technology developments in natural gas exploration ... · gas technology institute/rpsea and...

Enhancing Microbial Gas from Unconventional ReservoirsAmherst College and the University of Massachusetts Amherst have formed a research partnership toexamine methanogenesis in sedimentary basins. Funding from the National Science Foundation, theGas Technology Institute/RPSEA and industry partners has allowed this group to develop a multifac-eted study on gas from the Michigan Basin and Forest City Basin, drawing from tools common toaqueous, isotope and organic geochemistry as well as environmental and molecular microbiology.

High Temperature Electronics—One Key to Deep Gas ResourcesLarge resources of unconventional gas are locked up in tight-gas sands, shales and coalbedmethane throughout the Gulf of Mexico, Rocky Mountains, Texas, Oklahoma and AppalachianBasin, but to obtain this resource, there are a number of hurdles to overcome.

Enhanced Wellbore Stabilization and ReservoirProductivity with Aphron Drilling Fluid TechnologyLaboratory research is required to provide understanding and validation of aphron drilling fluid technol-ogy as a viable and cost-effective alternative to underbalanced drilling of depleted oil and gas reservoirs.

Fiber Laser Offers Fast Track to Clean PerforationsTraditional methods of completing a cased hole include perforating with explosives, creating a tunnel toallow production of reservoir fluids to the surface. Although methods have been devised throughout theyears to optimize this completion process, significant damage to the reservoir is typically created with acorresponding restriction to fluid flow. In addition to this damage are concerns of safety and security.

Safety Net Royalty Relief Analysis of Natural Gas and Oil Production and Revenues The U. S Department of Energy’s National Energy Technology Laboratory has completed work onbehalf of the Bureau of Land Management that evaluates potential impacts of tax and royaltyincentives and the trade-offs of these incentives on future production from federal and NativeAmerican gas and oil leases during the next 20 years.

Regulatory Considerations in the Managementof Produced Water—A U.S. PerspectiveThere are a number of U.S. regulations of which to be aware and consider when managing pro-duced water domestically.

Volume-Optimized Compressed Natural Gas Recent trends in the overall growth of global energy demand and the preference for natural gaswithin the mix of fuel supply choices has spawned a resurgence in the development of natural gasprojects as well as the acceleration of new technologies to help connect stranded gas resourcesand consuming markets.

TECHNOLOGY DEVELOPMENTS IN NATURAL GAS EXPLORATION, PRODUCTION AND PROCESSING

A Publication of Gas Technology Institute, the U.S. Department of Energy and Hart Energy Publishing, LP

GasTIPS®

Items of Interest 02 Editors’ Comments33 Events Calendar, Briefs and Contacts

Spring 2005 • Volume 11 • Number 2

GTI-05/0226

UnconventionalReservoirs

Deep Gas

EconomicImpact

Drilling Fluid

LaserTechnology

ProducedWaterManagement

Transport &Storage

3

8

12

17

21

25

29

The goal: economically stimulating the pockets of oil and gas you used to

bypass. The means: Halliburton’s family of pinpoint stimulation technologies.

The key is different systems for different applications. Because each well type

has its special challenges—new wells and old wells, vertical and horizontal.

But one common theme: if there’s a zone of interest, Halliburton can help you

stimulate it with pinpoint accuracy and great operational efficiency.

Halliburton has the energy to help. To learn more about Halliburton’s

pinpoint stimulation technologies, contact your representative or

visit www.halliburton.com.

Unleash the Energy.

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Pinpoint stimulation technologies help you reach more zones.

© 2005 Halliburton. All rights reserved.

HALLIBURTON

Production Optimization

Spring 2005 • GasTIPS 1

Managing EditorMonique A. BarbeeHart Energy Publishing, LP

Graphic DesignMelissa RitchieHart Energy Publishing, LP

EditorsGary SamesDOE-NETL

Kent PerryGas Technology Institute

Subscriber ServicesAmy [email protected] Energy Publishing, LP

PublisherHart Energy Publishing, LP

C O N T E N T SEditors’ Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Unconventional Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Deep Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Drilling Fluid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12

Laser Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Economic Impact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Produced Water Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Transport & Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Briefs and Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .33

DISCLAIMER:LEGAL NOTICE: This publication was pre-

pared as an account of work sponsored

by either Gas Technology Institute (GTI) or

the U.S. Department of Energy, (DOE).

Neither GTI nor DOE, nor any person act-

ing on behalf of either of these:

1. makes any warranty or representa-

tion, express or implied with respect to the

accuracy, completeness or usefulness of

the information contained in this report

nor that the use of any information, appa-

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report may not infringe privately owned

rights; or

2. assumes any liability with respect

to the use of, or for damages resulting

from the use of, any information, appara-

tus, method or process disclosed in this

report.

Reference to trade names or specific

commercial products, commodities, or

services in this report does not represent

or constitute an endorsement, recommen-

dation, or favoring by GTI or DOE of the

specific commercial product, commodity

or service.

GasTIPS®

GasTIPS® (ISSN 1078-3954), published four times a year by Hart Energy Publishing, LP,reports on research supported by Gas Technology Institute, the U.S. Department of Energy,and others in the area of natural gas exploration, formation evaluation, drilling and com-pletion, stimulation, production and gas processing.

Subscriptions to GasTIPS are free of charge to qualified individuals in the domestic naturalgas industry and others within the Western Hemisphere. Other international subscriptionsare available for $149. Domestic subscriptions for parties outside the natural gas industryare available for $99. Back issues are $25. Send address changes and requests for backissues to Subscriber Services at Hart Energy Publishing, 4545 Post Oak Place, Suite 210,Houston, TX 77027, Fax: (713) 840-0923. Comments and suggestions should be directed toMonique Barbee, GasTIPS managing editor, at the same address.

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2 GasTIPS • Spring 2005

A s this issue of GasTIPS goes topress, the U.S. Senate is beginningwork on an Energy Bill passed by

the U.S. House of Representatives. Two ele-ments of this bill would encourage the devel-opment of “deep” gas: an Onshore Deep GasProduction Incentive that would providefederal royalty incentives for onshore deepgas production; and Incentives for NaturalGas Production from Deep Wells in ShallowWater in the Gulf of Mexico, which wouldprovide for royalty incentives for natural gasat depths greater than 18,000ft below theocean floor. These incentives speak to thefact that demand for natural gas is increas-ing, as are the costs of developing newreserves, particularly those at greater depths.

The oil and gas industry spent 36% more in2003 to drill and equip gas wells than it did in2002, according to the 2003 Joint AssociationSurvey on Drilling Costs released last monthby the American Petroleum Institute (API).The survey also shows that 2003 was the 16thconsecutive year the industry spent moredrilling for natural gas than for oil. Everymetric was up compared with the previousyear’s gas well drilling: average depth (3.2%),median cost per well (14.2%) and average costper foot (8.1%).

A deep gas well is defined as any well thatproduces from a depth below 15,000ft.According to the Potential Gas Committee’s(PGC) report published in 2003, there aremore than 2,500 active well completionsbelow that depth in the lower 48 states, pro-ducing from more than 180 separate reser-voirs. These deep gas reservoirs are primarilyfound in the onshore and offshore basins ofthe Louisiana and Texas Gulf Coast, in theAnadarko and Permian basins of the mid-continent and in a number of RockyMountain basins.

The PGC reported in 2003 that the aver-age recoverable reserve for a deep gas wellvaries from 6 Bcf to nearly 34 Bcf, dependingon the basin. While only half of 1% of the gaswell completions in the lower 48 states qual-ify as deep completions, together they histor-ically produced 55 Tcf (6%) of the natural gascumulatively produced through 2002.

In addition, a significant volume of deepgas remains to be discovered. The commit-tee’s 2003 estimate of technically recoverablegas remaining to be discovered at depthsbetween 15,000ft and 30,00ft was 133 Tcf,or about 29% of the nation’s potential gasresource. More than half this potential liesbeneath the onshore and offshore areas ofthe Gulf of Mexico region. The industry isspending increasing amounts of money todevelop deep gas, and a rising percentage ofthis money is being spent in the Gulf ofMexico region.

These reserves are not easily captured.Deep gas wells are more than twice as expen-sive on a cost per foot basis as a typical gaswell. According to the API survey*, the costto drill and equip the median gas well in 2003was about $289,000. The average deep, non-deviated, onshore well drilled in 2003 (307deep wells averaged 16,936ft) cost $6.82 mil-lion. The average cost per foot for onshore,non-deviated deep gas wells was $403/ft com-pared with $190/ft for the average U.S. gaswell. Offshore in the Gulf of Mexico, deep gaswell costs run to $1377/ft. It is extremelyimportant that these costs are reduced.

The U.S. Department of Energy (DOE)has been sponsoring the Deep Trek Programto help develop the high-tech drilling tech-nology the industry needs to economicallydevelop this deep resource. Two of the arti-cles in this issue of GasTIPS detail some ofthese efforts.

The first is an update on National EnergyTechnology Laboratory (NETL) efforts toextend the capabilities and reliability of log-ging tools – including logging-while-drillingand measurement-while-drilling tools – andother “smart” well equipment. Key to thisextension is the production of electroniccomponents that can operate at temperaturesup to 600°F. The NETL has formed a jointindustry project with electronics manufactur-ers and oilfield end-users to achieve this goal.

A second article provides an update onefforts to develop laser technology for usedownhole as a perforating mechanism.Achieving effective perforations in the hardrocks found at great depths is not an easytask. Gas Technology Institute (GTI) hasbeen evaluating the possibility that lasersmight some day be configured to accomplishthis feat and provides an update of thisresearch in this issue.

Together with these two articles focusingon deep gas technologies, are a number ofothers that provide insights on other NETLand GTI research efforts related to the geo-chemistry of gas from fractured shale, pro-duced water management, cost-benefitanalysis of royalty incentives and marinetransport of compressed natural gas. Wehope you find this issue informative. ✧

* The 2003 Joint Association Survey (JAS)on Drilling Costs is available electronically andin hard copy from the American PetroleumInstitute, Statistics Department, by calling(202) 682-8508. The cost for non-members is$6,500. JAS statistics provided above courtesy ofJeff Obermiller.

Commentary

Developing Deep Gas Resources Key to Meeting Energy Demand


UNCONVENTIONAL RESERVOIRS

With demand for naturalgas on a steady rise(about a 30% increase

during the past 15 years), uncon-ventional gas deposits such asthose produced from coalbeds andshales are receiving attention from small independent operatorsand major energy companies. Inunconventional plays, knowing theorigin of the gas is fundamental forassessing reservoirs and guidingexploration strategies. Basin mar-gins generally exhibit low organicmatter maturity and active hydro-logic flow systems, while deepersections are more mature. Thus,exploration for gas of thermogenic originwould target mature sections of a basin,while exploration in unconventional gasplays of predominantly microbial origin mayinstead more successfully target basin mar-gins. Given the extensive occurrence andabundance of fractured black shales andcoalbeds throughout U.S. sedimentary basins(Figure 1), there is a significant economicincentive to evaluate potential microbial ori-gins of gas plays. Methanogenesis, or micro-bial methane generation, may be a significantand sustainable source of natural gas in manyunconventional gas reserves.

The organic-rich shales of the easternUnited States have a long history of gas

production, accounting for nearly 2% ofcurrent domestic natural gas production.Since 1988, U.S. shale gas production hasincreased by more than 60%, primarilybecause of a single new black shale play –the Antrim Shale in the Michigan Basin.Given its importance, the Antrim Shaleprovides a model setting to study microbialmethanogenesis and modification of ther-mogenic gas. Development in the ForestCity Basin (Iowa-Missouri-Kansas-Neb-raska) has revealed this play as anotherpotential source of microbial gas.

Antrim Shale wells from the northern mar-gin exhibit the highest natural gas productionrates in the basin, strongest geochemical and

isotopic indicators of microbialactivity and sharpest chemical gra-dients in formation water composi-tion. Production histories of wellsin the region suggest active and sus-tained methane generation, ratherthan relict methane generated inthe geologic past. Living organismsare detected in a number of produc-tive well waters, with genetic signa-tures suggesting high relatedness toother known forms of methane-generating microorganisms. Similargeochemical and microbiologicalindicators are observed in ForestCity Basin waters suggesting thisplay too may derive from active

subsurface methanogenesis.One key geochemical indicator of micro-

bial activity in subsurface formation watersis the concentration of dissolved inorganiccarbon (DIC), also known as carbonatealkalinity. In most formation waters, alkalin-ity is held buffered at low concentrationsthrough equilibrium with carbonate miner-als in the rock. Accordingly, groundwaters inthe overlying glacial drift and deep centralAntrim brines measure about 0-5 meq/LDIC (Figure 2a). However, when otherprocesses, such as organic matter degrada-tion, contribute alkalinity to formationwaters, DIC concentrations rise. Antrimwaters collected along the N, W and S

By Anna M. Martini, Amherst College; and

Klaus Nüsslein and Steven T.Petsch, University of

Massachusetts Amherst

Enhancing Microbial Gas from UnconventionalReservoirsAmherst College and the University of Massachusetts Amherst have formed a research partnership toexamine methanogenesis in sedimentary basins. Funding from the National Science Foundation, theGas Technology Institute/RPSEA and industry partners has allowed this group to develop a multifac-eted study on gas from the Michigan Basin and Forest City Basin, drawing from tools common toaqueous, isotope and organic geochemistry as well as environmental and molecular microbiology.

Figure 1. Distribution of U.S. coalbed and shale gas resources(Newell et al. 2004). Many of these basins include a mix of ther-mogenic and microbial gas.



Margins all exhibit DIC concentrations>>10 meq/L, and Forest City Basin watersare similarly high in alkalinity. This indi-cates extensive organic matter (OM) oxida-tion within the Antrim Shale and ForestCity coals localized along basin margins.

Stable carbon isotope ratios also provide a

measure of microbial activity within shaleformation waters. The ratio of 13C to 12C inDIC reflects a balance between sources ofDIC, equilibration with carbonate mineralsand processes that remove DIC from thewater. By convention, differences in 13C/12Cratios are expressed as per mill deviations offa standard on the δ13C scale. In most forma-tion waters, carbonate mineral equilibrationdominates, generating carbon isotope ratios(δ13C values) similar to carbonate in the rock.This is seen in δ13CDIC values in waters fromthe overlying glacial drift and deep Antrimbrines, indicating little or no microbial activ-ity in the central Michigan basin. However,microbial methane generation consumesDIC in a process strongly selective for 12C,leaving behind DIC that becomes more andmore enriched in 13C. This form of Rayleighisotope distillation indicates closed or nearlyclosed system behavior. The extremely 13C-enriched δ13CDIC values in productive Antrimwaters are some of the highest measured innatural waters anywhere, indicating extensivemethanogenesis along the margins of theMichigan Basin (Figure 2a). Forest CityBasin waters also exhibit elevated δ13CDIC val-ues, but not as extreme as in Antrim Shalewaters. This indicates a more open isotopicsystem operating in the Forest City play.

Stable carbon isotopic ratios of natural gasprovide an effective tool to distinguish ther-mogenic from microbial gas. Thermogenicmethane forms by abiotic cracking of kero-gen, generating methane slightly depleted in13C relative to bulk organic matter. Moreimportantly, however, thermogenic δ13CCH4

values will exhibit no relationship with for-mation water δ13CDIC values. In contrast,microbial gas generation is intimately linkedwith DIC geochemistry. Methane δ13C val-ues are systematically offset from δ13CDIC val-ues by about 78‰. Early researchers identi-fied gas in the Antrim as thermogenicbecause δ13CDIC was not measured andassumed to be near 0‰. δ13CCH4 values ofabout -50‰ seemed to more closely resem-

ble kerogen δ13C. However, measurement ofa single isotopic parameter, δ13CCH4 values, isnot sufficient to uniquely identify methano-genesis. When coupled to measurement ofthe extremely 13C-enriched pool of DIC,Antrim methane is clearly shown to obey atight relationship between δ13CCH4 andδ13CDIC values offset by 78 ‰ (Figure 2b).Once again, the Forest City Basin samplesplot nearer to open system fractionation.

During methanogenesis, there also is adirect link between hydrogen isotopic ratios(D/H) of H2O and microbial CH4. This rela-tionship is not observed in thermogenic gas. Astrong regional H-isotope gradient in Antrimwaters (δD from -25‰ to -100‰) permitschemical tracing of H2 derived from H2O

4.For the Forest City Basin and most of the W,N and S margins of the Antrim Shale, theδDCH4-H2O relationship δDCH4 =δDH2O + 160(± 10‰) (Figure 2c) indicates a strong imprintof microbial methane generation. In contrast,CH4 from the central Michigan Basin has δDvalues consistent with a thermogenic originand little evidence of equilibration with associ-ated waters.

Pathways and constraints onmicrobial methane generationThere remains a key unresolved questionregarding sedimentary basin methanogene-sis: what fuels these subsurface microorgan-isms to generate such significant amounts ofmethane? Active microbial populations arerecognized in a variety of subsurface sedi-mentary environments, including OM-poormarine sediments, gas hydrate-rich sedi-ments, sedimentary rocks, petroleum-conta-minated aquifers, unconsolidated sedimentsand petroleum reservoirs. Only one group ofmicroorganisms (Archaea) is capable of gen-erating methane, and only through a limitednumber of metabolic reactions (Table 1).These organisms are strict anaerobes that diein the presence of oxygen and are easily out-competed by other forms of microorganisms.None of the chemical precursors for

Figure 2. New data from the Forest CityBasin and Antrim Shale plotted with pre-viously published data.



methanogenesis (H2, single-carbon compounds and acetate)are abundant in biologicallyinactive sedimentary basins.Thus microbial methane gener-ation in the Antrim and ForestCity Basin must be coupled toanaerobic biodegradation ofshale OM (kerogen, bitumensor aqueous dissolution prod-ucts) to generate the necessarysubstrates for active methano-genesis. Thus the questionbecomes not “What fuels methanogenesis?”but rather “What fuels production of theprecursors that drive methanogenesis?”

Methanogenesis by itself requires no exter-nal supply of e-acceptors, only H2, CO2 andacetate. An intriguing source of H2 andacetate in environments where competitionfrom anaerobic respiration cannot occur isdecomposition of hydrocarbons leading tomethanogenesis. Zengler and colleaguesshowed that hexadecane decomposition toacetate and H2 can proceed (i.e. is energeti-cally favored) if coupled with removal ofacetate and H2 through the activity ofmethanogens. These three microbial reactions(Table 2) can operate in syntrophy, decom-posing hydrocarbons into methane and CO2

in a set of reactions thermodynamicallyfavored only when combined. Although ini-tial reports suggested this reaction is sluggishand revealed concerns about co-metabolismwith sulfate-reducers, subsequent study hasindicated this process is fairly rapid in subsur-face sediments and in the absence of sulfate.

Microscopic evidence of active microbial populations in the AntrimFreshly collected waters from the mainAntrim gas-producing trend reveal anactive, and in some cases motile, populationof organisms when examined under themicroscope. This stands in strong contrastto saline waters in the center of the basin

(where cells are absent) and glacial driftwaters (in which cells are sparse). Microbialincubation experiments using Antrim for-mation waters are also instructive models ofsubsurface microbial activity in theMichigan Basin. No detectable growth isobserved under aerobic or nitrate-reducingconditions. Growth is detected under sul-fate- and iron-reducing conditions, andstrong growth is observed under conditionssupporting fermentation and methanogene-sis. Importantly, when waters collected fromoutside the main gas-producing zone wereused (e.g. from the southernmost, highlysaline well), no growth in any of the enrich-ment media was observed. Only limitedgrowth (nitrate reduction, fermentation)was detected in waters collected from theglacial drift recharge well. Methane-producing enrichment cultures inocu-lated with waters from the Antrim Shalemain gas-producing trend revealed anabundant array of cells, with two domi-nant morphologies: single or paired rod-shaped cells and long filaments of cellslinked in single rows end-to-end (Figure3a). In contrast, sulfate- and ferric iron-reducing enrichments exhibit a dis-tinctly different mor-phology of princi-pally single (Fe-reducing, Figure 3b)or paired cells (SO4-reducing, Figure 3c).

Community analyses based on DNA Attempts to culture microorganisms in thelaboratory generally are of limited success;less than 0.1% of microorganisms can begrown in the laboratory on media.Thus iden-tification of microbial communities reliesheavily on culture-independent techniquesemploying sequences of DNA isolated fromenvironmental samples. These techniqueshave been applied to waters collected fromproductive and non-productive Antrim wellsand overlying glacial drift waters. Ourresearch compares sequences among species-indicating marker genes to identify commu-nity members and functional, protein-codingmarker genes to evaluate genetic diversityamong the methanogens present.

Figure 3. All photomicrographs are of enrichments from a single producing well. a) Epifluorescent pho-tomicrograph of DAPI-stained methanogenic enrichment culture. b) Plain light photomicrograph of fer-ric iron-reducing enrichment culture. Black precipitate is iron sulfide. c) Epifluorescent photomicrographof DAPI-stained sulfate-reducing enrichment culture. Scale bar is ~25 µm.

Table 2. Syntrophic anaerobic decomposition of hydrocarbons

(1) hexadecane (C16H34) + 16 H2O ➝ 8 CH3COO- + 8 H+ + 17 H2

(2) CH3COO- + H+ ➝ CH4 + CO2

(3) 4 H2 + CO2 ➝ CH4 + 2 H2O

Table 1. Selected methane-generating pathways

4 H2 + CO2 ➝ CH4 + 2 H2O

CH3COO- + H+ ➝ CH4 + CO2

4 CH3OH ➝ 3 CH4 + CO2 + 2 H2OCH3OH + H2 ➝ CH4 + H2O4 CO + 2 H2O ➝ CH4+ 3 CO2

Other known substrates: formate, amines, thiols

a) c)b)



DNA extracted from wells within theproducing trend exhibits rich diversityamong Archaea. In particular, the speciesthat dominate these communities aredirectly or indirectly implicated in methano-genesis, such as acetate producers, syntrophsand methanogens. This description of com-munity composition is based on markergene analysis (16S rRNA) for presence ofArchaea and analysis of a functional gene(mcrA) specific to methanogens. Themethanogenic community is particularlyrich in species members (Figure 4).Numerous novel genetic sequences werefound, clustering within groups ofmethanogens such as Methanomicrobiales,Methanosarcinales and Methanobacteriales.Bacteria diversity is much more limited,mainly to acetate-producing members of theAcetobacteria, Syntrophomonadaceae andSyntrophobac-teraceae. Surprisingly, no DNAor enrichment culture evidence for sulfate-or metal-reducing bacteria is detected inAntrim waters.

Microcosm methanegenerationThis research also includes micro-cosm experiments in which Antrimand Forest City formation watersare returned to our laboratories inAmherst, Mass., under O2-freeconditions. These waters are thenused to establish microcosms ofmicrobial activity representative ofambient environmental conditionsin the subsurface. Methane concen-trations were measured in the head-space of microcosm experimentsinoculated with formation watersfrom wells in the Forest City Basinand from the main gas-producingtrend of the Antrim Shale. Controland sterile blank experiments showno methane generation, whileincreased methane concentrationsup to 20 micromoles/L are mea-sured in the headspace of micro-

cosms containing methanogenic enrichmentmedia. Dilution and transfer of methanogenicenrichment cultures into new enrichmentmedia initiates renewed methane generationafter increases in methane concentration hadleveled off. Similarly, methane generation wasachieved in unamended formation waters indilution stimulation experiments where rela-tively dilute formation waters from the maingas-producing trend in the Antrim weremixed with poorly producing waters from thehighly saline center of the basin. Whilemethane concentrations in these mixed exper-iments do not match those observed in thehighly producing trend, the concentrationsachieved are much greater than measured inmethane-poor waters prior to amendment.

Conclusions and recommendationsGeochemical analyses confirmed microbialmethanogenesis as the dominant methanesource in Antrim formation waters andrevealed significant microbial methane gener-

ation in Forest City Basin formation waters.Active (rather than relict or ancient) methanegeneration was confirmed in enrichment aswell as microcosm experiments using watersfrom both reservoirs, a finding that has signif-icant implications for gas production predic-tion. Genetic information obtained fromDNA isolated from Antrim formation watersindicates a microbial community comprisedof acetogenic bacteria acting in syntrophywith acetate-utilizing and CO2-reducingmethanogenic Archaea. Thus, active micro-bial methanogenesis in sedimentary basinsmay not depend on an external supply of elec-tron acceptors (e.g. sulfate, ferric iron), butinstead reflects internal control limited by for-mation water hydrology, geochemistry andorganic matter composition.

The results of this seed project involvingmicrobial community analysis in shale gasplays strongly indicate microbial methane gen-eration in sedimentary basins is an activeprocess, with a high potential for stimulationand extension of projected well productionhistories. Application of these results has adirect relationship with potential targets ofexploration and gas production in other sedi-mentary basins where methanogenesis mayoccur or, in the future, be stimulated. Thus,this research may contribute toward develop-ment of technologies to enhance methane pro-duction in shale gas plays and help secure nat-ural gas resources from the extensive occur-rence of fractured black shales and coal bedsfound throughout the United States.

Further investigations are necessary tounderstand microbial methane generation todevelop strategies to target or deploy naturallyoccurring microorganisms for conversion ofdomestic hydrocarbon resources to naturalgas. In addition, geologically distinct regionsshould be examined for fingerprints of bio-genic gas production, both geochemical andbiological. Through strategic analysis of moregas-producing sites, we will identify and char-acterize the full range of anaerobic microbialconsortia capable of producing methane.

Acetobacterium

Syntrophomonadaceae

CampylobacteraceaeSyntrophobacteraceae

Bacteroidaceae

Bacteroidales

ClostridialesUnclassified Bacteria

Methanosarcinales

Methanomicrobiales

UnclassifiedArchaea

Archaea

Bacteria

Figure 4. Diversity and relative abundance ofArchaea (top) and Bacteria (bottom) from culture-independent molecular studies of a gas-producingwell in the Antrim Shale. Note that methanogenscomprise almost the entire Archaea diversity. For theBacteria, note the dominance of Acetobacterium rel-atives and the absence of sequences related to sul-fate- or metal-reducing bacteria.



This research demonstrates a direct pathtoward stimulating and enhancing gas gener-ation in unconventional resources, crucial forsecuring U.S. domestic energy resources.These highly promising preliminary resultsexhibit the synergy of combined geochemical,isotopic and microbiological efforts to investi-gate the activity of economically importantmicrobial processes in the subsurface. ✧

References 1. Hill, D. G. and Nelson, C. R., Gas ProductiveFractured Shales: An Overview and Update:GRI, GasTIPS, p. 2-9, June 2000.2. Newell, K.D., Johnson, T.A., Brown,W.M., Lange, J.P. and Carr, T.R., Geologicaland Geochemical Factors Influencing theEmerging Coalbed Gas Play in the Cherokeeand Forest City Basins in Eastern Kansas.Kansas Geological Survey, University of Kansas,Open-file Report 2004-17.3. Martini, A. M., Walter, L. M., Budai, J. M.,Ku,T. C. W., Kaiser, C. J., and Schoell, M. (1998.Genetic and Temporal Relations betweenFormation Waters and Biogenic Methane:Upper Devonian Antrim Shale, Michigan

Basin, USA. Geochimica et Cosmochimica Acta62, 1699-1720.Martini et al., 2003.4. Martini, A.M., Walter, L.M., Ku, T.C.W.,Budai, J.M., McIntosh, J.C., and Schoel, M.,Microbial Production and Modification ofGases in Sedimentary Basins: A GeochemicalCase Study From a Devonian Shale Gas Play,Michigan Basin. AAPG Bulletin 87, 1355-1375, 2003.5. Schoell, M. The Hydrogen and CarbonIsotopic Composition of Methane fromNatural Gases of Various Origins, Geochimicaet Cosmochimica Acta 44, 649-661, 1980.6. Wellsbury, P., Mather, I., and Parkes, R. J.,Geomicrobiology of Deep, Low OrganicCarbon Sediments in the Woodlark Basin,Pacific Ocean. FEMS Microbiology Ecology42, 59-70, 2002.7. Parkes, R.J., Cragg, B.A., Getliff, J.M,Goodman, K., Rochelle, P.A., Fry, J.C.,Weightman, A.J., and Harvey, S.M., DeepBacterial Biosphere in Pacific Ocean Sed-iments, Nature 371, 410-413, 1994.8. Parkes, R.J., Cragg, B.A., and Wellsbury, P.,Recent Studies on Bacterial Populations andProcesses in Marine Sediments: A Review.

Hydrogeology Journal 8, 11-28, 2000.9. Wellsbury, P., Goodman, K.,Cragg, B.A., and Parkes, R.J., TheGeomicrobiology of Deep MarineSediments from Blake RidgeContaining Methane Hydrate(Site 994, 995, and 997). Proc-eedings of the Ocean DrillingProgram, Scientific Results 164,379-391, 2000.10. Krumholz, L. R., McKinley, J. P.,Ulrich, G. A., and Suflita, J. M.,Confined Subsurface MicrobialCommunities in Cretaceous Rock.Nature 386, 64-66et al., 1997.11. Ringelberg, D. B., Sutton, S., andWhite, D. C., Biomass, Bioactivityand Biodiversity: Microbial Ecol-ogy of the Deep Subsurface:Analysis of Ester-linked Phosph-olipid Fatty Acids. FEMS Micro-

biology Reviews 20, 373-377, 1997.12. Colwell, F. S., Onstott, T. C., Delwiche, M.E., Chandler, D., Fredrickson, J. K.,Yao, Q.-J., McKinley, J. P., Boone, D. R.,Griffiths, R., Phelps, T. J., Ringelberg, D.,White, D. C., LaFreniere, L., Balkwill, D.,Lehman, R. M., Konisky, J., and Long, P. E.,Microorganisms from Deep, High Tempera-ture Sandstones: Constraints on MicrobialColonization. FEMS Microbiology Reviews20, 425-435, 1997.13. Kotelnikova, S., Microbial Productionand Oxidation of Methane in DeepSubsurface. Earth-Science Reviews 58, 367-395, 2002.14. Petsch, S. T., Eglinton, T. I., and Edwards,K. J., 14C-dead Living Biomass: Evidencefor Microbial Assimilation of AncientOrganic Matter during Shale Weathering.Science 292, 1127-1131, 2001.15. Lovley, D.R., Woodward, J.C., and Chapelle,F.H., Stimulated Anoxic Biodeg-radation ofAromatic Hydrocarbons using Fe(III)Ligands. Nature 370, 128-131, 1994.16. Lovley, D.R., Geomicrobiology: Inter-actions between Microbes and Minerals.Science 280, 54-55, 1998.17. Orphan, V. J., Taylor, L. T., Hafenbradl,D., and Delong, E. F., Culture-dependentand Culture-independent Characterizationof Microbial Assemblages Associated withHigh-temperature Petroleum Reservoirs,Applied and Environmental Microbiology66(2), 700-711, 2000.18. Röling, W. F. M., Head, I. M., and Larter,S. R., The Microbiology of HydrocarbonDegradation in Subsurface PetroleumReservoirs: Perspectives and Prospects,Research in Microbiology 154, 321-328, 2000.19. Zengler, K., Richnow, H. H., Rosseló-Mora,R., Michaelis, W. and Widdel, F., MethaneFormation from Long-chain Alkanes byAnaerobic Microorganisms, Nature 401,266-269, 1999.20. Anderson, R. T. and Lovley, D. R., Hexade-cane Decay by Methanogenesis. Nature 404,722-723, 2000.

ANAEROBIC RESPIRATIONAnaerobic respiration is the oxidation of organic matterusing electron acceptors (e-acceptors) other than oxy-gen, such as ferric iron minerals or dissolved sulfate.The products of respiration can be coupled to micro-bial fermentation reactions to yield H2 and acetate.Common anaerobic respiration pathways detected insubsurface environments include iron- and sulfate-reduction. Provided that e-acceptors can be suppliedin sufficient, sustained quantities, anaerobic respirationas the initiator of fermentation and methanogenesismight be predicted as a common feature of sedimen-tary basins. A strong limitation to respiration is imposedby extremely slow migration of fluids resupplyingpotential terminal e-acceptors. Oxidized iron mineralsare not abundant in black shales, and sulfate resupplyrequires constant recharge from either seawater orevaporites. Unless a mechanism can be establishedthat maintains a sustained supply of e-acceptors to theAntrim or Forest City Basin, anaerobic respiration isunlikely to be an important means of providingsubstrates for fermentation and methanogenesis. Our geochemical analyses support this conclusion; sulfateconcentrations are below detection limit in all wellswith significant microbial gas contributions.


DEEP GAS

There are a number ofchallenges from costand technological imp-

rovement before significantquantities of gas can be categorized as a potentialresource to technically andeconomically recoverable res-erves (Figure 1). A consider-able amount of this gas is indeep (greater than 15,000ft)sources. Recently, a majoroil company announcedplans to drill more than30,000ft below the mudline on the Gulf ofMexico Continental Shelf. Current indica-tions show environments at these depthswill be high pressure (HP – approaching30,000psi) and high temperature (HT –greater than 600°F).

Efforts to extend the capabilities and reli-ability of logging tools – including logging-while-drilling (LWD) and measurement-while-drilling (MWD) – and other “smartwell” tools to these HT and HP have beenunderway for some time. In the late 1990s,prior to the current Deep Trek program, theU.S. Department of Energy’s (DOE)National Energy Technology Laboratory(NETL), Maurer Engineering Inc., Hall-ibuton’s Sperry-Sun Drilling Services andHalliburton Energy Services recognized thefuture need for HT drilling and geologicalmeasurement technology. Two partnershipprojects were to enhance the capabilities of

HT LWD and MWD tools. The LWD pro-ject was to extend the capability of such tools(from 284°F to 347°F with survivability to392°F). The MWD project objective was toextend the temperature of the suite of toolsfrom 347°F to 383°F.

Although a complete suite of MWD toolswas not developed during that project, theMWD project did advance the knowledgebase with significant lessons learned and pro-vided important direction to additionalresearch for MWD and LWD tool develop-ment. Changes made as a direct result of workperformed under these projects have resultedin improved life and a more robust MWDtool at the previous temperature rating of346°F, as well as limited use at higher temper-atures. The LWD project also benefited fromlessons learned in the MWD project.

These two studies and other industryinformation showed current electronics are

not capable of providing thebuilding blocks to developthe tools necessary to charac-terize the reservoirs and drillthe complex wells at theseHT/HP environments. As aresult, the DOE’s Office ofFossil Energy (FE)/NETLhas taken a leadership role,partnering with the industryto encourage the devel-opment of HT electronic component building blocks.Thus the electronics industry

should be able to provide the infrastructurethe oil and gas industry needs to develop thenecessary advanced electronic tools to exploreat deep HT/HP depths in the near future.

The oil and gas industry is not the only onein need of elevated temperature electronics.Other industries will need the HT compo-nents for improved safety, reliability andmaintainability at lower cost. Some of theseother industrial applications include automo-biles with longer life and higher fuel effi-ciency, chemical processes with ultra-precisecontrol and minimal waste, and commercialand military aircrafts that can fly at greaterthan twice the speed of sound. Even with allthe other industries, the market for HT elec-tronics is not sufficient to sustain the researchand development, and process developmentto manufacture the HT electronics compo-nents or building blocks of the LWD, MWDlogging and other downhole electronic

By John D. Rogers, Ph.D., PMP, P.E.,U.S. Department of Energy/National

Energy Technology Laboratory;Randy Normann, Sandia NationalLaboratory; and Ed Mallison and

Bruce Ohme, Honeywell

High TemperatureElectronics—One Key toDeep Gas ResourcesLarge resources of unconventional gas are locked up in tight-gas sands, shales and coalbed methanethroughout the Gulf of Mexico, Rocky Mountains, Texas, Oklahoma and Appalachian Basin, but toobtain this resource, there are a number of hurdles to overcome.

Figure 1. An expanded view of natural gas resource base.


DEEP GAS

tools to drill and produce at elevatedtemperature environments.

Historical perspective on electronicsHistorically, electronic devicessuch as televisions, radios and eventhe first computers of the modernage used vacuum tubes, whichoperated well even at elevatedtemperatures. In fact, they neededa warm-up period to functionproperly. As the solid-state (SS) or semicon-ductor industry emerged, semiconductorsand integrated chips (ICs) replaced theseeffective but inefficient vacuum tubes, andthe age of microelectronics and miniaturiza-tion was born.

The products that used these ICs neededto be run at cooler temperatures. The firstsemiconductors ran so hot they destroyedthemselves. Thus, the SS devices neededcoolers or heat sinks instead of “heaters” likethe vacuum tubes. This is not a problem fortypical consumer devices operating at normaltemperatures. However, it does limit the abil-ity to apply electronic systems where there iscritical need for operations at elevated tem-peratures. The current need in the oil and gasindustry is to provide the sensors and devicesto effectively explore, drill, and produce oiland gas at elevated temperatures above 350°Fwithout coolers and thermal shields.

Typically, ICs are designed to perform reli-ably at temperatures up to 158°F for com-mercial grade electronics, 185°F for industrialgrade electronics and 257°F for militarygrade. Above those design limits, the charac-teristics for semiconductors change suffi-ciently so the circuit parameters will not bemet, or permanent changes may occur thatcause the circuit to fail.

Figure 2 shows a qualitative analysis of theeffect of temperature on the life of semicon-ductor components:

• the blue line is an attempt to relateexpected operating life of comm-

ercial/industrial grade electronics and isbased on “standard” metallization prac-tices of commercial/industrial electroniccomponents. Unfortunately, there is nooperating life requirement on commer-cial or industrial grade electronics;

• the green plot is for commercial/industrialcomponents being re-qualified and/orrepackaged.This is based on some knownproprietary data. The curve is generous asit gives a life expectancy of 1,000 hours at392°F and 5 years at 302°F, but it couldactually be lower (i.e. 400 hours at 391°Fand 3 years at 302°F); and

• the red curve is an estimate of silicon-on-insulator (SOI) technology. Therehas been some demonstration with thelimited SOI available (Honeywell com-ponents) that has established signifi-cant life expectancy even at HTs.

Two strong and evident observations arethat temperature has a dramatic effect on SSdevices, and SOI can increase longevity andreliability significantly at lower temperature.

Most oil and gas wells drilled today are belowthe 302°F limit of a typical semiconductor.However, drilling to deeper depths will need adifferent paradigm. HT electronics are neces-sary if LWD and MWD tools, logging toolsand even smart well applications are to be usedto any reliability.

Silicon-on-insulator technologyTransistor density and speed define the perfor-mance and cost of a digital device. A metal-

oxide semiconductor (MOS) transis-tor is an electronic switch and consistsof three basic elements: the source, thegate and the drain. Figure 3 is a sim-plified sketch of a MOS transistor.

The source and drain are regions ofsilicon that have been implanted witha small percentage of dopant atoms(such as boron or phosphorous) thatchange the conducting properties ofthe silicon. The silicon region bet-ween the source and drain is doped

with a species different from that used to dopethe source and drain. Doping adjacent regionsof silicon with different dopant species creates a“junction” that has an inherent electrostatic bar-rier to conduction.

The gate is between the source and drain ontop of a thin insulating (non-conducting) layerof silicon dioxide. When sufficient charge orvoltage is applied to the gate (referred to as the“threshold” voltage, VT) the electrostatic con-duction barrier is overcome, and a conductingchannel is established in the silicon regiondirectly beneath the gate. In this case, currentcan flow from the source to the drain throughthe silicon substrate when a charge or voltageis applied to the gate. Basically, when the gate-voltage is below the threshold voltage the sili-con substrate acts as a barrier to conduction.When the gate voltage is above the thresholdvoltage, the substrate acts as a conductorallowing current to flow. However, a smallamount of current can leak into the substrate(even at conventional temperatures) across theboundary between the source/drain and thesubstrate, which occurs regardless of the gatevoltage. As temperatures increase, the leakagecurrents rise dramatically.

Finally, it should be noted that the thresh-old voltage itself varies with temperature.Depending on the processing details (such asthe thickness of the insulator under the gateand the doping levels in the substrate) thethreshold voltage may go to zero at HT, mak-ing it difficult to use the gate terminal as ameans to control conduction.

Figure 2. A qualitative comparison of electronic componentoperating life.


DEEP GAS

Six typical basic effects occur in materialas temperature increases:

• electrical resistance of interconnectionmaterials and contacts increases;

• electrical resistance of insulating mate-rials decreases and charge leakageincreases;

• thermal conduction decreases for goodconductors;

• thermal conduction increases for poorconductors;

• thermal expansion coefficients in-crease; and

• chemical and metallurgical activity andinteractions within and between mate-rials increase.

Controlling these effects is essential forICs in devices needed to operate at HTs.Additionally, operating life and dependabilitycan be critical. Temperature is commonlyassociated with faster aging, shorter lifetimesand degraded reliability.

The junction current leakage between thesource or drain and the substrate is greatlyreduced by using SOI technologies. TheMOS transistors are isolated by a silicondioxide dielectric layer (Figure 4). SOI limitsappear at about 572°F where junction leakage

currents become prohibitive,though operations up to752°F have been reported.

Conventional semicon-ductor processes employedfor commercial electronicsare not capable to producecomponents that operate atHT or are reliable at HT.The upper limit of opera-tion for conventional silicondevices is about 392°F, andeven at these temperaturesthe operating life may bevery short (measured inweeks). Operation at highertemperatures (such as the600°F current projectedtemperatures of deep gas

resources) require different materials such asSOI, silicon on sapphire (SOS), silicon car-bide (SiC), gallium arsenic (GaAs), galliumnitride (GaN), diamond and so on.

GaN and diamond does not have the tech-nological maturity that silicon does and is dif-ficult to work with. GaAs offers only a slighttemperature advantage over SOI while lackingthe design flexibility of SOI. SOS technologyis limited by the cost of growing a layer of sil-icon on a single crystal of sapphire substrate.SiC is useful for power electronics and has theability to handle high voltage, high currentsand high temperatures. Power transistorsbecame commercially available in 2004.

The other materials have not had sufficientmarket draw or commercial devices devel-oped to justify process development. Thematerial selected depends on the temperaturerange and needed bandwidth. Even for HTSOI technology, the manufacturing of theintegrated chips or ICs is difficult, and only afew companies have the “foundry” capable ofmaking the high-quality HT SOI devices.This technology, though not highlyemployed, is well understood and can pro-duce well functioning devices to 572°F.

SOI and SiC are complementary technolo-

gies. SOI can be seen as the brains; takingmeasurements, processing data and then mak-ing decisions. While SiC provides the powerto turn the motor or open the valve.

SOI devices can be reliable, even at HTs.The major factors limiting the life of IC con-ductors and contacts operating at elevatedtemperatures are electromigration – thetransport of material caused by the gradualmovement of the ions caused by current flow,time and temperature – and corrosion accel-erated by the HTs.

Deep Trek HT electronics initiative To develop highly reliabile HT electronicproducts and technology that will enablesmart drilling at depths of 20,000ft and tem-peratures more than 392°F, the DOEthrough its gas program at NETL initiated a project to develop SOI technology for the oil and gas industry. HoneywellInternational Inc. Solid State ElectronicsCenter in Plymouth, Minn., formed a joint-industry-project ( JIP) to direct and providethe necessary cost share for the HT electron-ics project. The JIP will ensure this projectaddresses the most relevant set of systemspecifications and functionality primarily forthe oil and gas industry to develop the deepHT tools.

Three major service companies – BakerHughes, Halliburton Energy Services andSchlumberger – two smaller technologydevelopers/service companies – Quartzdyneand NOVATEK – one major oil and gasoperator (BP), and a large aerospace com-pany (Goodrich Corp. – Aerospace EngineSystems) co-fund the JIP with the DOE.

The DOE provides about $6 million andthe JIP members and Honeywell provide acost share of about $2.5 million. The projectbegan in October 2003 and will continuethrough December 2006. The project haschanged significantly since the initial proposalto DOE through the guidance of the JIPmembers to develop technically relevant and

Figure 3. A cross-section of typical metal-oxide-semi-conductor transistors on silicon substrate showing leak-age path that could occur at high temperature.

Figure 4. Cross-section of a metal-oxide-semiconductortransistor in a silicon-on-insulator technology.


DEEP GAS

purposeful products. More than 24 compo-nents initially were considered and prioritizedwith five fitting within the allocated budget:

• programmable memory electricallyerasable programmable read only mem-ory (EEPROM);

• pre-programmable (volatile) field pro-grammable gate array (FPGA);

• precision amplifier;• Sigma-Delta analog to digital converter

(18-bit); and• an electronic designer’s tool kit for creat-

ing custom “system-on-a-chip” SOI ICs.A state-of-the-art microprocessor was

considered, but the cost of intellectual prop-erty rights and subsequent upgrading to SOItechnology made it prohibitively expensivefor the current project. The system-on-a-chip capability allows engineers to mix ana-log and digital circuits in one SOI IC.Although this process is expensive (between$250, 000 and $350,000), the result is a smalland powerful application specific device.

Most notable in the above list is theplacement of a user-programmable non-volatile (holds data or program if power isinterrupted) memory product. The JIP part-ners have placed a high value on this com-ponent. A non-volatile user-programmablememory is required in a system that containsthe FPGA. User-programmable memoryalso is important to a system that uses amicroprocessor where non-volatile memoryis commonly used to store application-spe-cific instruction code. Finally, this type ofmemory is useful in any type of data-acqui-sition system where sensors are character-ized and sensor-specific calibration coeffi-cients are stored and employed to improvesystem accuracy.

Developing the programmable memory sig-nificantly affected the program. Non-volatilememory required integrating new steps and features into the wafer fabrication process. Asubstantial effort is required for device optimiza-tion, characterization and verification of HTperformance, and reliability devices operated in

fundamentally different ways than envisioned bythe original project. These changes involvecycles of wafer processing to characterize andoptimize the wafer fabrication flow. Finally, theEEPROM product should represent a relativelylarge portion of the integrated circuit design anddevelopment within the project. To include theprogrammable memory required that othertasks be revised and/or discontinued. In particu-lar, the microprocessor development is notaffordable and is discontinued. The cost of thestate-of-the-art HT SOI microprocessor devel-opment could be as much as one-third the totalproject budget (more than $2 million).

Another major change is that the FPGA,which was originally proposed for implemen-tation in 0.35-micron process, will instead beimplemented in the 0.8-micron process. Themajor impact of this change is a trade-offbetween nonrecurring development cost(which is decreased) and production cost(which is increased). The development cost isdecreased because this program does not fund wafer process development to renderHoneywell’s 0.35 micron process capable forHT use. The production cost is increasedbecause the 0.8 micron process is less densethan the 0.35 micron process, and therefore theresulting die will be larger and (presumably)more costly to produce. Using the 0.8-micronprocess also means the maximum operatingspeed (or clock rate) for the FPGA will belower than it would have been otherwise. Afurther change (also for the sake of includingthe programmable memory) is the eliminationof the hardware demonstration task. A majormotivation of this task was to demonstrate theapplication of the microprocessor, withoutwhich, the loss of this task is less significantthan it otherwise would have been.

Because the program requires a significantnumber of wafers be built to characterize andoptimize the process flow for EEPROMdevelopment, the number of wafers devotedto running final product designs is reduced.This means less material will be available tothe JIP members than would have been the

case without the EEPROM development.The FPGA in particular is impacted becausein a 0.8-micron flow, the die will be larger, andtherefore the number of die per wafer will beless to begin with. The quantity of FPGA dieproduced is not expected to exceed 150. Moredie could be provided for an additional cost.

Finally, adding the programmable memoryto the scope of this project represents a signifi-cant new area of development risk. Offsettingthis risk is the added reward that successfuldevelopment of this capability represents. TheHT SOI EEPROM memory chip has beenidentified by the JIP partners as an enablingtechnology. In recognition of the changed riskprofile, Honeywell has established that the pro-gram shall include several key “decision gates”at which time progress will be assessed and, ifnecessary, a determination may be made toadjust remaining program scope and direction.

The project is currently within acceptableschedule and within budget.

The components will have higher reliabil-ity at lower temperatures because the HTSOI’s designed for 5 years of life at 437°F.This long life provides reuse of tools andreconfigurations lower cost per tool.Members of the joint industry project haveexclusive market access until late 2007.

Related Deep Trek HTElectronics ProjectsThere are three additional projects currentlyfunded by DOE/FE/NETL/ONG to dev-elop HT downhole tools:

• wireless electromagnetic telemetry withE-Spectrum;

• research a 436°F MWD using SOItechnology; and

• a commercial innovative HT/HP MWDtool with Schlumberger technology. ✧

For more information, contact John Rogers,NETL project manager for natural gas supplydrilling, completion and stimulation projects at (304) 285-4880 or via email [email protected]


DRILLING FLUID

Many oil and gas reservoirs in theUnited States are mature andbecoming increasingly depleted of

hydrocarbons, which makes for more costlydrilling. While the formations above andbelow these producing zones typically havemuch higher pore pressures and require highfluid density to stabilize them, exposure of adepleted zone to this high-density fluid canresult in significant loss of drilling fluid anddifferential sticking. Uncontrollable drillingfluid losses are at times unavoidable in theoften-large fractures characteristic of theseformations. Furthermore, pressured shales

often are found interbedded with depletedsands, thus requiring stabilization of multi-ple pressure sequences with a single drillingfluid. Drilling such zones safely and inex-pensively is difficult with conventional rigequipment. Preventive measures with nor-mal- or high-density fluids generally entailuse of a low concentration of a pluggingagent in the circulating system or remedia-tion when the rate of loss of drilling fluidexceeds some threshold level. The latterrequires injection downhole of a pill – a 50-bbl to 100-bbl slug of fluid – that contains ahigh concentration of a plugging agent or a

settable/cross-linkable fluid. None of thesemeasures is completely satisfactory.

An increasingly popular alternative fordrilling depleted or multiple pressure zonesis the use of a fluid that has a density lowenough to balance the pore pressure in thelowest-pressure zone. However, this resultsin drilling the zones above and below thedepleted zone “underbalanced,” a conditionthat risks wellbore collapse and blowouts. Anew drilling fluid technology was developedrecently that does not entail drilling under-balanced, yet is designed to mitigate loss offluid and differential sticking. This novel

By Fred Growcock,MASI Technologies

LLCEnhanced Wellbore Stabilizationand Reservoir Productivity withAphron Drilling Fluid TechnologyLaboratory research is required to provide understanding and validation of aphron drilling fluid technol-ogy as a viable and cost-effective alternative to underbalanced drilling of depleted oil and gas reservoirs.

Figure 1. Aphrons can survive pressurization to at least 3,000 psig. Note that images b through d are magnified to 40x.

b)a)

e)d)

c)


DRILLING FLUID

technology is based, in part, on the use ofuniquely structured micro-bubbles of aircalled “aphrons.”

Because of concerns about corrosion andwell control, drillers generally discourageentrainment of air in drilling fluids; indeed,they often go to substantial lengths to elim-inate air altogether from drilling fluids.Consequently, the purposeful incorporationof air, as in aphron drilling fluids, is lookedon with some apprehension. Furthermore,there are no controlled studies that havebeen able to shed much light on the mecha-nism or the effectiveness of the aphrons atdownhole pressures. This project was devel-oped to provide the much-needed validationdata that would put such issues to rest,thereby leading to greater application ofaphron drilling fluid technology. Withwider use of aphron technology, clients willreduce their drilling costs significantly andbe able to pass some of those savings on toAmerican consumers.

MASI Technologies, funded in part by theU. S. Department of Energy’s Office of FossilEnergy, is carrying out a study with threeobjectives: develop a comprehensive under-standing of how aphrons behave at elevatedpressures and temperatures; measure the abil-ity of aphron drilling fluids to seal permeableand fractured formations under simulateddownhole conditions and establish how thefluids control fluid invasion with minimal for-mation damage; and determine the role playedby each component of the drilling fluid.

BackgroundAphron drilling fluids have been used suc-cessfully to drill depleted reservoirs andother low-pressure formations in a largenumber of wells, particularly in North andSouth America. These novel fluids have twochief attributes that serve to minimize fluidinvasion and damage of producing forma-tions. First, the base fluid is very shear thin-ning and exhibits an extraordinarily highlow-shear-rate viscosity; the unique viscosity

profile is thought to reduce the flow rate ofthe fluid dramatically upon entering a losszone. Second, very tough and flexible micro-bubbles are incorporated into the bulk fluidwith conventional drilling fluid mixingequipment. These highly stabilized bubblesor aphrons are essential to sealing the prob-lem area and are thought to form a sealwithin the permeable or fractured formation.

Aphrons are made of a spherical gas core anda protective outer shell. Contrasting with aconventional air bubble, which is stabilizedby a surfactant monolayer, the outer shell ofthe aphron is thought to consist of a muchmore robust surfactant tri-layer. This tri-layeris envisioned as consisting of an inner surfac-tant film enveloped by a viscous water layer;overlaying this is a bi-layer of surfactants

Figure 2. Large aphrons survive pressurization from 500 psig to 2,000 psig, but smalleraphrons (50 µm to 100 µm) do not.

Figure 3. Oxygen in aphron drilling fluids depletes rapidly.


DRILLING FLUID

that provides rigidityand low permeability tothe structure whileimparting some hydro-philic character to it.Under quiescent condi-tions, the structure iscompatible with theaqueous bulk fluid; how-ever, it is thought thatwhen enough shear orcompression is appliedto the aphron, for exam-ple, when bridginga pore network, theaphron may shed its outermost shell layer,rendering the bubblehydrophobic.

Aphrons are claimedto act as a unique bridg-ing material, forming amicro-environment in apore network or fracture that appears tobehave in some ways like foam and in otherways like a solid, yet flexible, bridging mate-rial. As is the case with any bridging mater-ial, concentration and size of the aphrons arecritical to the drilling fluid’s ability to sealthief zones. Drilling fluid aphrons have coresof air and are constructed by entraining air inthe bulk fluid with standard drilling fluidmixing equipment; this reduces the safetyconcerns and costs associated with high-pressure hoses and compressors commonlyutilized in underbalanced air or foamdrilling. Although each application is cus-tomized to the individual operator’s needs,the drilling fluid system is generally designedto contain between 12 vol % and 15 vol % airat the surface (ambiant temperature andpressure), and the aphrons generated arethought to be sized or polished at the drillbitto less than 200 µm diameter, which is typi-cal of many bridging materials.

The project is divided into two phases.Phase I (year 1) dealt with developing evi-

dence for the ways in which aphrons behavedifferently from ordinary surfactant-stabi-lized bubbles, particularly how they seal per-meable and micro-fractured formations dur-ing drilling operations. Various methodswere evaluated for characterizing the proper-ties of aphrons, including acoustic bubblespectrometry, optical and electronic micro-imaging and interfacial tension. Key proper-ties investigated included the effects of pres-sure on bubble size, the influence of environ-mental parameters on aphron stability, theaffinity of aphrons for each other and themineral surfaces in rock pores and micro-fractures, and the nature of aphron seals inpermeable and micro-fractured rock. Initialsealing and formation damage tests were car-ried out, using lab-scale apparati designed tosimulate permeable and micro-fracturedenvironments. Phase II (year 2) is focusingon optimization of the structure of aphronsand composition of aphron drilling fluids,quantifying the flow properties of the fluids(radial vs. linear flow, shear and extensional

viscosity effects and bubblyflow phenomena), and und-erstanding formation sealingand damage under simulateddownhole conditions (inc-luding scale-up tests), so asto furnish irrefutable evi-dence for this technology andprovide field-usable data.

Much of the scenariodescribed above about therole of aphrons in reducingfluid losses downhole is con-jecture that has not beenconfirmed under stringentlaboratory conditions. Fur-thermore, the overall mannerin which the drilling fluid isable to reduce fluid lossesdownhole has been broughtinto question. As a result,there has been considerableresistance in some places to

acceptance of the technology.

Aphron propertiesIn contrast to conventional bubbles, whichdo not survive long past a few hundred psi,aphrons have been found to survive com-pression to at least 27.3 MPa (4,000 psig)for significant periods of time. When afluid containing bubbles is subjected to asudden increase in pressure above a fewhundred psi, the bubbles initially shrink inaccordance with the modified Ideal GasLaw. Aphrons are no exception. However,conventional bubbles begin to lose airrapidly via diffusion through the bubblemembrane, and the air dissolves in the sur-rounding aqueous medium. Aphrons alsolose air, but they do so very slowly, shrink-ing at a rate that depends on fluid composi-tion, bubble size, and rate of pressurizationand depressurization.

Compression will reduce a bubble of 200-µm diameter at atmospheric pressure to 76µm when subjected to a pressure of 250 psig,

Figure 4. Aphrons undergo bubbly flow during displacement of water from20/40 sand pack by an aphron drilling fluid. Note that the fluid front (at thefluid/water interface) is predominantly aphrons (white).

Close Up


DRILLING FLUID

and 36 µm at 2,500 psig. But the biggesteffect of pressure by far on the fate of a bub-ble is increased gas solubility. Henry’s Lawstates that the solubility of a gas is roughlyproportional to the pressure. When a fluidcontaining 15% v/v entrained air at ambientpressure is compressed to just 250 psig, all ofthe air becomes soluble. If the stabilizingmembrane surrounding the bubble is perme-able, the air will diffuse into the surroundingmedium and go into solution. This is whathappens with ordinary bubbles, and it occurswithin a matter of seconds after compres-sion. Aphrons have a much less permeablemembrane, so they do not lose their air asreadily; indeed, when subjected to a pressureof 250 psig, air is prevented almost indefi-nitely from diffusing out of the aphrons andinto the aqueous medium.

Aphrons will survive compression anddecompression for short periods of time. Asshown in Figure 1, rapid compression of anaphron drilling fluid from 0 psig to 3,000 psigfollowed by decompression back to 0 psigresults in essentially full regeneration of theaphrons. Large aphrons appear to be able tosurvive better than small aphrons. Figure 2shows the effect of the size of an aphron on itssurvivability. Aphrons of different sizes arepressurized from 500 psig to 2,000 psig insteps of 500psi every 10 seconds. Aphronslarger than 200 µm diameter decrease in sizewith increasing pressure as expected byBoyle’s Law (modified Ideal Gas Law); thesmall deviation from Boyle’s Law is because of

loss of air via slow diffusion into the sur-rounding fluid. When aphrons reach a criticalminimum size (50 µm to 100 µm diameter),they undergo a structural change that leads totheir rapid demise, with the expelled air againdissolving in the surrounding fluid. Upondecompression to a pressure sufficiently lowfor the aqueous medium to become supersat-urated with air, the air is released; most of theair goes into existing aphrons, though it mayalso create new aphrons.

Another important finding is that the oxy-gen in aphrons – even the oxygen dissolvedin the base fluid – is lost via chemical reac-tion with various components in the fluid, aprocess that usually takes minutes and resultsin nitrogen-filled aphrons. Thus, corrosionof tubulars and other hardware by aphrons isnegligible. Figure 3 shows that even at ambi-ent temperature and pressure, the oxygen insolution in an aphron drilling fluid disap-pears within hours after preparing the fluid.By contrast, in a typical clay-based or poly-mer-based fluid, the concentration of oxygenin solution remains relatively constant.

Fluid dynamicsThe base fluid in aphron drilling fluids yieldsa significantly larger pressure loss (or, for afixed pressure drop, lower flow rate) in longconduits than any conventional high-viscos-ity drilling fluid. Similarly, if flow isrestricted or stopped, aphron drilling fluids(at a fixed wellbore pressure) generate signif-icantly lower downstream pressures than do

other drilling fluids. In permeable sands, thesame phenomena are evident. In addition, inpermeable sands of moderate permeability(up to at least 8 Darcy) and low pressures,aphrons themselves slow the rate of fluidinvasion and increase the pressure dropacross the sands. Lastly, and most impor-tantly, aphrons move more rapidly throughthe sands than the base fluid. Figure 4 showsa transparent version of an aphron drillingfluid (dyed blue) displacing water from a bedof 20/40 sand under the influence of a 100-psi pressure gradient. The drilling fluid frontis populated with a high concentration ofbubbles that turn the fluid nearly white. Thisphenomenon, called “bubbly flow,” appearsto follow conventional Navier-Stokes theory.High-density particles such as barite (a den-sifying material) or drilled cuttings tend tobe left behind the base fluid. Low-densityinternal phases, such as bubbles, flow morerapidly than the base fluid. For a rigid spherein a fluid under the influence of a one-dimensional pressure gradient, ∆P/L, therelative velocity of the bubble in an infinitelywide conduit is:

V = 0.23 r 2 /η * ∆P/L

where r is the bubble radius and η is the fluidviscosity. For flow through permeable media,the expression is modified to incorporateDarcy flow.

Wettability tests indicate aphrons havevery little affinity for each other or for the

Figure 5. In time, conjoined aphrons separate and show little affinity for each other.


DRILLING FLUID

mineral surfaces in rock formations encoun-tered during drilling. This is demonstratedin Figure 5, which shows bubbles purposelyjoined by creating them via air injection.The bond between the bubbles is thought tobe the result of imperfect development ofthe aphron shell. Within a few seconds, thebubbles separate from each other, ratherthan coalesce. This lack of affinity of bub-bles for one another and for silica and lime-stone surfaces does not result from sheddingsurfactant layers, as was thought before, butis an intrinsic characteristic of the wholeaphron structure. Thus, aphrons resistagglomeration and coalescence and areexpected to be pushed back out of a perme-able formation easily by reversing the pres-sure differential, thus minimizing formationdamage and cleanup.

Finally, leak-off tests demonstrate thataphron drilling fluids are capable of sealingrock as permeable as 80 Darcy. Figure 6shows test results in synthetic Aloxite coresof 0.75 Darcy to 10 Darcy permeability. Thebase fluid in aphron drilling fluids is primar-ily responsible for slowing or stopping theinvasion, but properly designed aphrons canreduce these losses even further.

Future effortsPhase II of this project is continuing with astudy of the effects of individual componentsin the fluid on the properties of aphrons; adetailed investigation of the surface chem-istry involved in the interactions of thedrilling fluid with reservoir rock and pro-duced fluids; visualization of the flow ofaphron drilling fluids in a wellbore/reservoirsimulator; and extension of the fluid flowmodel to include bubbly flow. ✧

AcknowledgementsThis project is partially funded by the U. S.Department of Energy’s (DOE) Office of FossilEnergy, National Energy Technology Labor-atory contract DE-FC26-03NT42000. TheAphron Technology Team of MASI Technologies

LLC responsible for gathering the data reportedhere consists of Arkadiy Belkin, MirandaFosdick, Tatiana Hoff, Maribella Irving andBob O’Connor; my sincerest gratitude to all ofthem. I thank Gary Covatch, the DOE projectmanager, for his guidance throughout the courseof this project, and John Rogers of the DOE forhis advice and valuable and informative discus-sions. In addition, many thanks to the followingindividuals for their continuing contributions:Tony Rea and Tom Brookey of MASITechnologies LLC for their essential advice anddirection; Dr. Peter Popov of Texas A&MUniversity for the all-important bubbly flowmodelling work; George McMennamy of M-ISwaco for some critical analytical work on thecomposition of aphron drilling fluids, and Dr.Ergun Kuru and his team at the University ofAlberta, who are carrying out some surfacechemistry work in parallel with our own effort.

References1. Montilva, J., Ivan, C.D., Friedheim, J. andBayter, R., Aphron Drilling Fluid: FieldLessons From Successful Application inDrilling Depleted Reservoirs in Lake

Maracaibo, OTC 14278, presented at the 2002Offshore Technology Conference, Houston, May6-9, 2002.2. Growcock, F.B., Simon, G.A., Rea, A.B.,Leonard, R.S., Noello, E. and Castellan, R.,Alternative Aphron-Based Drilling Fluid,IADC/SPE 87134, presented at the 2004IADC/SPE Drilling Conference, Dallas,March 2-4, 2004.3. Brookey, T., Rea, A. and Roe, T., UBD andBeyond: Aphron Drilling Fluids for DepletedZones, presented at IADC World DrillingConference, Vienna, Austria, June 25-26, 2003.4. Growcock, F.B., Simon, G.A., Guzman, J.,and Paiuk, B., Applications of Novel AphronDrilling Fluids, AADE-04-DF-HO-18, pre-sented at the AADE 2004 Drilling FluidsConference, Houston, TX, April 6-7, 2004.5. Sebba, F., Foams and Biliquid Foams –Aphrons, John Wiley & Sons Ltd, Chichester,1987.6. White, C.C., Chesters, A.P., Ivan, C.D.,Maikranz, S. and Nouris, R., Aphron-BasedDrilling Fluid: Novel Technology for DrillingDepleted Formations, World Oil, Vol. 224, No.10, October 2003.

Figure 6. Static linear leak-off tests of aphron drilling fluids in permeable Aloxite coresdemonstrate the sealing performance of the fluids and the role played by aphrons (air).


LASER TECHNOLOGY

For the past 8 years, Gas TechnologyInstitute (GTI) and its research part-ners have investigated the applica-

tion of high-power laser energy for wellconstruction and completion. Initial inves-tigations were performed with larger mili-tary lasers to qualitatively demonstratetheir feasibility for well construction.Additional work followed with less power-ful, yet more practical and commerciallyavailable industrial lasers to determinerock-breaking energy requirements. In itsmost recent research, GTI advanced itsdownhole application research focusing onperforations using the most recent evolu-tion of high-power lasers – a 5.34-kWytterbium-doped multiclad fiber laser. Theinvestigation has produced promisingapplication results as well as an extensivetesting of the most likely laser device to bedeployed at a well site.

Early thoughts on laser applicationsSince the earliest practical demonstration oflasers, the petroleum industry has recognizedthem as a potential alternative to, or meansto assist, conventional mechanical methodsof reaching and producing petroleumreserves. Many logical designs and methodswere conceived and patented for subsurfacelaser applications that might offer revolu-tionary improvements in penetration ratesand efficiency.

Laser technology, however, proved inade-quate and impractical when first demon-

strated. Lasers at the time were expensiveand had limited practical applications,located primarily in academic and militarysettings. The lasers of the time had excessivepower requirements, were large in size, andexperienced poor reliability and frequentmaintenance. Although technical progressand applications were expanding, limitedenergy transmission to subsurface targetsand overall energy conversion inefficienciestabled any real thoughts for applications inthe petroleum industry.

By the late 1990s, laser technology hadmatured considerably when GTI and itspartners investigated military and industriallasers applications, only to dispel many of theoil and gas industry’s previously held beliefs.With more technically advanced laser sys-tems and the ability to better control beamapplication, it was shown that lasers werecapable of breaking any lithology. Efficientrock removal methods of spallation and cal-cination were investigated, while avoidingmore energy intensive methods of meltingand vaporization.

Examination of post-lased rock propertiesyielded additional observations that sup-ported laser application methods, particu-larly as part of a non-explosive perforationsprocedure. It was found that the transfer ofthermal energy to the rock produced stimu-lation effects to fluid flow characteristicswhile rock was being removed. In Bereasandstone applications, porosity increasedbetween 50% and 150%, and permeabilityincreased 22% in the rock tunnel and sur-

rounding areas. In addition, thermal energyweakened the overall strength of the rock inand around the excavated tunnel.

Key technical breakthrough in designHistorically, low-power versions of fiberlasers were used as optical signal amplifiersin the telecommunications industry. High-power configurations theoretically wereachievable and only commercially realized in2001. Since the design was scalable, fiberlasers were available with output powersnearing 10 kW within a year.

The principle behind the fiber laser is aninternalization of the process that createsphotonic emissions. In a fiber laser, pho-tonic emissions are created in a doped silica“active” fiber using individually connecteddiodes, resulting in an efficient, compactlaser source with exceptional beam quality.In other lasers, this process takes place in aseparate resonance chamber energized byflash lamps or diodes. Laser emissions mustthen be channeled from the resonancechamber into an optical fiber or directlyapplied. Most industrial lasers are fiber connectable, although carbon dioxide(CO2) laser emissions must be applied in adirect line of sight or through reflectiveoptical tubes.

The unique design of the fiber laser allowsa number of significant advantages overother industrial lasers. Together, theseadvantages have accelerated the practicalapplication of high-power lasers for remote

By Brian C. Gahan, P. E.,Gas Technology InstituteFiber Laser Offers Fast

Track to Clean PerforationsTraditional methods of completing a cased hole include perforating with explosives, creating a tunnel toallow production of reservoir fluids to the surface. Although methods have been devised throughout theyears to optimize this completion process, significant damage to the reservoir is typically created with acorresponding restriction to fluid flow. In addition to this damage are concerns of safety and security.


LASER TECHNOLOGY

applications, including wellperforations and other wellconstruction and completionmethods. Notable improve-ments include: energy con-version, or wall plug efficien-cies about 20%; the footprintof the 5.34-kW ytterbiumfiber laser is 5.4 sq ft; andmean time to failure in excessof 50,000 hours of continu-ous operations.

The high wall plug effi-ciency of the fiber laser sig-nificantly reduces the req-uired input energy comparedwith other industrial lasersgenerating the same outputpower. Assuming identical application con-ditions, a typical lamp-pumped Nd:YAGlaser would require as much as 200 kW ofelectrical power compared with about 25kW for an ytterbium fiber laser to send 4kW of laser energy to a target (Figure 1).This represents 87.5% less input energy for the fiber laser to achieve the same out-put power. Less input energy results in areduction of on-site electrical generationequipment and a reduction in coolingrequirements for energy lost through ther-mal dissipation.

Perforating with fiber lasers Given the advantages of fiber lasers overother high-power lasers, and the observedimprovements they create in the fluid flowcharacteristics of rock, GTI performed ademonstration to further explore the practi-cal application of fiber lasers for wellboreperforations.

Many of the previous experiments wereperformed using high-power lasers on Bereasandstone as it is well described in the liter-ature as clean and relatively homogeneous inits physical properties with good fluid flowcharacteristics. Berea sandstone also hasbecome the accepted standard for laboratory

investigations of porous, permeable rock. A1-ft cube of Berea sandstone was chosen todetermine the ability of the fiber laser beamto tunnel through the block, the resultingenergy requirement and resulting changes torock properties. Since the influence of ther-mal energy on Berea previously was docu-mented, we examined only permeability asan indicator of the extent of any changes inphysical properties.

Previous laboratory experiments haveobserved laser/rock interactions of single ormultiple beam bursts of several laser types onvarious lithologies with up to 4-in. x 6-in.length cylindrical core samples. The deepestpenetrations recorded to date for a Bereasandstone was a 1-in. x 31⁄4-in. deep hole,created by a 6-kW CO2 laser with a defo-cused, conical beam shape.

Specific energy (SE) was used to quan-tify the energy required to remove a unitamount of rock (kJ/cc). In previous experi-ments, optimal SE observations in Bereawere determined using half-second beamexposures. The lowest recorded observa-tions of SE in Berea under these con-trolled, optimized single shot conditionsranged from 4.3 kJ/cc to 5.2 kJ/cc. Latertests involving multiple shots were

designed to layer singleshots upon one anotherresulting in larger, deeperholes in Berea samples(about 1-in. in diameter and1-in. deep) with SE valuesranging from 9.2 kJ/cc to 13kJ/cc.

The low values of SE wereachieved by avoiding sec-ondary effects, defined asprocesses that consume laserenergy for purposes otherthan breaking the rock. Mostof the secondary effects thatoccur in laser/rock interac-tions, including mineral melt,were avoided through limit-

ing temperature accumulation in the exposedtunnel matrix and cuttings. As quartz is thedominate mineral in Berea (about 85%),melting occurs at temperatures greater than2,700°F. Once mineral melt occurs, any addi-tional energy the beam applies to the rockserves to increase the temperature of themelt rather than spallating the rock.

Altering the rate of energy transferred tothe rock face while simultaneously reducingbeam exposure to the cuttings as they exitthe hole can control temperature accumula-tion in the rock. Energy transfer rates can becontrolled easily through methods thatinclude altering the average measured powerapplied, changing the power density(power/area) of the application or limitingthe exposure time on a given area. Optimalbeam power level and density were indepen-dently determined for fiber laser applicationsto Berea.

Cuttings removal is important in avoidingthermal accumulation. This becomes moreapparent the deeper a hole is drilled.Experimental observations identified meth-ods of creating a hole with a diameter largerthan that of the applied beam. This wasaccomplished by moving the beam in arepetitive geometric pattern that allowed a

Figure 1. Comparison of required energy required of lamp-pumpedNd:YAG (LP:YAG), diode-pumped Nd:YAG (DP:YAG), carbon dioxide(CO2 ) and high-power fiber laser (HPFL) to generate a 4-kW beam.


LASER TECHNOLOGY

greater percentage of cuttings to exit the holewith limited or no exposure to the beam.

Tunneling through the targetThe laser used for this demonstration was a5.34-kW ytterbium-doped multiclad fiberlaser with an emission wavelength of 1.07microns (Figure 2), capable of generatingcontinuous or pulsed beams. Although largerfiber lasers have been built, this is the largestavailable for research in the United States.Other major elements of the laser systemincluded a tri-axial robotic arm mounted ona vibration free optical table, a gas purgenozzle, a fume extractor and beam dump. Inaddition, a beam collimator mounted on therobotic arm was used to convert the raw laserbeam from the fiber into a collimated beam1-in. in diameter. The robotic arm was pro-grammed to move the beam in a circularmotion 2-in. in diameter at 22.6 rpm.

A purge gas consisting of compressed airat 75 psig was directed through a stainlesssteel nozzle with a quarter-in. outlet diame-ter and maintained at about 1-in. from thetarget block by continuously moving it for-ward as the hole deepened.

The target block of Berea sandstone mea-suring 12-in. on each side was exposed to thebeam for a total of 6 minutes. Permeabilitymeasurements were taken prior to beamexposure for later comparison to those takenafter. Measurements were taken using a pres-sure-decay profile permeameter at intersec-tions of a 1-in. grid system.

The beam was applied continuously at 1-minute intervals to avoid thermal accumula-tion. Laser power was maintained at an opti-mal level found in previous studies for thisrock type (3.2 kW). When the beam pene-trated half the length of the block, it wasturned such that the beam could penetratefrom the opposite direction and meet theexisting tunnel in the block’s center. Thisprocedure was performed to reduce theinfluence of boundary effects and better sim-ulate an infinite reservoir rock. Boundary

effects had been observed as design artifactsof past experiments: as the beam approachedrock sample edges, thermal diffusion charac-teristics are altered, regardless of the sample’sphysical dimensions.

Demonstration results The resulting hole created in this demon-

stration passed through the full 12-in. lengthof the sample. The tunnel diameter wasabout 2-in. at the entry points on either faceand 1.1-in. at the center of the block (Figure3). Although a collimated beam was usedand a uniform diameter hole was expected,the laser head assembly and purge nozzlewere moved forward nonlinearly betweenlaser applications.

An SE value for creating the entire tun-nel was determined to be 5.5 kJ/cc. Thisrepresents one of the lowest valuesobserved for a tunnel created by any lasersource previously investigated. In addition,it was obtained while creating the deepesttunnel in Berea to date. This was achiev-able by limiting temperature accumulationand avoiding phase change of the rockminerals. Also notablein their contributionswere the novel purgingsystem that maximizedejection of cuttings fromthe hole and the appliedcircular motion of thebeam that minimizedcuttings exposure to thebeam prior to ejectionwhile limiting continu-ous beam exposure tothe tunnel walls.

Comparisons of pre-and post-lased perm-eability measurementsalong the lased rock faceperpendicular to thedirection of the beamwere inconclusive, as thedeformation zone ext-

Figure 2. A 5.34-kW ytterbium-dopedmulticlad fiber laser with an emissionwavelength of 1.07 microns.

Figure 3. A cross-section of lased tunnel 12-in. across mea-suring 2-in. diameter on each end. The inset is a micrographshowing no evidence of melt and some discoloration.


LASER TECHNOLOGY

ended only one-sixteenth-in.radially into the rock from thetunnel wall. This indicated, alongwith the observed SE value, thatmuch of the energy directed atthe sample was used to spallatethe rock, and not to thermallyalter near-tunnel rock properties.A similar comparison was madealong the bisected length of thetunnel. There was no evidence ofmineral melt on the tunnel wall.Post-lased permeability readingsranged from 100 mD (low) to300 mD (high) with a pattern ofhighest permeability readingscorrelating with the tunnel. Thisrepresented permeability inc-reases in the wellbore of between15% and 30%. Although thisenhancement is produced onlywithin one-sixteenth-in. of the tunnelwalls, we observed that the process of lasingperforation tunnels is at worst a non-dam-aging application (Figure 4).

ConclusionsThe commercial introduction of high-powerfiber lasers beginning in 2002 represented asignificant step forward in realizing field-based applications of photonic energy forwell construction and completion. Fiberlasers meet the multiple demands fromindustry regarding a field deployable system,including overall size limitations, mobilerugged on-site deployment, requisite energydelivery to target, real-time controllabilityand penetration of multiple materials.

From an economic perspective, the orderof magnitude improvement in efficiency sig-nificantly lowers input energy and waste heatdissipation requirements. They also requireminimal maintenance and repair, and arecommercially available.

The application of GTI’s 5.34-kW fiberlaser to a 1-ft cubic block of Berea sandstonesuccessfully demonstrated the most recent

breakthrough in industrial laser technology.The demonstration provided a minimalvalue of SE when compared with previouslaser/rock interaction tests, and yet wasachieved while creating the deepest tunnel todate. This was made possible, in part, byeffectively removing cuttings to avoid energylosses through thermal accumulations in the matrix and the cuttings. Additionally,boundary effects were minimized by using atarget with a greater mass than found incylindrical cores, and by opening the tunnelfrom both sides to meet in the center.

Evaluation of changes to rock propertiesproved that low power applications will cre-ate a narrower thermal deformation zonethan megawatt military lasers. The deforma-tion zone extends from the tunnel face radi-ally into the rock; however the resultingimpact on fluid flow enhancement is unde-termined.

The importance of removing rock cuttingswas again demonstrated, by means of creat-ing tunnel diameters larger than beam diam-eters, and continually pushing gas purge linesinto the deepening hole.

During the past 2 years, com-mercially available fiber lasershave increased in power from sev-eral watts to kilowatts. They arenow capable of efficiently deliver-ing requisite power via fiber opticsto targets downhole, and haverapidly evolved into the leadingcandidate for on-site applicationsin well construction and comple-tion. Their use as an alternativemethod to conventional explosivecharges could reduce or eliminateperforation damage and signifi-cantly boost production rates,cumulative production and overalleconomic returns. ✧

References1. Parker, R.A., Gahan, B.C., Graves,R.M., Batarseh, S., Xu, Z., Reed,

C.B., Laser Drilling: Effects of BeamApplication Methods on Improving RockRemoval, SPE 84353, 2003.2. Batarseh, S., Gahan, B.C., Graves, R.M.,Parker, R.A., Well Perforation Using High-Power Lasers, SPE 84418, 2003.3. Gahan, B.C., Shiner, B., New High-PowerFiber Laser Enables Cutting-Edge Research,GasTIPS, 10, 29.4. Graves, R.M., Araya, A., Gahan, B.C., Parker,R.A., Comparison of Specific Energy BetweenDrilling With High Power Lasers and OtherDrilling Methods, SPE 77627, 2002.5. Graves, R.M., Batarseh, S., Parker, R.A.,Gahan, B.C., Temperature Induced by High Power Lasers: Effects on ReservoirRock Strength and Mechanical Properties,SPE/ISRM 78154, 2002.6. Xu, Z., et al. 2003. Application of HighPowered Lasers to Drilling and CompletingDeep Wells,” Topical Report ANL/TD/TM03-02, DOE/NGOTP Contract Number 490667. Batarseh, S.I., Gahan, B.C., Sharma, B.C.,Deep Hole Penetration of Rock for OilProduction Using Ytterbium Fiber Laser,SPIE 5448-98, 2004.

Figure 4. A two-dimension permeability map overlaying a pho-tograph of tunnel cross-section.


ECONOMIC IMPACT

T he incentives costs andbenefits were measured interms of changes in nat-

ural gas and oil production, anddirect federal and state revenues.A decline curve analysis and eco-nomic evaluation was conductedon 16,515 federal properties con-taining more than 62,000 produc-ing wells on leases managed bythe Bureau of Land Management(BLM). The analyses were basedon monthly historical productionfrom 1990 to 2003.

In 2002, the BLM formed theBLM incentives team to conduct areview of existing incentives fornatural gas and oil production, andrecommend changes or new incen-tives that would promote federallands production at a reasonablecost to the federal treasury. Theincentives team membership inc-luded: BLM representation fromheadquarters and field offices; theU.S. Minerals Management Ser-vice (MMS); the Department ofEnergy’s (DOE) Office of Fossil Energy andthe National Energy Technology Laboratory(NETL); and representatives from NewMexico, Wyoming and Oklahoma.

The NETL Strategic Center for NaturalGas and Oil maintains, operates and utilizes areservoir level analytical system for evaluation

of programmatic and policy decisions in sup-port of its gas and oil programs. The system isused to set research and development priorities;evaluate technology feasibility; justify programelements; and estimate benefits of various poli-cies, environmental, and other regulatory ini-tiatives for the DOE and other agencies.

Evaluating incentivesThe team initially considered morethan 20 different incentives. The incen-tives reported here target existing pro-duction and extending reservoir life –the so-called “safety net study.” Theincentives team determined that anysafety net system would have a produc-tion rate and price requirement.

Incentive goals—One goal was to cre-ate a safety net to avoid premature pro-ducing well abandonment during lowproduct prices. The incentive is to beused when necessary to keep wells onproduction. The incentive rules alsomust be simple to administer for royaltyrelief reduction or increase.

Design considerations—Several con-siderations were given to the safety netincentive design. The primary focus wasto balance two often-competing goals:• incentive must be targeted so it is

only provided to producing proper-ties that need it to remain on pro-duction; and

• incentive must be reasonable forthe BLM, the MMS and industryto administer.

It was decided that low prices and low pro-duction rates are required to trigger the incen-tive. This avoids granting the incentive to aproperty during a low production rate periodand then having the production rate increasesignificantly with the incentive still active. If the

By Betty Felber, National Energy Technology Laboratory,

U.S. Department of EnergySafety Net Royalty ReliefAnalysis of Natural Gas andOil Production and Revenues The U. S Department of Energy’s National Energy Technology Laboratory has completed work onbehalf of the Bureau of Land Management that evaluates potential impacts of tax and royalty incen-tives and the trade-offs of these incentives on future production from federal and Native American gasand oil leases during the next 20 years.

Figure 2. States included in the studies

Figure 1. Federal lands locations


ECONOMIC IMPACT

production rate or price trigger is exceeded, theincentive will not be allowed for that property.

Incentive starting criteria—The productprices where royalty relief incentives are ini-tiated were identified. These incentives weretied to published prices of West TexasIntermediate (WTI) crude for oil and HenryHub natural gas prices. There also is a timerequirement to make the incentive effective,which is when the average monthly WTIprice falls below a threshold for three con-secutive months (four consecutive months inthe Energy Bill case) or when the averagemonthly Henry Hub price falls below athreshold price for the same period.

Either price condition can be met for thisincentive to be effective. It is possible tohave the incentive effective for oil, naturalgas or both. There is also a rate qualifica-tion – 15 boe/d – or each property. This rate

follows a similar qualifica-tion time period.

Incentive removal crite-ria—Once the incentive hasbeen granted, there must beclearly defined price, pro-duction and time parametersrequired to remove theincentive. These match thestarting criteria of price andrate qualification. The inc-entive will be removed whenthe average monthly WTI orHenry Hub price is greaterthan the threshold price for

three consecutive months. The barrel-of-oil-equivalent rate qualification will follow thesame pattern. Three months of high rate willremove the property from the incentive.If the incentive is the Energy Bill, the timeperiod is 4 months instead of 3. When the incentive is removed (because of rate orprices) the incentive starting criteria mustagain be met to reinstate the incentive. Inthese analyses, threshold prices were notadjusted for inflation.

Importance of analyses Federal lands produce one-third of thenation’s gas and one-fifth of its oil. The fed-eral lands locations are shown in Figure 1,and the states included are shown in Figure 2.

Data—Data was derived from a variety ofsources including, the MMS-MineralRevenues Division, the BLM and the state

of Wyoming. The primary data source wasthe MMS Oil and Gas Operations Report(OGOR) data system. The MMS MineralRevenue Division provided monthly detailedOGOR data on a well-by-well basis for allonshore federal and Native American landsfrom January 1990 to December 2003. Thisdata was used to populate the databaserequired to run the analytical model.

Data processing—The data processedincluded the lease and agreement number,gas and oil production, depth, primary prod-uct, state and county, lease well counts, dayson production, water injection or steaminjection, BTU content, American Petrol-eum Institute gravity, number of completionsper well, percent of federal lease, percent ofprivate lease and effective royalty. All 16,515leases were tagged for current stripper, heavyoil and multi-rate royalty relief configura-tions. The production for each well wasaccumulated to the lease level.

The gas and oil operating costs wereupdated through December 2002. The dataused was the annual operating cost ($/well).The data provided consists of regional para-meters needed to define equations for certaindepth dependent gas and oil fixed operatingcost equations. Also included are regionalvalues for variable operating costs (based onvolume of production) and regional values forG & A costs. The operating costs also tookinto account the number of completions ineach wellbore. Multiple completions had dif-fering operating costs from single ones. Foroil leases, these costs also included the pri-mary production operating cost plus thepump operating cost or secondary operatingcost for waterflood or steamflood leases.

Safety net royalty relief modeling systemThe system used to model the proposedsafety net royalty relief scenarios consists oftwo FORTRAN modules designed specifi-cally for this application. The first model per-forms a hyperbolic decline on historical

Figure 3. Current royalty rates

Oil Price($/bbl)

Gas Price($/Mcf)

Constant12.5%Royalty

CurrentRoyalty

StructureEnergy Bill

Energy Billwith Injection

35.00 4.67 ✓ ✓

20.00 2.67 ✓ ✓ ✓ ✓

18.00 2.40 ✓ ✓ ✓ ✓

16.00 2.13 ✓ ✓ ✓ ✓

15.00 2.00 ✓ ✓ ✓ ✓

13.00 1.73 ✓ ✓ ✓ ✓

11.00 1.47 ✓ ✓ ✓ ✓

Figure 4. Example analysis conducted


ECONOMIC IMPACT

production for the major product (gas or oil)of the lease/agreement being evaluated andproduces a 20-year monthly production pre-diction. The second model performs a cashflow analysis to determine the economic limitunder various price and cost structures. Thismodel has coded into it the series of differentroyalty relief scenarios proposed by the BLMincentives team as well as the current royaltyrates by product. Figure 3 shows the distrib-ution of current royalty rates as of 2003.

For each lease/agreement the economicevaluation model does a monthly cash flowanalysis. Included in this analysis are calcu-lating gross revenue, royalty payments basedon the royalty structure, state productiontaxes based on individual state rates and netrevenue. The monthly operating cost basedon the product, number and depth of wells,fluid production and region in which thelease exists also is calculated. Operating costsare subtracted to calculate income, whichdetermines whether the lease economic limithas been reached. This calculation deter-mines when the lease will be shut-in andwhen it will be abandoned. As part of deter-mining the economic limit, the model calcu-lates royalty payments and severance taxespaid. This allows comparison between pro-duction and royalty payments for differingassumptions of future product prices, operat-ing costs and royalty schemes. A separatemodel run must be made for each price, costor royalty scenario. The system is designed tomodel all the onshore federal lands in theLower 48 and Alaska.

The results track 20 years of monthly pro-duction (gas, oil and water), well count, alongwith federal and state royalties and severancetax projections. Production and royalty col-lection is broken up into its federal, NativeAmerican and private components. They areaggregated at the lease, state and total U.S.levels, and presented as monthly volumes aswell as 20-year summaries.

The secondary product is estimated by mul-tiplying the primary product by the gas-oil

ratio or yield derived fromhistorical data analysis. Fut-ure water production is estimated by multiplying theprimary product rate by thewater-oil ratio or the water-gas ratio, also derived fromhistorical data analysis.Theseresults are provided by indi-vidual lease, state totals andU.S. totals. A monthly com-plete cash flow at the individ-ual lease/agreement level isalso provided.

Two assumptions madewere that the future royaltyrate did not change and thatdistribution between federaland Native American landremained unchanged. Theresults were then comparedto determine the change ingas and oil produced withthe change in royalty col-lected. In effect, the “cost”to the federal and state trea-suries of incremental prod-uct produced as a directresult of the proposedincentive. Thus the pro-grams traced productionand the economic factors ona lease basis.

Two base runs weredefined to help analyze theincentives. A current roy-alty case was run to modelthe current property royaltystatus. The royalty rateincluded existing incentivesreceived, for example, theStripper Well Incentiveand/or the Heavy Oil Incentive.

The second base case assumed that no exist-ing royalty incentives were available. All prop-erties have a constant 12.5% royalty. For com-parison, the constant 12.5% royalty case was

assumed as a base case and compared to thecurrent royalty case and the two defined incen-tives cases, the Energy Bill and the Energy Billwith water or steam injection wells days online used to calculate daily production rates.

Figure 6. 20-year cumulative oil production

Figure 5. 20-year cumulative gas production

Figure 7. 20-year royalty collections


ECONOMIC IMPACT

The BLM safety net royaltyrelief analysis resultsOverview of Analysis—The set of analysesconsisted of 26 model runs. Figure 4 pro-vides a matrix of the model runs performedfor the analysis.

The four royalty cases were run using sevenconstant monthly price tracks. The ratiobetween oil and gas prices was maintained at 7.5for each price track. This ratio is derived fromthe $15.00 and $2.00 price thresholds proposedin the Energy Bill. No runs were made for theproposed Energy Bill cases using the $35 to$4.67 price track since it was not conceived thatthe threshold oil price for royalty relief would beabove $20/bbl or $2.67/Mcf levels.

Incremental comparison of summary results—There is an implicit assumption when analyz-ing a royalty relief proposal that there will be abenefit defined by production increases. Therealso is a cost – a loss in public sector revenuebecause a smaller production percentage goestoward royalty payments. The goal is thatthere is a scenario where the outcome is “rev-enue positive,” meaning that so much incre-mental production is stimulated that theamount of royalty collected is greater than itwould have been even though the percentagecollected per barrel equivalent produced is less.

Three royalty structures at a range of prod-uct prices are compared. The three royaltyscenarios are the Energy Bill, Energy Billwith injection and the current royalty struc-ture in place today. To evaluate the cost/ben-efit ratios in a consistent manner, the 20-yearsummary results are compared to the resultsof the constant 12.5% royalty case.

All of the scenarios studied were “revenuenegative,” meaning there was less revenuegenerated for the federal and state treasurythan there would be under a standard 12.5%royalty. Please note that the 12.5% royalty isnot the current royalty on many of the leasesstudied. There is always going to be a costassociated with producing incremental oil bythe safety net royalty relief programs beingconsidered. Figures 5, 6 and 7 show the

cumulative production of gas and oil aswell as the royalty collections at a gasprice of $1.47 and an oil price of $11.

Incremental federal and state rev-enue royalty collected provides theincentive cost. State revenue collectedis calculated by adding the state royaltyto the state severance tax. Some loststate revenue is offset by the increasedseverance tax collection. The cost to thefederal and state treasury is then pro-vided in a cost per incremental barrel ofoil equivalent produced. This is calcu-lated by dividing the incremental fed-eral royalty and the incremental staterevenue by the incremental barrel of oilequivalent generated. Finally, the fed-eral cost and state cost are combined toget the total cost per incremental barrelof oil equivalent produced.

ConclusionsFigure 8 shows that at prices above $15,the current royalty structure is more costeffective even though the Energy Bill sce-nario produces more barrels of oil equivalent.The reason for this is that the Energy Bill sce-narios give royalty relief to gas productionwhereas the current structure does not. If theresults of the Energy Bill runs are examined, theincentives are most effective for oil at higherprices and are more effective for gas as the pricesbecome lower. This is illustrated in Figure 9,which shows the relative proportions of incre-mental gas and oil generated by the Energy Billproposal at the various price tracks.

After careful interpretation of the safety netroyalty relief model results, six conclusions cap-tured the major points gleaned from this analysis:

• proposed safety net royalty relief propos-als will not be revenue generators underscenarios evaluated when compared tothe 12.5% royalty payments;

• small incremental production is glea-ned under safety net royalty relief sce-narios studied;

• gas production is not as sensitive to

lower prices as oil production in theranges considered;

• cost effective to include injection days online for incentive to increase production;

• proposed Energy Bill incentives aremore cost effective at lower prices; and

• proposed Energy Bill incentives athigher trigger prices are more expensivethan current royalty structures.

The study is completed with the finalreport issued. The BLM has used the incen-tive analyses as basis to promulgate new roy-alty rules. ✧

AcknowledgementsThe author acknowledges the contributions from theBureau of Land Management, Washington, D.C.;the U. S. Department of Energy, Washington,D.C.; the Bureau of Land Management,California; the U.S. Minerals ManagementService, Denver; and the State Auditors on NewMexico, Oklahoma and Wyoming.

Figure 8. Cost per incremental barrel of oilequivalent vs. product price

Figure 9. Constant price effect on production

T he process of producing oiland natural gas generateslarge quantities of water pro-

duced from the same undergroundformations. Management of this pro-duced water represents a significantcost component in the production ofoil and gas. In the United States,about 20 billion bbl of producedwater are generated per year (world-wide, the annual volume is about 70billion bbl). Management options forproduced water are to a large extentdriven by applicable federal and stateregulatory requirements.

In 2004, Argonne National Laboratoryprepared a comprehensive white paper onproduced water for the U.S. Department ofEnergy. One chapter reviews U.S. regulatoryrequirements for produced water. This articleoffers a summary of that chapter, including abrief overview of the federal laws and regula-tions that govern management of producedwater in the United States. States typicallyhave similar laws and regulations but mayalso have more restrictive requirements insome cases. Requirements for managing pro-duced water differ substantially throughoutthe world; a discussion of international pro-duced water management requirements isbeyond the scope of this article.

U.S. regulatory requirementsIn 1988, the U.S. Environmental ProtectionAgency (EPA) exempted wastes related tooil and gas exploration and production

(E&P) from the hazardous waste portions ofthe Resource Conservation and RecoveryAct. The E&P waste exemption covers pro-duced water. However, exempting E&Pwaste from the federal law governing haz-ardous waste management does not precluderegulation of these wastes under other fed-eral or state laws and regulations.

Once produced water has been broughtto the surface, the primary managementoptions include discharge to surface waterbodies and underground injection forenhanced recovery (pressure maintenance)or disposal. Federal laws have assigned thelead program implementation responsibilityfor the discharge and injection programs tothe EPA. However, willing and able statescan seek primacy to run the programs. Thefollowing sections describe the major regu-latory programs and some of their impor-tant requirements.

Dischargingproduced waterIn the oil and gas industry, producedwater discharge volume and charac-teristics can vary considerably; anexample of a modest produced waterdischarge in a Rocky Mountainstate is shown in Figure 1. At theother end of the spectrum, somelarge offshore platforms can dis-charge tens of thousands of barrelsper day (see Figure 2). The CleanWater Act (CWA) requires that apermit issued under the NationalPollutant Discharge Elimination

System (NPDES) program must authorize alldischarges of pollutants to surface waters(streams, rivers, lakes, bays and oceans). Thetwo basic types of NPDES permits issued areindividual and general. Individual NPDESpermits are specifically tailored to individualfacilities. General NPDES permits cover mul-tiple facilities within a certain category in aspecific geographical area. General permitscontrol most offshore oil and gas discharges.

Under the CWA, the EPA has the author-ity to implement the NPDES program or itmay authorize states to implement all or partsof the national program. Once approved, astate gains the authority to issue permits andadminister the program. However, the EPAretains oversight responsibilities, includingthe option to review the permits issued by thestate and formally object to elements deemedin conflict with federal requirements. In caseswhere states have not been approved, the


PRODUCED WATER MANAGEMENT

By John A. Veil and Markus G. Puder,

Argonne National Laboratory,Washington, D.C.

Regulatory Considerations inthe Management of ProducedWater—A U.S. PerspectiveThere are a number of U.S. regulations of which to be aware and consider when managing produced water domestically.

Figure 1. Produced water is discharged to the surface in a coalbedmethane gas field. (Photo Courtesy ALL Consulting, Tulsa, Okla.)

EPA’s regional offices directly implement theNPDES program. Examples of importantgas-producing states that do not currentlyimplement the NPDES program for oil andgas discharges include Texas, Oklahoma,New Mexico and Alaska.

Discharge limits—NPDES permits containnumerical effluent limits that control dis-charges of pollutants to receiving waters.These generally are stated as average andmaximum concentration limits (in mg/l) butcan be expressed as loading limits (in kg/day)depending on the circumstances. Permitwriters derive effluent limits using technol-ogy-based standards and water quality-basedstandards. The more stringent of the two willbe written into the permit.

Effluent limitations guidelines (ELG)—These are national technology-based mini-

mum discharge requirementsdeveloped by the EPA on anindustry-by-industry basis thatembody the greatest pollutantreductions economically ach-ievable for an industry sector orportion of the industry, forexample, offshore oil and gasplatforms. Existing facilitiesmust meet a performance standard known as best avail-able technology economicallyachievable.

The EPA has developed five subcategoriesof ELGs for the oil and gas industry. Theterms onshore, offshore and coastal may beillustrated by drawing an imaginary line thatruns along the coast of the country. The linecrosses the mouth of rivers, bays and inlets.Any facility to the ocean side of the line is anoffshore facility. Any facility to the land sideof the line and on land is classified as anonshore facility. Any facility in or on the wateror in wetlands on the land side of the line is acoastal facility. For example, a facility in amarsh or inside a river mouth or bay is acoastal facility. The EPA has codified theELGs in the Code of Federal Regulations(CFR) at 40 CFR Part 435. The nationalELG requirements for produced water arediscussed in the next paragraphs. Table 1 pro-vides a quick overview.

The ELGs for offshore wells establishlimits for oil and grease of 29 mg/l averageand 42 mg/l maximum. Oil and gas activitiesin coastal waters may not discharge producedwaters, except for platforms in Cook Inlet,Alaska, which is treated in the same manneras offshore waters.

The produced water requirements foronshore wells are divided into three subcat-egories. As a general rule, onshore oil andgas activities may not discharge producedwater. However, two subcategories provideexceptions to the onshore rule. The agricul-tural and wildlife water use subcategoryallows those onshore facilities west of the98th meridian (a north-south line runningapproximately through the center of thecountry) to discharge produced water that isfresh enough to be beneficially used in agri-culture or wildlife propagation. These dis-charges must meet a maximum oil andgrease limit of 35 mg/l and be used for agri-cultural or wildlife purposes. The secondexception that allows for onshore dischargesis the stripper subcategory. It applies tofacilities that produce 10 b/d or less ofcrude oil. The EPA has published nonational discharge standards for this sub-category, effectively leaving any regulatorycontrols to the states. The gas-producingcommunity may be interested to note thatthe stripper subcategory applies only tosmall oil wells and not to small or marginalgas wells.

Why oil and grease —The EPA chose tolimit oil and grease as an indicator of manyother chemical compounds. Oil and grease isnot a single chemical compound, but a mea-sure of many different types of organic mate-rials that respond to a particular analyticalprocedure. Not all produced waters containthe same constituents even if they have thesame oil and grease content. Oil and greaseis made up of at least three forms:

• free oil (this is in the form of largedroplets are readily removable by gravityseparation methods);



ELG Subcategory Oil and Grease Limit Comments

Offshore 29 mg/l average42 mg/l maximum

Coastal Zero discharge Discharges to Cook Inlet, Alaska, aresubject to the offshore limits

Onshore Zero discharge Applies to all onshore wells except thosecovered by the stripper or agriculturaland wildlife subcategories

Stripper No national requirements;these are left to permitwriter discretion

Applies to wells producing less than 10b/d of oil; no comparable section forsmall gas wells

Agricultural and wildlife use

35 mg/l maximum Applies to wells west of the 98th merid-ian; produced water must be used foragricultural or wildlife purposes

Table 1 – EPA’s national ELGs for produced water discharges.

Figure 2. An offshore platform in the Gulf of Mexico.(Photo by J. Veil, Argonne National Laboratory)

• dispersed oil (this is in the form of smalldroplets that are more difficult toremove); and

• dissolved oil (these are hydrocarbonsand other similar materials dissolved inthe water stream; they are often chal-lenging to remove).

Depending on the distribution of oil andgrease in a produced water type, operators mustemploy different types of treatment processesto meet the applicable discharge requirements.

Water quality-based limits and other permitconditions—ELGs serve as a foundation forthe effluent limits included in a permit, butthe ELGs are based on the performance of atechnology and do not address the site-spe-cific environmental effects of discharges. Incertain instances, the technology-based con-trols may not be strict enough to ensure theaquatic environment will be protectedagainst toxic quantities of substances. Inthese cases, the permit writer must includeadditional, more stringent water quality-based effluent limits and other monitoringand operational requirements in NPDESpermits. The water quality-based limits maybe numeric or narrative. The EPA has pub-lished numeric water quality criteria formore than 100 pollutants that can be used tocalculate water quality-based limits(http://epa.gov/waterscience/standards/wqcri-teria.html). A narrative limitation would uselanguage like “no toxic substances in toxicquantities.” The process for establishing thelimits takes into account the designated useof the water body, the variability of the pol-lutant in the effluent, species sensitivity (fortoxicity), and, where appropriate, dilution inthe receiving water (including discharge con-ditions and water column properties).

Four of the EPA’s regional offices haveissued general permits to authorize producedwater discharges to ocean and coastal waters.The EPA’s general NPDES permits imposeadditional numerical limits on toxicity andinclude different combinations of limits ormonitoring requirements for other parame-

ters such as metals, organics, radionuclidesand nutrients. The permits also includeoperational, monitoring, testing and report-ing requirements. Veil et al. (2004) describesthe four most important general permits foroil and gas exploration, development andproduction operations issued for the EasternGulf of Mexico (Region 4), Western Gulf ofMexico (Region 6), California (Region 9)and Cook Inlet, Alaska (Region 10).

No centrally compiled information existson the permits that have been issued under EPA’s agricultural and wildlife subcat-egory. Veil (1997) identified the states thathad issued stripper well discharge per-mits at that time and described the permitrequirements.

Coalbed methane (CBM) discharges—CBMproduction activities are somewhat differentfrom conventional gas production in thatwater is intentionally pumped from coalseams to lower pressure, thereby allowingproduction of the gas. CBM produced watermay contain far lower total dissolved solidsand oil and grease than produced watersfrom other gas or oil wells because CBMwater has been in contact with coal seamsrather than crude oil in the formation. TheEPA did not consider CBM production

when it established its oil and gas industryELGs and has not yet revised its ELGs toinclude CBM discharges. In the absence ofnational ELGs for CBM water, some stateregulatory agencies have chosen to issueNPDES permits allowing discharges ofCBM water using their own best profes-sional judgment.

The regulations that govern water dis-charges from CBM wells, as well as those thatdo not apply, are described in a 2002 report,describing the permitting procedures and lim-itations Alabama, Wyoming, Montana andColorado use. Each state provides for some-what different permitting procedures and dis-charge standards. In general, the states requirelimits or monitoring for oil and grease, salin-ity (such as chlorides, total dissolved solids orconductivity), pH, total suspended solids andtoxicity. Similar requirements may be in placefor other contaminants. In practice, the CBMproducers who are currently discharging canmeet the permit limits through a minimaldegree of treatment. Interest in CBM dis-charges has intensified since 2002. The per-mitting agencies continue to shape new poli-cies and permit conditions.

Injecting produced waterMost onshore produced water is injected forenhanced recovery or disposal. Injection isregulated under the Underground InjectionControl (UIC) program. Injection wellsrelated to oil and gas operations are knownas Class II wells (Figure 3). The EPA hasdelegated UIC program authority to manystates, which then regulate injection activi-ties to ensure protection of undergroundsources of drinking water (USDW). Eachstate has somewhat different specificrequirements but generally they include thefollowing elements:

Area of review (AOR)—Applicants for newClass II injection well permits must identifywithin the injection well’s AOR (often aone-quarter mile radius) the location of allknown wells that penetrate the injection



Figure 3. A Class II injection well (Photoby J. Veil, Argonne National Laboratory)

zone, or in the case of Class II wells operat-ing over the fracture pressure of the injectionformation, all known wells within AOR pen-etrating formations affected by the increasein pressure.

Construction requirements—All new ClassII wells must be sited to inject into a forma-tion separated from USDW by a confiningzone free of known open faults or fractureswithin the AOR. Class II wells must becased and cemented to prevent fluid move-ment into or between USDW.

Operating requirements—The operatingrequirements in UIC Class II permits mustspecify a maximum injection pressure that willnot initiate new fractures or propagate exist-ing fractures in the confining zone adjacent tothe USDW. Injection pressure must not causethe movement of fluids into USDW.

Mechanical integrity testing—Well ownersor operators must demonstrate the internaland external integrity of their injection wells.This includes the absence of significant leak-age in the casing, tubing, or packer of theinjection wells.

Monitoring and reporting—Owners/oper-ators must monitor the nature of injectedfluids (at least once within the first year ofauthorization and thereafter wheneverchanges are made to the injection fluid);injection pressure, flow rate and cumulativevolume at various frequencies specified in theregulations (weekly for disposal wells andmonthly for enhanced recovery wells);mechanical integrity (at least once every 5years); and other operational statistics.Owner/operators must submit at least anannual report of the monitoring results. Inaddition, well failures or other well-specificactivities (including corrective action) mustbe reported.

Plugging and abandonment—Injectionwells that have not been in operation for 2years must be plugged and abandoned unlessspecial precautions are taken to avoid endan-germent of USDW. Prior to abandonment,Class II wells must be plugged with cement

in a manner that will not allow movement offluids into or between USDW.

Veil et al. (2004) provides a detaileddescription of the injection programs fromseveral large oil- and gas-producing states(Texas, California, Alaska and Colorado),and two federal agencies that oversee activi-ties of federal lands (onshore – Bureau ofLand Management and offshore – U.S.Minerals Management Service).

Requirements relating to other management optionsThe previous sections described regulatoryrequirements for discharging or injectingproduced water. Increasingly, oil and gas pro-ducers are considering ways they can reuseproduced water or convert it to a commercialcommodity. Some examples for reuse of pro-duced water include livestock watering, cropirrigation, fire control, vehicle washing, cool-ing water and process water in a power plantand use in making drilling fluids. Nonational regulatory standards apply to theseactivities. Individual states may place restric-tions on certain types of reuse options.

Research is being conducted to investigatethe desalination of produced water for bene-ficial use for community water supplies. Ifthat technology becomes economically viableand is used to produce drinking water, thetreated water would be subject to all applica-ble federal and state drinking water regula-tions. The regulatory details are not dis-cussed here because produced water is notcurrently used for human consumption.Desalination may also be used to treat pro-duced water for reuse for irrigation or live-stock. These uses are not subject to drinkingwater regulations but may be subject to otherstate or local requirements.

SummaryMost offshore produced water is dischargedto the ocean under the provisions of NPDESgeneral permits. Most onshore producedwater is injected for enhanced recovery or

disposal under a Class II UIC permit. TheNPDES and UIC programs are adminis-tered by the EPA or through delegation bystate agencies. Discharge requirements varysubstantially depending on whether the wellis onshore or offshore and where it is in theUnited States. Most states have adoptedtheir own UIC requirements that includevarious operational and management provi-sions to protect USDW. ✧

AcknowledgementsThe U.S. Department of Energy/NationalEnergy Technology Laboratory, under ContractW-31-109-Eng-38 funded Argonne’s work onthis article.

References1. ALL Consulting, Handbook on CoalbedMethane Produced Water: Management andBeneficial Use Alternatives, prepared by ALLConsulting for the Ground Water ProtectionResearch Foundation, U.S. Department ofEnergy and U.S. Bureau of Land Management,July 2003.2. Veil, J.A., Surface Water Discharges from Onshore Stripper Wells, prepared forU.S. Department of Energy by Argonne National Laboratory, Office of Fossil Energy,December 1997.3. Veil, J.A., Regulatory Issues AffectingManagement of Produced Water fromCoalbed Methane Wells, prepared for U.S.Department of Energy, Office of Fossil Energy,National Petroleum Technology Office, by ArgonneNational Laboratory, February 2002. (availablefor downloading at www.ead.anl.gov/pub/dsp_detail.cfm?PubID=1477)4. Veil, J.A., M.G. Puder, D. Elcock, and R.J.Redweik, Jr, A White Paper DescribingProduced Water from Production of CrudeOil, Natural Gas, and Coalbed Methane, pre-pared by Argonne National Laboratory for theU.S. Department of Energy, National EnergyTechnology Laboratory, January 2004, 87 pp.(available for downloading at www.ead.anl.gov/pub/dsp_detail.cfm?PubID=1715)



The maritime transportindustry is engaged in awide-ranging program

for the construction of liquefiednatural gas (LNG) carriers,including evolutionary designs,to support the current wave ofnew LNG projects. At the sametime, EnerSea Transport LLCand other natural gas innova-tors also are leading a criticalbut less visible role throughtheir development of a newgeneration of compressed natural gas (CNG) marinetransport and storage systemsthat promises to establish anadditional and valuable com-mercial means for shipping natural gas.

This article will focus on the design fea-tures of EnerSea's innovative “Volume-Optimized” CNG technology and how itmay be applied to improve the prospects forremote and stranded gas development. It willexplain the key considerations and chal-lenges that have been reflected in the designsand how this new gas ship concept opens anew world of remote and offshore fielddevelopment opportunities (Figure 1).

CNG marine transport allows emerging,energy-hungry markets around the globe toaccess additional gas supplies that otherwisewould continue to remain stranded. As com-pared with other solutions for de-strandinggas resorces, such as LNG and gas-to-liquidtechnologies, CNG transport offers a solu-tion that reduces the amount of fixed-asset

investment required as well as the amount ofgas lost because of process energy require-ments and boil off, to name a few reasons.Such value-adding features make the recentbreakthrough in CNG storage and han-dling technologies, and the new class ofships that support CNG transport opera-tions, attractive to gas and power players ona global scale.

Volume-optimized natural gas transport technology Natural gas is a complex fluid that exhibitsnon-ideal gas properties when compressedabove about 1,000 psi.The non-ideal charac-teristics can be accommodated by adjustingthe Ideal Gas Law through the introductionof what is commonly called the compress-ibility factor or Z-factor. The gas industry

has conducted extensive resea-rch on the phase behavior ofnatural gas, including predictivemodels to characterize the Z-factor effects in gas compressionengineering. EnerSea’s volume-optimized transport and stor-age (VOTRANS™) technol-ogy recognizes the relationshipbetween the design require-ments of containment systemsand the Z-factor effect in gasstorage design. By chilling gas to a suitably low temperature(usually well below 32°F), it ispossible to compress great quan-tities of gas into tubular con-tainers such that the ratio of the

weight of the gas stored to the weight of thecontainer is optimized, thus providing sig-nificant cost improvements over previousCNG designs.

Achieving an optimum design requires thestoring of this cool gas at relatively moderatepressures – about 1,400psi to 1,800psi,depending on gas composition – which isabout half that of traditional “ambient tem-perature” CNG designs. This critical designbreakthrough means the compression horse-power requirement and its cost, along withthe gas cargo container and ship hull costs,can be substantially reduced. These savingsare somewhat offset by costs for refrigerationand insulation, but the net cost advantageand operational benefits demonstrate thevalue of volume optimization in the contain-ment design.


TRANSPORT & STORAGE

By John P. Dunlop, P.E. and Charles N.White, P.E., EnerSea Transport LLCVolume-Optimized

Compressed Natural Gas Recent trends in the overall growth of global energy demand and the preference for natural gas within themix of fuel supply choices has spawned a resurgence in the development of natural gas projects as wellas the acceleration of new technologies to help connect stranded gas resources and consuming markets.

Figure 1. EnerSea Transport's V-800 compressed natural gas carrier.

Gas handling considerationsVOTRANS also employs aunique system for efficientlyhandling the transfer of gascargo into and out of thecargo storage system. Apatented liquid displacementsystem provides the ability tocontrol pressure and temper-ature of the gas throughoutthe processes. By controllingbackpressure when loadinggas into the containers, tem-perature extremes created byauto-refrigeration and heatof compression effects in tra-ditional CNG designs can beavoided. Using the displace-ment fluid as a piston to push the gas cargo outof the containers at the discharge terminal alsoprevents the automatic cooling of the gas anddropout of natural gas liquids.

An important feature of EnerSea’s liquiddisplacement gas-handling technology is thatthis approach allows substantial transport sys-tem design and cost efficiency advantages.Thiscapability enables the storage and transport ofricher gas streams, such as gas associated withoilfield production. The low temperature com-pressibility characteristics of rich gas allow evenmore cargo to be stored, and at lower pressurein lighter and less expensive containers, thanfor a lean gas cargo. Because of the high-energycontent of the rich gas cargo, the economics ofgas transport can be attractive for transit dis-tances up to 3,000 nautical miles.

Gas cargo handling and storageTo limit the amount of time at the loadingand unloading terminals, VOTRANS shipscan be configured to include dynamic posi-tioning systems for connection to an effi-cient bow loading or single-point mooringbuoy system, or internal turret device similarto the APL shuttle loading system installedat Norway’s Heidrun field (Figure 2).

Generally, the shipboard gas-handling sys-tem design assumes the gas arrives on boardat a pressure that allows the gas to beinjected into the storage containers at therelatively low temperatures and pressuresallowed by the volume-optimization princi-ples noted above.

Loading is expected to take place at a ratecorresponding to the production rate of thefield being serviced such that the cargo con-tainers are usually filled in 2 days to 3 days.Uninterrupted field production operationscan be supported through the use of a dual-buoy loading terminal configuration.

At the gas delivery terminal, it also isdesired to limit turnaround time. Therefore,the ship utilizes the liquid displacement sys-tem to dispel the gas cargo from storage in anefficient and controlled manner. Once theCNG ship is properly connected to the deliv-ery terminal, gas is discharged through theinternal turret to a flowline that ties into asubsea pipeline connection. Pumping capac-ity usually is designed to discharge the cargowithin 24 hours. The displacement liquid iskept chilled and carried in insulated tankswith enough capacity to support a sequential,cascading displacement operation.

Container designVertically oriented steelcylinders (“pipe tank” bot-tles) are incorporated withinchilled, nitrogen-inerted andinsulated cargo holds for the current VOTRANS shipdesigns (Figure 3).

The gas cylinders are fab-ricated from high-strengthsteel pipes with end caps andnozzles produced for thespecific project require-ments. The pipes and headsmust be made from high-strength materials that pro-vide low temperature tough-ness in the as-welded condi-tion. Current designs are

based on specially developed API 5L X80pipes at least 42-in. in diameter.

The gas cylinders may be considered to bepressure vessels and generally are designed tomeet American Society of MechanicalEngineers (ASME) Section 8 Div3 underspecial Code Case considerations for theintended service. Det Norske Veritas (DNV)and the American Bureau of Shipping(ABS) have developed guidelines that willallow rational/probabilistic design methodsto demonstrate suitability for marine serviceand class. Design pressure, cylinder diameterand material strength are the primary deter-minants of wall thickness and weight of theindividual cylinders.

Ship Design and Development Status

Design evolutionA discussion of key design drivers or con-straints illustrates the evolution of the cur-rent VOTRANS CNG carrier designs.These key drivers include:

• regulatory and class requirements;• mission requirements (gas cargo charac-

teristics and required storage capacity);


TRANSPORT & STORAGE

Figure 2. A schematic of Heidrun field with two submerged turret loadingbuoys. (Graphic courtesy of APL)

• construction and commissioning con-siderations; and

• operability.Because of the status of this emerging

industry, many potential beneficiaries haveinquired about the ability of a marine CNGtransport project to gain regulatory approval.These queries were largely answered duringthe successful 1st International MarineCNG Standards Forum held last June atMemorial University of Newfoundland,under the sponsorship of The Centre forMarine CNG (www.cmcng.org). This eventgathered together a highly distinguished del-egation comprised of many CNG develop-ers, energy companies, shipping companies,leading professional organizations (such asSIGTTO and ASME) and class societies, aswell as key maritime administrations andrepresentatives from other governmentaloversight agencies. The official communiquéof the forum noted that the state of guidancefor classification and regulatory purposes iswell advanced, and that alignment across theindustry was a practical goal. The forumleadership also recognized that theCMCNG was positioned to play an impor-tant role in advancing the state of the tech-nology toward practical standards andimplementation.

The International Gas Carrier (IGC) Codeprovides the foundation for establishing a path-way to regulatory approval. However, becausethe IGC Code did not adequately anticipatelarge-scale marine CNG transportation pro-jects, ABS and DNV have prepared guidelinesor rules to more fully address the critical fea-tures of safety review for classification. A safetycase approach, involving intense hazard identi-fication and mitigation exercises, as well asquantitative risk assessments, complement thecodes and guidelines to ensure safe designs aswell as operating practices.

Having completed the initial complementof hazard identification and operability stud-ies, the overarching consensus of the review-ers is that CNG fleets can meet, and possibly

exceed, the level of safety established by themaritime LNG industry.

Inspection and maintenance considera-tions influence the dimensioning of, andarrangements within, the holds. Accessibilityrequirements are well recorded in existingRules for Marine Vessels. In the VOTRANSsystem design approach, periodic visualinspection of cargo cylinders and associatedpiping is supplemented with a continuousintegrity monitoring system based onacoustic emissions (AE) technology. Allmanifolds are instrumented with AE sen-sors such that critical areas of all tanks canbe monitored throughout the service life. Ifindications of developing critical situationsare recorded, individual manifold groupscan be temporarily or permanently decom-missioned. Because of the high degree ofsegregation and low probability of failure,there is currently no intention to remove,replace or repair any individual cylinders.Instead, a failing cylinder can be perma-nently isolated from a manifold tank groupat the next scheduled dry-docking so thetank group may then be recommissionedinto service.

Mission requirements clearly provide acompetitive edge for the volume-optimizedCNG design, as this technology allows for excellent flexibility relative to the designof facilities and the fleet dedicated to a spe-cific project.

Market opportunity reviews have ledEnerSea to focus on ship designs with acargo capacity range of 500 MMscf to 1,000MMscf. Although VOTRANS technologymay be applied for horizontal or vertical pipetank configurations, EnerSea has deter-mined that vertically oriented tanks areappropriate for the intial target range ofcargo capacities.

The VOTRANS systems are capable ofaccomodating a wide range of gas composi-tions and supply conditions with limited gashandling facilities installed on the CNG car-riers. When a dry, sweet gas stream is sup-

plied at a pressure adequate to charge thecontainment system (about 1,400psi for richstreams and up to 1,800psi for leaner gaswhen storing the gas at -22°F), onboard gashandling facilities are minimal.

Construction and commissioningConstruction and commissioning operationsrequire early consideration when generatingthe ship design and project management plan.CNG carriers represent a new class of vesselsthat will challenge the capabilities of traditionalshipyards. Only capable, progressive shipyardswill be prepared to undertake the completeproject to deliver a fleet of CNG carriers. If thecontainment system is too heavy or the hulllines are too fine, the ship cannot be completedin or ever enter a dry-dock. As an alternative,gas cargo systems may also be fabricated,installed and commissioned quayside at a spe-cialized fabrication facility. Therefore, alterna-tive construction scenarios have evolved thatmay not wholly depend on a single shipyard.

VOTRANS CNG carriers may bedesigned so they can be completed in dry-dock because the containers provide a lowenough lightship weight to allow float outwith all equipment onboard.

Ship operabilityOperability targets are in many ways the mostcomplex to address in achieving a practicalimplementation of a significant new technol-ogy. The overall ship dimensions were drivenby a need to maintain and repair the vesselduring its service life. Maximum availabledrafts at repair facilities around the worldconstrained the design draft in the repair con-dition (basically lightship). The maximumlightship draft is, therefore, targeted to besubstantially less than 26ft, based on a world-wide survey of all major repair shipyards. Thisconstraint drives the overall length and beam,with an associated reasonable block coeffi-cient, to arrive at a lightship displacementwithin the draft limits that can be accommo-dated at multiple repair facilities worldwide.


TRANSPORT & STORAGE

Ship speed, and hence installedpower, is driven by many factorsincluding gas production rate,distance to market, economicalship speed and fleet size.

The power required forpropulsion sets the minimum sizeof the power plant. However,depending on the offloading raterequirements, a large power loadmay also be allocated for cargohandling processes. This set thestage for an all-electric shiprather than a low speed dieselwith separate electric power gen-eration system. A twin-screwarrangement was chosen, in partbecause of the small change indraft between light ship and fullload, and also to provide for addi-tional overall vessel systemredundancy.

The choice of prime mover andtype of fuel was set after discus-sions with ship operators regard-ing availability of ship engineers trained inthe operation of gas turbines vs. heavy fueloil diesels. Dual fuel diesels (gas and heavyfuel oil) can also be considered but, becauseof the CNG cargo system’s inherent capabil-ities, gas boil-off will not occur as it typicallydoes in LNG tankers. To maximize deliveryof the gas, heavy fuel oil prime movers mayoften be specified. For projects where re-fuelling and fuel availability are concerns orsupply gas is distinctly less valuable thanbunker fuel, the dual-fuel option deservesconsideration.

A high degree of cargo system monitoringand automation has been incorporated intothe design to minimize the size of the crew.Limited additional crew training will berequired to ensure safe operation of the cargoloading and offloading systems. Most ofthese systems are extensions of existingmarine systems though maybe somewhatlarger, such as the cargo cooling system.

CNG carrier development statusABS granted EnerSea “Approval inPrinciple” for the design and operatingplans for a generic V-800 VOTRANS shipin April 2003. The V-800 ships are notion-ally designed to carry up to 800 MMscf ofrich gas. Subsequent ship design conceptsbeing considered for new project-specificopportunities are taking onboard thelessons learned from that design exerciseand the interactions with the knowledge-able review team at ABS.

EnerSea has ensured design and technol-ogy development is in line with commercialproject development status. Front-endactivities for a number of CNG projectapplication opportunities were underway atthe end of last year. Announced early phase project studies include Oil SearchLtd.’s Papua New Guinea-New Zealandventure, Husky Energy’s White Rose gas

development in offshore New-foundland and GAIL (India)Ltd.’s gas importation projectfor eastern India.

Concurrently, a multi-milliondollar technology validation pro-gram is moving into the finalphases with participatory com-mitments and funding fromclients and key suppliers. This val-idation program features both afunctional testing program withthe Gas Technology Institute, anda full-scale cold temperaturefatigue and burst test program ofthe cargo cylinders. Additionalspecial topic studies and analysesare complementing the maintechnical objectives with investi-gations into fracture/fatiguetoughness and cold jet gas releasethermodynamics. These strategicinvestigations combine to supportdecision-making hurdles with keyclients and timely development of

the foundation for possible ASME CodeCase applications.

ConclusionsLarge-scale marine transport of CNG isnow imminent as confirmed by theannouncements of a number of early stageproject-engineering initiatives. Advance-ments on many fronts – technology, regula-tory (standardization), and project opportu-nities – have been achieved that are bringingthis new industry to realization within thenear term.

The innovative features, advantages andconcepts of volume-optimized CNG marinetransport, as well as the progress describedherein, demonstrate how this promisingtechnology is developing a leading positionin the creation of an important new gastransport solution for the upstream industryand energy-hungry markets in need of addi-tional gas supplies. ✧


TRANSPORT & STORAGE

Figure 3. VOTRANS cargo module with manifold piping andvalve arrangements.

PROJECT SELECTIONMEETING RECAP

The Stripper Well Consortium (SWC) selected13 projects for funding in 2005 at its annual pro-ject selection meeting in San Antonio on March8-9. The total value of the projects selected is$2,459,564, of which $1,547,192 will be fundedby the SWC. The abstracts for the selected pro-jects, as well as those for previously funded pro-jects, can be found on the SWC Web site atwww.energy.psu.edu/swc. Some of the projectsselected include:

• “Field Application of Accurate, Low CostPortable Production Well Testers” – OakResources, Inc.;

• “Interaction of Nitrogen/CO2 Mixtures withCrude Oil” – The Pennsylvania State University;

• “Uncovering Bypassed Pay in CentralOklahoma Using Statistical Analysis and FieldTests” – Schlumberger Consulter Services;

• “Re-fit Two Stripper Wells with ExistingLarge Diameter or Open Hole Completionswith Spoolable Non-metalic Tubing,Transition Connections, Variable DiameterSeal Cups and Modified G.O.A.L. CasingSwab to Automatically Lift Fluids andEnhance Performance” – Brandywine Energy& Development Co.;

• “Desalination of Brackish Water and Disposalinto Waterflood Injection Wells” – TexasA&M University;

• “New Technology for Unloading Gas Wells” –Colorado School of Mines; and

• “Building and Testing a New Type of VacuumPump for Casinghead Pressure Reduction inStripper Wells” – W & W Vacuum &Compressors Inc.

METHANE HYDRATE RESEARCHCRUISE UNDERWAY

The semisubmersible drilling vessel Uncle Johnentered the Gulf of Mexico on April 17 for a 35-day methane hydrate research voyage. During theU.S. Department of Energy Fossil Energy sup-ported expedition, researchers will collect drilling,logging and coring data from deep well pairs inthe Keathley Canyon and Atwater Valley loca-tions to characterize methane hydrates in thedeepwater Gulf. The mission is part of the Gulf ofMexico gas hydrates joint industry project ( JIP)led by ChevronTexaco in cooperation with theNational Energy Technology Laboratory(NETL). The JIP is a 4-year effort to developtechnologies for locating and safely drillingthrough or near gas hydrates. Data collected dur-ing the cruise will help researchers understandhow natural gas hydrates can trap oil or gas inshallow reservoirs, affect seafloor and wellborestability and influence climate change. TheStrategic Center for Natural Gas and Oil area ofthe NETL Web site is providing background pro-ject information, status reports and pictures fromthe cruise. For more information, visitwww.netl.doe.gov/

NEW MICROHOLETECHNOLOGY PROJECTS

The U.S. Department of Energy (DOE) has markedanother key milestone in its research and develop-ment initiative to develop “microhole” technologiesaimed at slashing the costs and reducing the envi-ronmental impacts of drilling America’s oil and gaswells. The DOE announced the award of funding

for 10 projects designed to push microhole technol-ogy another step closer to commercialization andwidespread adoption by the U.S. oil and gas industry.The initiative involves developing technologies asso-ciated with drilling wells smaller than 43⁄4-in. indiameter and related downhole micro-instrumenta-tion. The ultimate result of industry broadly embrac-ing this technology could be a sea change in the waythe nation’s oil and gas producers explore for, drilland monitor wells. www.netl.doe.gov/scngo


BRIEFS

EVENTS

5TH INTERNATIONALCONFERENCE ON GAS HYDRATES

June 13-16, Trondheim, Norway. For more informa-tion, visit www.icgh.org/

IPAA MID-YEAR MEETINGJune 15-17, San Francisco. The focus of this meetingwill include the future of crude oil as it relates to globalsupply and demand and the role China, India and thePacific Rim will play in the coming years; Canada’s oilsand reserves and extraction challenges; the future ofcrude oil and exploration and production trends; and anofficial from Mexico's Department of Energy willaddress the country's outlook for supply and demandduring the next decade as well as discuss opportunitiesSouth of the U.S. borders.

SOCIETY OF PETROLEUMENGINEERS CONFERENCE

Oct. 9-12, Dallas. For more information, visitwww.spe.org

Gas Technology Institute (GTI)1700 S. Mount Prospect RoadDes Plaines, IL 60018-1804Phone: (847) 768-0500; Fax: (847) 768-0501E-mail: [email protected] site: www.gastechnology.org

GTI E&P Research Center1700 S. Mount Prospect RoadDes Plaines, IL 60018-1804Phone: (847) 768-0500; Fax: (847) 768-0501E-mail: [email protected] site: www.gastechnology.org

GTI/CatoosaSM Test Facility, Inc.19319 N. E. 76th, Owasso, OK 74015Phone: Toll-free (877) 477-1910 Fax: (918) 274-1914E-mail: [email protected]

U.S. Department of Energy National Energy Technology Laboratory Web site: www.netl.doe.gov/scngo

3610 Collins Ferry RoadMorgantown, WV 26507-0880

626 Cochrans Mill RoadPittsburgh, PA 15236-0340

One W. Third St.Tulsa, OK 74103-3519

525 DuckeringFairbanks, AK 99775

Office of Fossil Energy1000 Independence Ave., S.W. Washington, DC 20585Web site: www.fe.doe.gov

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CONTACT INFORMATION

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