs in energy market prices. It also considers other effects arising from climate change, air pollutants such as mercury and risks to national security. This analysis suggests that major initiatives to further reduce emissions, improve energy efficiency or shift to a cleaner electricity generating mix could reduce the damages of external effects.

Contents:

This report summarizes the findings of prestigious panels of experts in energy, health, economics, and the environment, but it fails in its mission to inform, due to the complex-ity of the issue and the large uncer-tainties in many of the parameters and variables considered. As might be expected, this is a tough read. . . .

Probably a must for those deeply involved in the economics of energy delivery and policy; all other readers will be disappointed by the lack of accessibility and concrete information on this incredibly important topic. Recommended.

Choice

Spring 2011 57

Petroleum Resources with Emphasis on Offshore FieldsO.T. Gudmestad, A.B. Zolotukhin and E.T. JarlsbyWIT PressAshurst LodgeAshurst, Southampton SO40 7AA England2010. 269 pages. US$ 198.00ISBN: 978-1-84564-478-9

This book presents lessons learned from mature Norwegian offshore projects. The authors take an interdisciplinary approach in exploring the petroleum industry’s upstream side, from locating resources offshore to their conversion to petroleum products. Gudmestad, Zolotukhin and Jarlsby emphasize the careful handling of natural resources, safe and environmentally friendly development practices, adherence to ethical business practices and attention to social responsibility.

Contents:

The ‘upstream’ side of the petro-leum industry worldwide is so com-plex and challenging that workers and decision makers comprise interdisci-plinary project teams requiring an unusual breadth of knowledge and

understanding. Thus, an up-to-date basic reference book is mandatory. Here, Gudmestad, . . . Zolotukhin . . . and Jarlsby . . . introduce essential critical topics simply and exception-ally lucidly. . . . The text is straight-forward and enhanced by excellent interpretive drawings. Select refer-ences follow each chapter. This is an indispensable resource for both students and industry professionals including scientists, engineers, economists, lawyers, environmental-ists, and politicians. Highly recommended.

Choice

The Geology of Stratigraphic Sequences, Second EditionAndrew D. MiallSpringer-Verlag GmbHHeidelberger Platz 314197 Berlin, Germany2010. 337 pages. US$ 99.00

This second edition, which stresses a deductive approach to geology, situates stratigraphic sequences within the broader context of geologic processes and attempts to answer the question: Why do sequences form? The book is intended for students of geology and professional geologists involved in hydrology and coal, gas and petroleum geology.

Contents:

Historical and Methodological Background, The Basic Sequence Model, Other Methods for the Stratigraphic Analysis of Cycles of Base-Level Change

The Major Types of Stratigraphic Cycle, Cycles with Episodicities of Tens to Hundreds of Millions of Years, Cycles with Million-Year Episodicities, Cycles with Episodicities of Less Than One Million Years

Summary of Sequence-Generating Mechanisms, Long-Term Eustasy and Epeirogeny, Tectonic Mechanisms, Orbital Forcing

An Assessment of the Current Status of”Global Eustasy”: The Concept of the Global Cycle Chart; Time in Sequence Stratigraphy; Chronostratigraphy, Correlation, and Modern Tests for Global Eustasy

This in-depth discussion of stratigraphic sequences requires the reader to have a strong background in geology, preferably with experience in stratigraphy and sedimentation and some knowledge of petroleum geology. . . . [I]t was the work of Peter Vail, working with Exxon in the 1960s–70s that revolutionized sequence stratigraphy as the domi-nant paradigm in the science of stratigraphy. In this new edition . . . Miall . . . examines in detail the results of Vail and his followers, showing where he agrees with those results and where he feels that the Vail/Exxon model has gone too far in extrapolating from these results. . . . A must-read book for those actively involved in stratigraphy. Highly recommended.

Choice

Quantum Man: Richard Feynman’s Life in ScienceLawrence M. KraussW.W. Norton & Company, Inc.500 Fifth AvenueNew York, New York 10110 USA2011. 350 pages. US$ 24.95

The author presents a new look at Richard Feynman, the physicist who changed the way scientists thought about quantum mechanics. Krauss, a physicist himself, describes how the Nobel Prize–winning physicist scruti-nized everything from different points of view before coming to his own conclusions. The author traces Feynman’s life and scientific career from his early days at the Manhattan Project to his rise as physics legend.

Contents:

Lights, Camera, Action; The Quantum Universe; A New Way of Thinking; Alice in Quantumland; Endings and Beginnings; Loss of Innocence; Path to Greatness; From Here to Infinity; Splitting an Atom; Through a Glass Darkly

Matter of the Heart and the Heart of Matter; Rearranging the Universe; Hiding in the Mirror; Distractions and Delights; Twisting the Tail of the Cosmos; From Top to Bottom; Truth, Beauty, and Freedom

‘Richard Feynman was a legend for a whole generation of scientists, long before anyone in the public knew who he was,’ writes Krauss in this engaging biography. . . . Feynman’s work has had an impact on almost every aspect of modern science today, from nanotechnology to particle physics, semi-conductors and high-temperature superconductors. . . . In the author’s view, he was arguably the most important scientist in the latter half of the 20th century, comparable to Einstein in influence, although his genius was not to achieve fundamen-tally new results but to look at ‘old things from a new viewpoint.’ Krauss explains the complicated scientific material in a clear, lively style that would have earned Feynman’s approval. A worthy addition to the Feynman shelf and a welcome follow-up to the standard-bearer, James Gleick’s (1992).

Kirkus Reviews:

Oilfield Review58

Earth MaterialsKevin Hefferan and John O’BrienWiley-Blackwell111 River StreetHoboken, New Jersey 07030 USA2010. 624 pages. US$ 99.95 ISBN: 978-1-4443-3460-9

Encompassing the study of minerals and rocks as well as soil and water, this textbook is designed for a combined mineralogy and petrology course. Its comprehensive framework is intended to serve not just students, but environ-mental scientists and engineering geologists as well. The book covers mineralogy, sedimentary petrology, igneous petrology and metamorphic petrology.

Contents:

provides a relatively balanced treatment of all major topics involving the various components of the earth. The book also emphasizes the various roles of earth materials as resources, hazards, and human health influences and their impact on the general global environ-ment and economy. The well-illus-trated text includes numerous, mostly appropriate, photos/figures/sketches, although color coding commonly is not clearly defined, and some figures are mislabeled. . . . This work should fill an important niche for lower- to intermediate-level earth and/or environmental science courses. Includes an extensive, up-to-date reference list, a relatively thorough index, and a companion web site. Recommended.

Choice

Geological Methods in Mineral Exploration and Mining, Second EditionRoger MarjoribanksSpringer-Verlag GmbHHeidelberger Platz 314197 Berlin, Germany2010. 238 pages. US$ 129.00

This step-by-step guide to searching for metallic deposits describes fundamen-tal geologic field techniques used for the collection, storage and presentation of geological data and their use in locating ore. Marjoribanks includes descriptions and examples from various projects on which he has worked. The author emphasizes traditional skills and shows how they can be effectively combined with modern technological approaches. Contents:

Marjoribanks wrote this slim but thoroughly informative volume . . . as a ‘practical field manual for geolo-gists engaged in mineral exploration.’ . . . The 10-chapter book begins with a general discussion of exploration and geological mapping in mineral exploration. . . . This new edition includes three more chapters than the 1997 edition, an expanded appendix section, and ample references. Recommended.

Choice

The Unfinished Game: Pascal, Fermat, and the Seventeenth-Century Letter that Made the World ModernKeith DevlinBasic Books, a member of The Perseus Books Group387 Park Avenue SouthNew York, New York 10016 USA2010. 208 pages. US$ 15.95

The author delves into the mathemati-cal breakthrough that Blaise Pascal and Pierre de Fermat developed in the mid-1600s: what is now known as probability theory. Devlin starts with a 1654 letter Pascal wrote to Fermat that explains how he discovered how to

calculate risk. The author weaves these ideas with the work of other early mathe maticians, offering insights into how these basic concepts impact our modern world.

Contents:

Prior to the development of statistics in the late seventeenth and eighteenth centuries, even rationalists were convinced that no human could speculate on the future. Devlin . . . shows us how that belief was trans-formed through the . . . critical letter from Pascal to Fermat in which he discusses ‘the problem of points’—that is, how to determine the probable outcome of a game of chance—as a framework for a history of probability theory and risk management, fields which now dominate our social, political and financial lives. . . . This informative book is a lively, quick read for anyone who wonders about the science of predicting what’s next and how deeply it affects our lives.

Publishers Weekly

Spring 2011 59

resource is present to economically justify completing and producing the well. Logging indicates the basic parameters of porosity (fluid-filled por-tion of the rock); the water, oil and gas saturations and the vertical extent of a productive hydrocarbon zone, or net pay (above). Logging tools are calibrated to properly determine these and other quantities from the res-ervoir so companies can calculate accurate reserve values. Most logging tools designed for formation evaluation are based on electric, nuclear or acoustic measurements.

Electric LoggingOil and gas are more resistive than the salty water that fills most deeply buried rocks. Engineers created two types of electric sondes; both of them measure that difference. One type, a laterolog, measures formation resistiv-ity by creating an electric circuit. Current flows from a tool electrode through the formation and back to another electrode. The other design uses induction coils to measure conductivity, the inverse of resistivity. This has similar physics to an electric transformer: A tool coil induces a current loop in the formation that is measured by a pickup coil on the tool. An extensive zone filled with hydrocarbon is apparent on an electric log typically as more resistive than an adjacent water-filled zone.

Detecting RadiationQuartz and carbonates, which compose the most common hydrocarbon reser-voirs, have little or no intrinsic radioactivity. Shales, which often act as seals above reservoirs, include several naturally occurring radioactive components. Most logging strings include a gamma ray sonde to detect this radiation and discriminate geologic layers. A characteristic pattern on the gamma ray log often repeats in logs for wells throughout a given area. Geologists correlate these patterns from well to well to map geologic layers across the field.

Some logging tools use chemical sources that generate radioactive particles. The particles interact with the surrounding formation, and detectors on the sonde pick up the resulting signals. Gamma radiation is absorbed proportionally to the density of the formation. Other radioactive particles—neutrons—are absorbed proportionally to the amount of hydrogen. Measurements from both of these types of logs can be converted to porosity values. Each has a variability

based on the rock type, and the average of the two, a density-neutron log, can be a good measure of porosity. In the presence of gas, the two detection methods separate in a distinctive manner that is recognized as a gas indicator. Some contemporary tools use a pulsed neutron generator, which can generate neu-trons only while power is applied.

The chemical makeup of minerals in a formation can be determined with a neutron source that uses elemental capture spectrometry. This infor-mation helps geologists determine the rock composition.

Acoustic LoggingThe speed at which sound travels through rock depends on its mineral com-position and porosity. An acoustic or sonic logging tool transmits a sound pulse into the formation and a receiver on another part of the tool detects the transmitted pulse. The travel distance of the pulse is known, so its travel time provides a sound velocity that is proprotional to a porosity measurement.

The mechanical properties of a solid affect properties of sound waves passing through it. Some sonic tools measure these changes to quantify those mechanical properties.

A Multitude of MeasurementsGeoscientists and engineers have access to a wide variety of logging tools that provide much more than the basic information described above. Nuclear magnetic resonance tools obtain information about pore sizes and fluids in situ. Imaging logs can provide a high-resolution and 360° view of various formation properties at the wellbore wall. Other tools can bring rock or fluid samples to surface or measure properties of fluids as they flow into the wellbore. And at a larger scale, measurements made with a source in one well and a receiver in another indicate formation and fluid properties between them.

Well logging requires robust technology because of harsh well conditions and cutting-edge technology because of complex reservoir properties. Scientists use sophisticated methods to design new tools and evaluate the data they collect. Most hydrocarbon discoveries today are in remote areas and often are difficult to produce. These resources—and the people to find, evaluate and produce them—are vital to fulfill the growing energy needs of the world.

> Logging measurements used to determine reservoir properties. Some tools provide a direct measurement of a reservoir property (blue) and some provide partial information that is combined with other measurements to determine the property (green). In addition, tools are often sensitive to a property, even though they do not provide a measurement of that property (brown).

Electrical resistivity Laterolog Induction MicrolaterologSpontaneous potentialElectromagnetic propagationNuclear Gamma ray density Neutron porosity Natural radioactivity Induced gamma ray spectrometryNuclear magnetic resonanceAcousticDipmeter and imagingFormation testing and sampling Rock sampling Fluids sampling Fluids pressure testingSeismic

Measurements Resistivity Porosity Lithology Mineralogy Saturation Pore geometry Permeability Fluid properties Geomechanicalproperties

Geologicstructure

Geologicbedding

Measurement provides direct information about the reservoir property.

Measurement contributes to understanding the reservoir property.

Measurement is influenced by or is sensitive to the reservoir property.

DEFINING LOGGING (continued from page 60)

Oilfield Review60

Discovering the Secrets of the Earth

Oilfield Review Spring 2011: 23, no. 1.

Copyright © 2011 Schlumberger.For help in preparation of this article, thanks to Austin Boyd, Rio de Janeiro; Michel Claverie, Clamart, France; Martin Isaacs, Sugar Land, Texas, USA; and Tony Smithson, Northport, Alabama, USA.

Mark A. AndersenExecutive Editor

Oil and gas reservoirs lie deep beneath the Earth’s surface. Geologists and engineers cannot examine the rock formations in situ, so tools called sondes go there for them. Specialists lower these tools into a wellbore and obtain measurements of subsurface properties. The data are displayed as a series of measurements covering a depth range in a display called a well log. Often, several tools are run simultaneously as a logging string, and the combination of results is more informative than each individual measurement (right).

The Dawn of an EraThe first well log was obtained in 1927 in Pechelbronn field in Alsace, France. The tool, invented by Conrad and Marcel Schlumberger, measured electrical resistance of the earth. Engineers recorded a data point each meter as they retrieved the sonde, suspended from a cable, from the bore-hole. Their data log of resistivity changes identified the location of oil.

Today, geologists depend on sets of well logs to map properties of subsur-face formations (below). By comparing logs from many wells in a field, geologists and engineers can develop effective and efficient hydrocarbon production plans.

Types of LogsImmediately after a well is drilled, the formations are exposed to the well-bore. This is an opportune time to determine the properties of the rocks using openhole logging tools. In some cases, particularly in wells with com-plex trajectories, companies include logging tools as part of the drilling tool assembly. This approach is referred to as logging while drilling, or LWD.

Drillers typically stabilize formations by cementing metal casing in the well. The metal of the casing interferes with many logging measurements, but over the past 30 years the industry has dramatically improved its ability to measure formation properties and even locate bypassed oil behind casing using cased-hole logs. In addition, many cased-hole tools measure fluid flow rates and other production parameters in the wellbore or examine the integrity of the metal casing and its cement.

The first objective of logging in an exploration area is to locate hydrocar-bons in a well. Next, the operating company wants to determine if enough

> Assembling a logging tool on a rig floor. One logging operator holds a logging tool in place (left) while another assembles a connection (right). The upper part of the tool is suspended from the rig derrick (not shown, above the men). The operators will connect that to the lower section of the tool, seen protruding above the rig floor between the men. That part of the tool is suspended in the wellbore, held in place at the rig floor by the flat metal C-clamp. Most logging tools have a small diameter but can be the height of an average one-story building. The combination of several sondes in one toolstring can be many stories tall.

> Basic log. A common combination of logging measurements includes gamma ray, resistivity, and neutron and density porosity combined on one toolstring. The gamma ray response (Track 1) distinguishes the low gamma ray value of sand from the high value of shale. The next column, called the depth track, indicates the location of the sonde in feet (or meters) below a surface marker. Within the sand formation, the resistivity (Track 2) is high where hydrocarbons are present and low where brines are present. Both neutron porosity and bulk density (Track 3) provide measures of porosity, when properly scaled. Within a hydrocarbon zone, a wide separation of the two curves in the way shown here indicates the presence of gas.

Gamma RaygAPI0 150

Bulk Densityg/cm31.90 2.90

Neutron Porosity%45 –15

ResistivityDepth,ft ohm.m0.2

7,000

7,100

7,200

7,300

20

Shale

Shale

Sand

Hydrocarbon

Brine Brine

Oil

Gas

(continued on page 59)

The first in a series of articles introducing basic concepts of the E&P industryDEFINING LOGGING