gastips spring 2003 - citeseerx

GTI-03/0035

Very High-Speed Drill String CommunicationsNetwork: An Enabling TechnologyA new technology solves drillstring-coupling problems, making downhole data transmission a reality.

Security, Economy and Capacity—A SaltCavern-Based LNG Receiving TerminalNew research indicates salt caverns could provide a cost-effective storage method for liquefied natural gas.

Process Engineering for Natural GasTreatment using Direct-Injection H2S ScavengersDesign, troubleshooting and optimization of direct-injection H2S scavenging systems pose many challenges. Gas Technology Institute and others from the oil and gas industry are working together to develop engineering test data and modeling software needed to effectively address these tasks.

Consortium Selects 13 New Projects to Aid Stripper Well OperatorsThe recent war with Iraq reminded Americans of the need for the United States to become less dependent on foreign energy sources.

Gas: A Messenger from Subsurface ResourcesA detailed chemical and modeling analysis of a 77-mile by 124-mile area of the offshoreLouisiana Gulf of Mexico shows how gas venting from deep sources alters shallower hydrocarbons and carries information that could guide exploration.

Understanding the Mechanisms of HydrateNucleation and InhibitionThe Hydrates Flow Assurance Facility at Gas Technology Institute provides tools for understanding the mechanisms by which hydrates form and grow.

TECHNOLOGY DEVELOPMENTS IN NATURAL GAS EXPLORATION, PRODUCTION AND PROCESSING

Sour Gas Treatment

Liquefied Natural Gas Storage

Stripper Well Update

HydrocarbonMigration

Hydrate FlowAssurance

Downhole Telemetry

A Publication of Gas Technology Institute, the U.S. Dept. of Energy and Hart Publications, Inc.

Items of Interest

03 Editors’ Comments34 New Publications35 Events Calendar

Spring 2003 • Volume 9 • Number 2

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2 GasTIPS • Spring 2003

GasTIPS®

Managing EditorsMonique A. BarbeeRhonda DueyHart Publications

Graphic DesignersSharon JohnsonCory PattersonHart Publications

EditorsBrad TomerStrategic Center for Natural GasDOE-NETLJoe HilyardGas Technology Institute

Subscriber ServicesMarcos AlviarHart Publications

PublisherHart Publications

C O N T E N T SEditors’ Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Downhole Telemetry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Liquefied Natural Gas Storage . . . . . . . . . . . . . . . . . . . . . . . . 8

Sour Gas Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Stripper Well Update . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Hydrocarbon Migration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Hydrate Flow Assurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

New Publications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Events and Contact Information . . . . . . . . . . . . . . . . . . . . . . 35

DISCLAIMER:LEGAL NOTICE: This publication was prepared as

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1. makes any warranty or representation,

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, apparatus, method, or process dis-

closed in this report may not infringe privately

owned rights; or

2 . assumes any l iab i l i t y w i th respect

to the use of, or for damages resulting from the use

of, any information, apparatus, method or process

disclosed in this report.

Reference to trade names or specific commer-

cial products, commodities, or services in this

report does not represent or constitute an

endorsement, recommendation, or favoring by GTI

or DOE of the specific commercial product, com-

modity or service.

GasTIPS® (ISSN 1078-3954), published four times a year by Hart Publications, a divisionof Chemical Week Associates, reports on research supported by Gas Technology Institute,the U.S. Department of Energy, and others in the area of natural gas exploration, formationevaluation, drilling and completion, 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 industry areavailable for $99. Back issues are $25. Send address changes and requests for back issues toSubscriber Services at Hart Publications, 4545 Post Oak Place, Suite 210, Houston, TX77027, Fax: (713) 840-0923. Comments and suggestions should be directed to RhondaDuey, GasTIPS Managing Editor, at the same address.

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Spring 2003 • GasTIPS 3

T his issue of GasTIPS containsa veritable smorgasbord ofresearch initiatives aimed at

developing technology to find anddevelop domestic gas reserves. No onetechnology holds all the answers, andthese projects represent the work ofthousands of bright minds attacking theproblem from every conceivable angle.

On the exploration side, an article fromCornell University describes a study thathas discovered and documented theeffects gas can have on oil through aprocess called gas washing. Modeling ofvariations in n-alkane presence from thenorth end of the Gulf of Mexico studyarea to the south end indicates this varia-tion is expected from the changing patternof sediment deposition. The study indi-cates the chemistry of the gas and washedoils carry information on the currentpattern of subsurface petroleum migra-tion relevant to exploration for subsurfacehydrocarbon resources.

In drilling news, a new product calledIntelliPipe®, developed jointly betweenthe U.S. Department of Energy (DOE),NOVATEK and Grant Prideco, promisesto replace mud-pulse telemetry in pro-viding high-speed information fromdownhole during the drilling process.The availability of this real-time dataallows for bi-directional feedback andcontrol for downhole steering assembliesto more accurately locate and place thewell in a targeted reservoir. Also, the effi-ciency of drilling operations can beoptimized, costs reduced and safetyimproved. The technology potentially

enables the improvement and increase ofunderbalanced drilling technology, whichcan be used to increase drilling speed anddecrease formation damage.

Many of the projects discussed dealwith production issues. A key concern inthe United States is the vast number ofstripper wells. A stripper well is definedas a well that produces less than 10 b/dof oil or less than 60 Mcf/d of gas.These wells are important to the energysecurity of the United States, as theyrepresent 15% of the oil and 7% of thegas produced. Therefore, continued pro-duction from these wells is increasinglydependent on new technologies, whichwill keep them economical.

Recognizing that most stripper wellsare operated by smaller independentoperators who have neither the fundsnor the staff to develop new tech-nologies, the DOE through the NationalEnergy Technology Laboratory devel-oped and sponsors the Stripper WellConsortium (SWC). The SWC offers

operators across the United States aforum to discuss with technology devel-opers the operating problems they facein their daily operations. The SWCrecently held its third annual meetingand accepted 13 proposals for full orpartial funding, which also are discussedin this issue.

Other articles deal with hydrate inhi-bition, the treatment of sour gas and thepotential for using salt caverns to storeliquefied natural gas from offshoreinstallations. We hope you’ll find thisissue of GasTIPS informative. Pleasecontact the individuals listed at the endof each article to obtain more infor-mation on specific topics. If you haveany questions or comments, please con-tact managing editor Rhonda Duey [email protected]. ✧

Research Highlights Old, NewFields for DevelopmentIn the ongoing search for new natural gas technologies, projects run the gamut from understandinghydrocarbon migration to getting the most out of the least productive wells.

Commentary

Stripper wells are getting attention as a host of new technologies attempt to squeeze out theremaining reserves.

DOWNHOLE TELEMETRY

The quest for high-speed data trans-mission has been a Holy Grail inthe exploration and drilling disci-

plines since the inception of the ability toevaluate the downhole-drilling environ-ment and accurately characterize the for-mation being drilled while precisely navi-gating wellbores to targeted reservoirs inreal time. Since 1939, technology has beenproposed to provide data from downholeto the surface. The technical barrier hasbeen the couplings between the discretepipe sections comprising the drillstring.

For more than 60 years, the oil and gasindustry has struggled with the problemof a drill pipe connection, or “tool joint,”that would stand up to the wear and tearof hostile drilling conditions and opera-tions, yet provide a reliable and rapiddata transmission connection. Largelybecause of this stumbling block, develop-ers turned to a technology called “mudpulse telemetry” in the mid-1970s.

Mud pulse telemetry eliminates theneed to hard-wire pipe and electrical con-nections and transmits data as pressurepulses through fluid circulated to cleanthe cuttings out of the wellbore. But theexcruciatingly slow pace of mud pulsetelemetry – 3 to 10 bits per second –often means data resolution and tool reli-ability is so poor the driller cannot makecrucial decisions in real time. Often,time-consuming operations are requiredto retrieve the downhole data, or drillinghas to stop while other procedures areemployed to confirm the low-resolutiondata pulsed to the surface. Additionally,underbalanced drilling (UBD) operationsutilizing foams and gases cannot be usedwith the current mud-pulsed system.

Downhole Internet: The SolutionIn 1997 NOVATEK in Provo, Utah, wasfunded by the U.S. Department ofEnergy’s National Energy TechnologyLaboratory (NETL) to develop a steerableMud Hammer System. As part of thatresearch, a high-speed data transmissions y s t e m w a s n e e d e d . N O VAT E Kaddressed that need and found a largetechnology gap existed and wouldrequire substantially more resources thana supporting project task would allow.Additionally, in accomplishing theresearch, a better mode of data transmis-sion was identified. Grant Prideco, theworld’s largest drill pipe manufacturer,began working with NOVATEK on the

data system in early 2000 and formed anew corporation called IntelliServ® tocommercialize the system. In 2001,NETL partially funded the spin-off tech-nology development of a high-speeddownhole communications (telemetry)system now referred to as IntelliPipe®.

The key to the new system is a uniquenon-contacting coupler embedded inconnections between 30-ft sections ofdrill pipe (Figure 1). The concept allowsthe IntelliPipe to be used like regular drillpipe without any special handling of thepipe by the rig hands.

The concept is to passively link dis-crete components together into a down-hole communication network. Identifiedas IntelliCom™, this link is comprised ofa ring-shaped transducer that transmits


By John D. Rogers, Ph.D., P.E.,US DOE/NETL; David Pixton

and David Hall, NOVATEK Inc.;Michael Jellison, P.E. and

Brett Chandler, Grant Prideco.

Very High-Speed Drill StringCommunications Network: An Enabling TechnologyA new technology solves drillstring-coupling problems, making downhole data transmission a reality.

Figure 1: The above coupler permits data to be sent across the connection and through a high-speed cable attached to the inner-pipe wall.

data to another component withoutdirect electrical contact (Figure 2). Thismakes the system much more reliableand robust than other hardwired teleme-try concepts tried in the past and ordersof magnitude faster than the current mudpulse system.

The unique geometry design of GrantPrideco’s line of eXtreme Torque® (XT)drill pipe provides an ideal location forthe IntelliCom components (Figure 3).An armored data cable running the lengthof the drill pipe completes the data pathbetween the IntelliCom links or matedtool joints (Figure 4).

IntelliPipe is the basic building blockof a modular downhole data transmis-sion line. Once the transmission line is inplace, information may move betweenvarious members of the drilling assembly,much like information can be shared byseveral users on a network or Internet.The components comprising this “Internet”can be at the surface, at the bit or any-where along the drillstring. Just like theInternet, addressable nodes can bedefined along the drillstring. These nodescan be individual tool joints or controldevices including jars, motors, bits,measurement-, logging- or seismic-while-drilling (MWD, LWD and SWD)sensors as well as other downhole tools(Figure 5). At each node identifiableevents can be correlated to a particularregion of the well.

Proprietary software and hardware

controls the flow of information. Akey device called the IntelliLinkTM

controls the flow of information andboosts the data signal strength(Figure 6). This important compo-nent is housed in a modified full-length joint of drill pipe and includesa large through-bore to allow for lowfluid friction pressure losses andthrough-access.

The technology is applicable to alltypes of threaded drillstring assem-blies, including reamers, jars, stabi-lizers and other subs. Rotating joints,such as swivels and downholemotors, do not impair the use of theIntelliCom technology. A data swivelsub at the top of the drillstring allowsthe transmitted signal to be redirectedinto a drillstem data server and distrib-uted even to the World Wide Web afterencryption for access by company person-nel.

Enabling Technology and Benefits of the IntelliServ NetworkThe real-time characterization of a reser-voir during the drilling process is one ofthe premier applications of the IntelliServnetwork. These include LWD, MWDand SWD. The availability of this real-time data allows for bi-directional feed-back and control for downhole steeringassemblies to more accurately locate andplace the well in a targeted reservoir(Figure 7).

Increased efficiency, cost reductionand improved safety is possible since thenetwork allows for more precisely locat-ing stuck pipe, monitoring drillstring andbit vibration, actual downhole rotationspeed, weight on bit, monitoring pres-sures up and down the well for kickdetection, and seismic look-ahead datatransmitted over the network.

The IntelliServ network potentiallyenables the improvement and increaseof UBD technology, which can be usedto increase drilling speed and decreaseformation damage. The network is notaffected by the type of fluid used todrill a well, unlike current MWD, LWDand SWD telemetry systems. Therefore,


DOWNHOLE TELEMETRY

Figure 2: The non-contact feature ofIntelliCom’s ring-shaped transducer linkallows it to be embedded and protectedwithin drillstring components.

Figure 3: Mated segments of these double-shouldered drill pipes provide the connectivity for the high-speed data network of IntelliPipe.

Figure 4: The data cable completes the path for information to circulate between the IntelliComlinks and tool joints.

DOWNHOLE TELEMETRY

better productivity in under-pressuredand/or fluid sensitive reservoirs usingUBD is possible.

Status of the TechnologyInitial tests of the prototype were con-ducted in a 1,000-ft well at IntelliServ’s testfacility in Provo and at a 2,000-ft well at theGas Technology Institute’s Catoosa test sitein Oklahoma. Full-scale tests have includedmultiple makeups (50 to 150) to full torqueon several joint pairs. Data transmissionrates are approaching 2 million bits/sec.

Additionally, actual drilling tests havebeen concluded at the U.S. Departmentof Energy’s Rocky Mountain TestingCenter near Casper, Wyo. A 6,000-ftalready-drilled well was chosen for thistest. A drillstring comprising 121 jointsof IntelliPipe, IntelliLinks and Intelli-Heavyweight™ (3,827ft) was success-fully run in the well and able to establishcommunication along the entire string

for the duration of the testing. A datarate of 2 megabit/sec was establishedthrough the system for all tests. Totalstring length, including the bottomholeassembly, was 4,531ft. In this string, fiveIntelliLinks were used as network nodesand data collection sites.

Full-scale tests have been supplementedby bench-top laboratory testing. For example,seals used in cable connections have beentested in a pressure vessel at simulatedborehole condit ions of 391 ˚F and25,000psi. Such testing continues in aneffort to further improve the transmissionrange and drilling robustness of the system.

The process of inserting a wire perma-nently inside a joint of drill pipe requirescertain modifications to be made to thepipe. These modifications have been ana-lyzed by Grant Prideco engineers usingpredictive FEA and laboratory testing andhave shown the pipe strength and integrityof the pipe is unchanged.

Further DevelopmentsCurrently, this project is entering thethird and final phase of activity, whichis to get a complete drilling string intothe field, establish high-speed commu-nications with third-party down-holetools and prepare the system for com-mercial introduction.

Development efforts are underway toimprove the flexibility and capabilities ofthe IntelliServ drilling network softwareand hardware. A key area of focus is inte-gration of existing downhole measure-ment and logging devices with theIntelliPipe hardware and network system.Cooperative efforts with major tool man-ufacturers are underway. Other newtools and applications for the networkalso are being developed.

A second key area of present focus isimproving the passive transmission range ofthe system. As mentioned above, the pres-ent system has demonstrated transmission

of 1,000ft prior to needing a boostin signal level. Improvements totransmission line efficiency andelectronic module sensitivity areexpected to bring as much as afive-fold increase in this passiverange. Work to bring about theseimprovements already has begun.

A third area of focus is toextend the transmission line toother drillstring elements includ-ing jars, drill collars and miscel-laneous subs. Work in each ofthese areas is progressing. As amatter of particular interest,IntelliServ is working closelywith a major manufacturer ofdrilling jars, and a design fora wired jar is expected to be test-ed soon.

Finally, further work is neededto increase the high-pressureand high-temperature capabil-ities of the IntelliCom compo-nents and the network elec-tronics so these may be used inthe deepest wells and under themost severe drilling conditions.


Figure 5: IntelliPipe is the basic building block of a modular downhole data transmission line.

Introduction andCommercialization to thePetroleum IndustryOfficial introduction of this technologyto the petroleum industry occurred at the

2002 Society of PetroleumEngineers Annual Confer-ence. Initial commercialapplication of the Intelli-Serv system is anticipatedduring the fourth quarterof 2003.

A major effort and keyto all this work is fieldqualification of the system.IntelliServ is seeking oppor-tunities to field-test thedata transmission systemin low-risk applications.Such testing, though notwithout risk, is seen to be

fairly benign to normal drilling operations,since the test will largely consist ofhandling drill pipe. System failures encoun-tered in the testing, if any, are expected tohave minimal impact on the drilling process

and can be corrected during normal trippingof the string. Field testing of the system isexpected to continue throughout 2003.

Conclusions IntelliServ is one of the most enabling tech-nologies to be developed recently for thepetroleum industry. The impact is far reach-ing. The technological advancement expect-ed in the overall drilling process will result infaster well drilling, thereby reducing wellcosts. The “smart pipe” itself is the buildingblock of a downhole “Internet system” thatwill allow for the first time high-speed bi-directional communication with varioustools, and allow economic reservoir charac-terization and precise navigating of a wellwhile drilling in real time.

For more information, please contactJohn Rogers at [email protected], (304) 285-4880. ✧


DOWNHOLE TELEMETRY

Figure 6: The software and hardware inside the IntelliLink(inset) help control the flow of information.

Figure 7: With the IntelliServ network, the efficiency of drilling operationscan be optimized, costs reduced and safety improved.

Salt caverns provide an inte-gra l l ink in the logist ica lrequirements of the natural

gas, natural gas liquids, petrochemicaland refining industries in the UnitedStates. The purpose of this paper is topresent preliminary results of seminalresearch involving the use of salt cavernsin the receipt of seaborne liquefiednatural gas (LNG). The research is con-ducted under cooperative agreementwith the U.S. Department of Energy’s(DOE) National Energy TechnologyLaboratory (NETL).

Cooperative Agreement:DE-FC26-02NT41653

Project Title: Examine and Evaluate a

Process to Use Salt Caverns to ReceiveShip-Borne Liquefied Natural Gas (LNG)

IntroductionThe DOE cooperative research project onwhich this paper is based indicates thatsalt cavern-based receiving terminals inonshore and offshore locations on the GulfCoast could be built at reduced capital costand have less than half the operating costs,significantly higher delivery capacity,shorter construction time and be muchmore secure than conventional liquid tank-based terminals. The research describes anonshore LNG-receiving facility in south-west Louisiana (Figure 1) and an LNG-receiving facility built 50 miles offshore in

Vermilion Block 179. The con-siderable natural gas infrastruc-ture in this area in offshore gath-ering, and onshore intrastateand interstate pipelines has con-siderable capacity available to helpmeet increasing gas demands inthe United States. There is a sig-nificant body of knowledge andpractice concerning natural gasstorage in salt caverns, and thereis a considerable body of knowl-edge and practice in handlingLNG, but there has never beenany attempt to develop a processwhereby the two technologies canbe combined. Salt cavern storageis infinitely more secure than sur-face storage tanks, far less suscep-tible to accidents or terrorist actsand much more acceptable to thecommunity. Salt cavern naturalgas storage is known for itsvery high deliverability that isinstantaneously available to meet

variable demands in the gas grid. Theaddition of LNG receiving to cavern stor-age would allow the storage facilities tobe replenished during periods of con-tinued high demand or to replace declin-ing gas production.

LNG imports are expected to become anincreasingly important part of the U.S.energy supply, and the capacities to receiveLNG securely, safely and economicallymust be expanded. This research confirmsthe feasibility of salt cavern LNG-receivingterminals onshore and offshore. Such ter-minals can be quickly built and provideadditional import capacity into the UnitedStates, exceeding 10 Bcf/d in the aggregate.

The performance of work under thisagreement is based on U.S. Patent5,511,905 along with pending U.S. andforeign patent applications. The cost-sharing participants in the research arethe NETL, BP America Production Co.,Bluewater Offshore Production Systems(USA) Inc. and HNG Storage LP.

Conventional Tank-BasedLNG Receiving FacilityA typical tank-based facility will haveinsulated tank storage capacity for cargofrom two to three ships or about 5 Bcf to8 Bcf at standard conditions (250,000 cu mto 380,000 cu m in liquid form). Theterminal will always have an LNG inven-tory in its storage tanks to keep every-thing cooled down. Typically, the high-pressure pumps and vaporizers are theunits’ limiting send-out as the facility canreceive a cargo in 24 hours but takes from3 days to 6 days to discharge that volumeas gas to the pipelines. There are four LNGterminals in the United States of thisdesign, one of which is being refurbished.

By Michael M. McCall,Conversion Gas

Imports, LLCSecurity, Economy andCapacity—A Salt Cavern-Based LNG Receiving TerminalNew research indicates salt caverns could provide a cost-effective storage method for liquefied natural gas.

LIQUEFIED NATURAL GAS STORAGE


Figure 1: The Liberty LNG Terminal would connect to sevenmajor natural gas pipelines having a takeaway capacity of 3 Bcf/d.

All have announced expansion plans,but collectively the expanded terminalsfall far short of the projected imports ofLNG by 2020. Various alternate designsusing cryogenic tank storage on floatingvessels, shipboard regasification units orgravity-based structures generally takethis same model and move it to sea.

LNG cryogenic storage tanks areexpensive to build and maintain. Severalcargoes scheduled to be received afterSept. 11, 2001, have been delayedbecause of security concerns. There istherefore a need for a more secure, moreeconomical and higher-capacity way toreceive, store and distribute LNG importsthan has been done in the past.

Salt Cavern-Based LNG-Receiving Facility The application of conventional salt cavernstorage technology, augmented by newtechnology in the area of pumps, heatexchangers and facility design, couldmarry LNG and salt caverns into a highlysecure, economical and flexible method toexpand the importing nation’s energy sup-ply. In the Liberty LNG Terminal, the shipunloading occurs 35 miles from the cavernstorage site. In a conventional terminal, theliquid storage tanks must be in close prox-imity to the ship discharge site, and con-siderable inventory is maintained betweenships’ calls (Figure 2).

There are a number of salt formations,offshore and near shore, or navigablewaters where caverns could be solution-mined and developed into LNG-receivingterminals. Salt cavern gas storage facili-ties have very high deliverability instanta-neously available to the pipeline system,far higher than LNG vaporization capaci-ties in conventional LNG terminals.

Critical ElementsThe major critical elements revealed inthe research are:

• a method to moor and offload anLNG ship

• LNG pumps sufficient to create caverninjection pressures and volume

capability to allow acceptable shipdischarge times

• a heat exchanger design that willeconomically warm the LNG at highpressure and high volumes

• navigable waters sufficient for anLNG carrier to approach

• salt formations suitable for caverndevelopment

• a pipeline infrastructure sufficient tocarry large volumes of gas to market.

Mooring and OffloadingA conventional International Society ofGas Tanker and Terminal Operators jettyand mooring configuration alongside anavigable waterway was chosen to fit therequirements of the onshore Liberty LNGsite. For the offshore application, theresearch describes a new design developedby Bluewater Offshore Production Systems(USA) Inc. for the offshore mooring andLNG transfer system, the regasificationand the storage of the gas in offshore saltcaverns. The system is developed for non-dedicated tankers, offshore operations andgas storage, and a high operational avail-ability, even in severe weather. The near-shore facility comprises a single point-moored discharge point, a regasificationunit and a storage facility.

The design work done to date showsthe transfer system, regasification and stor-age options are fully feasible. The design isindependent of the volumes of gas desiredand the geographic location. Although it isnew, all of its components are proven andhave been used in terminal and offshoreloading systems for some time.

LNG PumpsLNG pumps sufficient to boost the pres-sure of the ship’s discharge from about50psi to cavern injection pressures of2,000psi to 2,200psi have been contem-plated by the major cryogenic pump-makers and cross no technological barri-ers from pumps widely used. Suchpumps, however, have not yet been con-structed and tested to industry’s satisfac-tion. Unloading rates between 283 Mcf/hrand 353 Mcf/hr can be achieved withmultiple pumps and are the design basisfor the research design facilities.

LNG Heat ExchangersConventional designs of heat exchangerscan be utilized to warm the resultanthigh-pressure LNG, but capacity limita-tions and energy consumption dictated anew approach resulting in the patentedBishop Process Heat Exchanger.



Figure 2: Salt cavern natural gas storage offers very high deliverability that is instantaneously avail-able to meet variable demands in the gas grid.

The Bishop Process warms LNG usinga heat exchanger and stores the resultingdense phase natural gas in a salt cavern,discharges it to a pipeline or both. Theheat exchangers use seawater as the war-mant. The combination of the high-effi-ciency heat exchanger and the inherentlyenergy-efficient storage operation usingsalt caverns indicate the total energy con-sumption in a salt cavern-based terminalwould be equal to about 0.35% of thethroughput volumes compared with asmuch as 3.0% in a conventional tank-based terminal.

To accomplish heat exchange in a hori-zontal flow configuration such as theBishop Process, it is important the coldfluid be at a temperature and pressure suchthat it is maintained in the dense or criticalphase so no phase change takes place inthe cold fluid during its warming to thedesired temperature. The dense or criticalphase is defined as the state of a fluid whenit is outside the two-phase envelope of thepressure-temperature phase diagram forthe fluid. In this condition, there is no dis-tinction between liquid and gas, and den-sity changes on warming are gradual withno change in phase. This allows the heatexchanger of the Bishop Process to reduceor avoid stratification, cavitation and vapor

lock, which are problems with two-phasegas-liquid flows.

The effect of confining the fluid to thedense phase is illustrated by an analysisof the densimetric Froude Number, F, thatdefines flow regimes for layered or strati-fied flows:

Here, V is fluid velocity, g is acceler-ation due to gravity, D is the pipediameter, � is the fluid density and ∆�is the change in fluid density. If F islarge, the terms involving stratificationin the governing equation of fluidmotion drop out of the equation. As apractical example, two-phase flows inenclosed systems generally lose allstratification when the Froude Numberrises to a range from 1 to 2. In thisapplication, the value of the FroudeNumber ranges in the hundreds, whichassures complete mixing of any den-sity variations. These high values areassured by the fact that in dense phaseflow, the term ∆�� in the equationabove is small.

Measurement of the Froude Numberoccurs downstream of the high-pressurepump systems and in the heat exchangers.Process simulations using a computerprogram and the finite element modelingconducted as part of the research projectindicate the heat exchange occurs as pre-dicted, icing is controlled and energyconsumption for the system is signifi-cantly lower than experienced in conven-tional liquid tank terminals. Field tests toconfirm the mathematical representa-tions are expected to be performed.

Salt Formations and Storage LocationThe Liberty LNG Terminal described inthe research uses two existing salt cavernsthat have been solution-mined in a salt for-mation in Calcasieu Parish, La., capable ofholding 16 Bcf of natural gas or the equiv-alent of cargo from about six ships.

The Vermilion 179 site wouldrequire the mining of caverns in anexisting salt formation located about1,000ft below the seabed. This casestudy locates the salt cavern storagefacility in Vermilion Block 179, a well-known salt formation in water about100ft deep. This is sufficient for thedrafts of any known and contemplated

LNG carrier. The rights to develop asalt cavern storage facility in U.S. terri-torial waters are obtained via leasefrom the U.S. Minerals ManagementService. Such a lease would be grantedon a “non-interference basis” with anyexisting or future mineral explorationand production lease on the sameblocks. This research describes thedevelopment of six caverns, each ini-tially of 2 million-bbl capacity butmaintaining a wash string in operationso that while in operation and duringtime they could be continually washedto greater capacities, depending on theneeds of the operator. These cavernscould hold about 12 Bcf of densephase natural gas at 2,000psi andcould be developed and placed inoperation in 12 months. They could



Figure 3: The Vermilion site would connect to the three largest offshore gathering systems in the Gulfof Mexico, Bluewater, SeaRobin and Texas Eastern, and have takeaway capacity in excess of 2 Bcf/d.

subsequently be enlarged to 4 millionbbl each for a total storage capacity of24 Bcf at a subsequent additional costof less than $2 million.

There are more than 1,000 saltcaverns being used in the UnitedStates and Canada to store hydro-carbons. Storage in salt cavernsexceeds 1.2 billion bbl of hydro-gen, natural gas, natural gas liq-uids, olefins, refined products andcrude oil. In the United States, thesalt cavern storage sites form alogistical connection between thegas, gas liquids, refining and petro-chemical industries. The entireinventory of the Strategic PetroleumReserve, more than 600 million bblof crude oil, is contained in salt caverns.

Salt caverns have high send-out capac-ity, are very secure, and very inexpensiveto create and maintain compared withsurface tanks, particularly cryogenictanks. A difference between the opera-tion of salt caverns used in LNG-receivingand conventional natural gas storage isthe high rates of injection into the cav-erns compared with most facilities.Conventional natural gas storage in saltcaverns uses compressors to boost thepressure of inlet gas to cavern injection atrates generally between 500 MMcf/d and1 Bcf/d. This application would involveinjections at 3 Bcf/d to 4 Bcf/d, which isaccommodated by multiple caverns andwell design. A significant energy savingsoccurs in pumping LNG compared withcompressing natural gas. A geomechanicaltemperature and rock mechanics analysisconducted as part of the research projectindicates that injections to the caverns andwithdrawals from them at the design ratesdescribed are within salt tolerances.

The PipelinesThe Liberty LNG Terminal would con-nect to seven major natural gas pipelineshaving a takeaway capacity of 3 Bcf/d.The Vermilion site would connect to thethree largest offshore gathering systemsin the Gulf of Mexico, Bluewater,

SeaRobin and Texas Eastern, and havetakeaway capacity in excess of 2 Bcf/day(Figure 3). More than 20 additional siteswere evaluated that combine salt forma-tions suitable for storage cavern develop-ment in proximity to existing pipelinecapacity, indicating that multiple loca-tions could be developed to accept virtu-ally any level of LNG imports that couldbe required in the future (Figure 4).

Facility OperationsThe LNG ship mooring at the LibertyTerminal would be identical to that usedat a conventional tank terminal. The off-shore Vermilion 179 terminal would usea mooring and offloading system that hasbeen designed for safe offshore load-ing/unloading of LNG to and from non-dedicated LNG carriers in wave heightsup to 15ft and flow rates up to 353 Mcf/hr.All LNG ships are equipped to offloadLNG cargo with shipboard pumps atabout 50psi and -260˚F.

At unloading however, rather thandirect the LNG to surface tanks for stor-age, the ship’s discharged LNG would beboosted by high-pressure LNG pumpsto about 2,000psi to the heat exchang-ers. Seawater heat exchangers wouldwarm the natural gas to design tempera-tures of 40˚F. From the discharge of theheat exchangers, all low-temperature

considerations end, and the gas is trans-ported in conditions standard to the nat-ural gas pipeline industry.

The natural gas would be injecteddirectly into the caverns and/or the con-necting pipelines with appropriate pres-sure control as necessary. The entirecargo would be handled this one time,leaving only enough LNG on site to keepthe pumps cold.

The operation of the salt cavern storagecaverns, their maintenance and inspectionwould be identical to those practices in the100-plus natural gas storage caverns inoperation in North America and Europe.

For more information, contact authorMichael McCall at [email protected], (713) 781-4949 or James Ammera t j a m e s . a m m e r @ n e t l . d o e . g o v , (304) 285-4383. ✧

AcknowledgementsGrateful acknowledgement is given to theU.S. Department of Energy and its com-ponent agencies, the Strategic Gas Centerand the National Energy TechnologyLaboratory, for commissioning the coop-erative research agreement under whichthis work was done, and to funding par-ticipants BP American Production Co.,Bluewater Offshore Production Systems(USA) Inc. and HNG Storage LP, whichhave participated in it.



Figure 4: There are several onshore and near-shore cavern sites that could be used for LNG storage.

SOUR GAS TREATMENT

Natural gas producers, domes-tically and abroad, haveincreasingly targeted lower-

quality gas resources for development.This trend continues to drive theindustry to search for better, morecost-effective and environmentallyacceptable methods for treating sourgas. For economic reasons, hydrogensulfide (H2S) scavenging has emergedas the technology of choice for gaswith low H2S concentrations, forexample, less than 200 ppmv.

Operators frequently select thedirect-injection method of applying H2Sscavengers because of the lower capital

costs and/or the severe restrictions onspace and weight encountered with off-shore applications. While the direct-injection method offers these advan-tages over batch application of liquid orsolid scavenging agents in large towercontactors, the ability to predict theperformance of the direct-injection sys-tem or achieve treatment specificationswithout excessive chemical usage is fre-quently a challenge. For these reasons,Gas Technology Institute (GTI) andothers in the industry have directedresearch during the past decade todevelop an improved understanding ofthe fundamental mechanisms control-

ling the direct-injection scavengingprocess. The potential benefit of suchan effort is substantial, considering theestimated $50 million/year spent onH2S scavenging chemicals in the UnitedStates alone.

H2S scavenging research has beenconducted primarily by independentresearch organizations such as GTI,product development groups within H2Sscavenging agent manufacturing compa-nies or companies that use the productsto treat their gas. For example, a groupof several companies involved in NorthSea gas production sponsored a projectto develop a better understanding of


By Kevin S. Fisher,CrystaTech, Inc.; and

Dennis Leppin, Raj Palla and Dr. Aqil Jamal, GTI E&Pand Gas Processing Group.

Process Engineering for Natural Gas Treatment using Direct-Injection H2S ScavengersDesign, troubleshooting and optimization of direct-injection H2S scavenging systems pose many challenges.GTI and others from the oil and gas industry are working together to develop engineering test data andmodeling software needed to effectively address these tasks.

Figure 1: The basic direct-injection scavenging installation consists of a chemical injection pump, a means of introducing the scavenging agent intothe natural gas pipeline, a length of pipe to allow for gas/liquid contact, and a downstream device for separating spent or excess scavenging agentfrom the gas .

how scavenging applications might bemade more efficient. As a follow-up tothis proprietary work, GTI, on behalf ofthree gas producer companies, began ajoint-industry project (JIP) in 2001 togather specific engineering test data todevelop a software package to improvetechniques for designing, troubleshoot-ing and optimizing H2S scavenging sys-tems. This package expands on thecapabilities of an existing GTI softwareproduct, Scavenger CalcBase™ (GRI-96/0482), developed to allow rapidscreening of H2S scavengers for particu-lar applications. The first phase of theJIP project will be completed in 2003.

This article provides an overview of theissues faced when designing or optimizingdirect-injection scavenging systems anddescribes GTI’s collaboration with theindustry to develop test data and model-ing software to support these activities.

How is Natural Gas Treatedusing Direct-Injection H2SScavenging?Method of Application—Continuousdirect-injection of scavenging agentsinto a natural gas pipeline is usuallyapplied near the wellhead (after separa-tion from produced water and hydrocar-bons) or at centralized treating facilitiesprior to dehydration. The basic direct-injection scavenging installation consistsof a chemical injection pump, a meansof introducing the scavenging agent intothe natural gas pipeline, a length of pipeto allow for gas/liquid contact and adownstream device for separating spentor excess scavenging agent from the gas(Figure 1). Piping tees, quills or atomiza-tion nozzles are used to introduce thescavenging agent into the pipeline.Atomization nozzles enhance mixingwhen gas velocities are low. While staticmixers have been used to enhancegas/liquid contact, test data from GTI’stest loop in South Texas have raisedquestions about the benefit of usingstatic mixers for this application.

However, for situations where contacttime is relatively short, some benefit mayresult from advanced contacting devices.Scavenging liquids may be partiallyremoved downstream using gravity sepa-rators and/or coalescing filter/separators.For facilities with existing sparged-tower contactors, some operators mayprefer to fill the towers with water anduse them to remove spent scavengingagent from the treated gas, effectivelypolishing the gas and increasing the effi-ciency of the system.

Economics—The economics of treat-ing natural gas with nonregenerablescavengers strongly depends on the con-centration of H2S in the gas stream. Forrelatively low concentrations, capital costbecomes the dominant factor, favoringcontinuous direct-injection applicationsover the more expensive tower-basedmethod of application. As H2S concentra-tion increases, the scavenging agent costbecomes dominant, favoring solid-basedagents that, in many cases, have lowercosts per pound of sulfur removed.

For preliminary analyses, scavenger-treating costs can be estimated usingpublished data. GTI’s Scavenger CalcBaseprogram provides a method for quicklyestimating capital and operating costsfor several H2S scavenging processes.The program is intended primarily forinitial screening of processes usingalgorithms based on design equationsprovided by scavenger vendors.

Other important factors include proj-ect life, seasonal operations, installationlocation (offshore vs. onshore) andspent scavenger disposal costs. A shorteconomic project life or seasonal opera-tions tend to penalize technologies with

higher capital costs because there arefewer standard cubic feet of natural gasto amortize the capital, and thereforecosts per standard cubic feet are higher.As a result, direct-injection scavengingbecomes more favorable for these oper-ations because of the lower capitalcosts. For example, direct-injection scav-enging has been used to successfullytreat slightly sour gas (10 ppmv to 20ppmv H2S) from underground naturalgas storage systems that operate foronly 4 months during the year.

When gas must be treated offshore,equipment size and weight greatly affecttreatment costs. The large size andweight of tower contactors largelymakes them prohibitive for offshoreoperations, leaving only the direct-injec-tion option. In addition to the size andweight limitations, the handling of spentscavenger becomes more difficult off-shore. All these factors tend to favor theuse of liquid scavenging agents in adirect-injection configuration for off-shore application. In some cases, spentliquid scavenger can be blended withproduced water and disposed of viainjection wells or discharged to the seaafter treatment.

The cost for disposal of spent scav-enging agent varies widely dependingon how these wastes are regulated bythe governing authorities. In some cases,the spent scavenging agents must behandled and disposed of as a hazardouswaste, greatly increasing disposal costs.A careful study of applicable regulationsfor a particular site location is an impor-tant part of the scavenger-selectionprocess. It should also be noted thatwhile scavenging agents themselves


SOUR GAS TREATMENT

A careful study of applicable regulations for a particular site location is an important

part of the scavenger-selection process.

SOUR GAS TREATMENT

may not be hazardous, the spent scav-enging agent could become hazardousbecause of the concentration of contam-inants such as benzene or mercuryremoved from the gas.

Gas Stream Characteristics—MostH2S scavenging agents are designed totreat gas over a wide range of pressure,temperature, composition and flow con-ditions. However, several gas streamcharacteristics should be evaluated care-fully during the process design phase.

• Water saturation—Natural gas isusually treated before being dehy-drated; however, it is sometimesnecessary to treat a dry gas usingscavenging agents, for example, at aterminal handling offshore produc-tion being brought ashore througha sour gas line to avoid platformprocessing. Water-based scavengingagents, such as solutions of triazineand iron oxide-based scavengingagents, generally require the gas tobe saturated with water to preventformation of unwanted solid by-products and to achieve therequired H2S level.

• Oxygen content—Oxygen is usuallynot present in natural gas unlessgas is collected from wells under apartial vacuum. In these systems,oxygen sometimes leaks into thegas and may cause the formation ofelemental sulfur in beds of ironoxide-based scavenging agents,resulting in a higher than normalpressure drop across the bed. Oxygenmay also cause the formation of cor-rosive nitrogen dioxide when anitrite-based scavenger is used.

• Temperature—Low-temperature gascan cause scavenger reaction kineticsto slow down and affect systemperformance. High temperature cancause the scavenger to break downand form corrosive products.

• Pressure—H2S scavenging is moredifficult at low pressures becausethe partial pressure of H2S is lowerfor a given concentration and because

pipes and contactor vessels are gen-erally larger in size.

• Variations in flow rate—Direct-injectionsystems are vulnerable to changes inflow rate. The H2S removal perform-ance drops off severely as flow rate(and thus gas velocity) is reduced.Tower-based contractors allow forbetter turndown of gas flow rates.GTI patented a contactor in 2000 fordirect-injection applications wherebythe turndown ability is improved toallow operation over a large range(e.g., a factor of ten or better) of gasflow rates.

• Onshore vs. Offshore—For onshoreapplications, providing adequatelength of pipe to promote goodconversion of the scavenger and toreach H2S outlet specifications isusually not difficult. For offshoreoperations, adequate pipe length isusually not available, and it may benecessary to treat high temperaturegas after a compressor.

Environmental and Safety Considera-tions—Numerous federal, state and localregulations in the United States and sim-ilar governing authorities in many othercountries regulate the disposal of spentscavenger material. In addition to vary-ing by jurisdiction, the regulatoryrequirements depend on the scavengingagent selected and the levels of otherpotentially hazardous components pres-ent in the natural gas stream.

All sour natural gas treating processesshare the common hazards (fire, explo-sion and worker exposure to H2S) asso-ciated with handling high-pressure com-bustible gases containing toxic levels ofH2S. In addition to these areas of con-cern, other potential hazards associatedwith the use of H2S scavenging agentsinclude eye and respiratory irritation;benzene, formaldehyde and toxic metalsexposure; and height and confinedspace entry hazards.

Formaldehyde and caustic are notused much because of the relatedhealth and safety problems. Similarly,

the use of iron-sponge has declinedduring the years, in part because of thepyrophoric nature of the spent scav-enging agent.

For direct-injection scavenging sys-tems, the potential for exposure to toxicmaterials is highest during maintenanceoperations or when handling spentscavenger material. Pump repairs, change-out of atomization nozzles, or repairand maintenance of spent-scavengerhandling equipment are operations thathave the potential for exposure. Duringthese times, high levels of volatile organiccompounds may be present, and operatorshave more potential of coming into directcontact with a scavenging agent or thespent scavenger material.

Process design considerations—Manyfactors, including some site-specific,require careful consideration during theprocess design for a particular direct-injection H2S scavenging system. Thefollowing discussion provides a check-list of several items that need to beaddressed during the process design.

In l e t and Out le t KnockoutSeparators—Vendors of H2S scavengingagents frequently recommend the use ofan inlet knockout separator to removewater and/or free hydrocarbon liquidsfrom the gas before treatment. The pres-ence of excess free liquids has the poten-tial to increase scavenger usage andtreatment costs because of the addi-tional scavenger required to react withthe H2S present in these liquids. Outletknockouts usually are recommended toprevent entrained liquid droplets fromreaching downstream glycol dehydra-tors or other process equipment thatcould be adversely affected.

Length of Pipe for Contact—Thelength of pipe available for gas/liquidcontacting in direct-injection applica-tions is an important design parameter.In general, longer pipe lengths result inimproved H2S removal and reducedchemical consumption.

Atomization—The importance ofatomizing the scavenging agent as it is


injected varies by application. When gasvelocities are low, pipe lengths are short,or when large pipe diameters are used,atomization can significantly improveperformance. In other situations wherelong pipe lengths are available and gasvelocities are high, atomization has littleor no effect.

Water Saturation—Water additionis sometimes required if the gas is notsaturated with water at the temperatureand pressure where scavenging treat-ment is applied. This situation some-times occurs when gas is heated beforetreatment or when previously dehy-drated gas is present in the feed sourgas. In the case of triazine-based liquidscavengers, the reaction products areintended to stay dissolved in the spentscavenger, where they are ultimatelyseparated from the gas stream for dis-posal. However, if the gas is subsatu-rated with water, enough water mayevaporate from the scavenger solutionto cause unwanted precipitation ofsolid reaction products in the pipeline.Some operators operate a small waterinjection pump upstream to add therequired amount of water to saturatethe gas.

Scale Inhibition—The formation ofscale is a consideration when hard watermay contact highly alkaline scavengingagent formulations. This may occur ifthe scavenging agent is diluted withwater before use or if hard water isinjected to maintain water saturation. Inother cases, the spent scavenger may becommingled with other sources of hardwater in downstream separators andproduced water facilities.

CO2 Interference—Carbon dioxide(CO2) does not normally present a majorproblem because the most commonly usedH2S scavengers react selectively with H2S.However, CO2 is known to react at leastpartially with triazine-based scavengers anddoes compete for the scavenging chemical.In these cases, chemical consumptionmay be increased as a result of high levels of CO2.

GTI and Industry SponsorsDevelop New ProcessModeling Software GTI, acting on behalf of JIP partici-pants, is developing a new software-modeling package to make process cal-culations for direct-injection H2S scav-enging systems. In 1998, GTI pub-lished a set of equations largely basedon empirical correlation of field datathat could be used for direct-injectionsystems. The new model being devel-oped is more mechanistic in nature andis based on rigorous modeling of thetwo-phase flow hydraulics, mass trans-fer and chemical kinetics. Further, thenew model will be incorporated into auser-friendly program with a graphicaluser interface. The program will not bemade available to the general publicbut will be available to the JIP partici-pants and potentially to other partiesexpressing interest in it.

Theoretical models of the direct-injection process require knowledge ofthe following:

• reaction stoichiometry and kineticsbetween H2S, CO2 and the scaveng-ing agent

• physical solubility of H2S in thescavenger solution

• liquid- and gas-film mass transfercoefficients

• interfacial surface area available formass transfer.

Once the above quantities are known,the H2S absorption can be calculated basedon the following mass balance equation,which is at the core of the new model:

where�H

2S = Mole fraction H2S in the gas

phaseG = Molar gas velocity, lbmol/hr/ft2


SOUR GAS TREATMENT

Figure 2: The GTI software modeling package reports the H2S profile over the length of pipe alongwith other quantities of interest such as the chemical usage, e.g. liters of scavenging agentper kg sulfur removed.

SOUR GAS TREATMENT

z = Pipe length, ftK G = Overall mass transfer coeffi-

cient, lbmol/hr/ft2/atma = Interfacial area for mass transfer,

ft2/ft3

P = Pressure, atm

This equation is a first-order linearordinary differential equation and canbe solved using standard numericaltechniques (for example, a fourth-order Runge-Kutta method) as long asthe function ƒ(z) can be evaluated ateach point in the pipe. Evaluation ofƒ(z) requires an estimation of the inter-facial area, gas and liquid mass transfer

coefficients, and enhancement factorsused to describe the enhancement ofmass transfer in the liquid phasebecause of rapid chemical reactionstaking place in the diffusion film nearthe gas-liquid interface.

The model solves these equations andreports the H2S profile over the length ofpipe (Figure 2) along with other quantitiesof interest such as the chemical usage, forexample, liters of scavenging agent perkilogram of sulfur removed. A full report ofall intermediate quantities such as meandroplet size, interfacial areas, gas and liquidfilm coefficients, kinetic rate coefficients,etc., also is available.

GTI Constructs High-Pressure Test FlowLoop in Des PlainesLaboratory FacilityGTI is in the process of constructing alaboratory direct-injection test rig tostudy H2S scavenging of natural gasunder controlled conditions. A schematicdiagram of the laboratory test rig isshown in Figure 3. This setup is made ofschedule 80 carbon steel pipe with totalcontact length of 240ft. The entire struc-ture is housed inside a 20-ft x 12-ft fumehood equipped with a carbon adsorp-tion bed. The unit has a maximum gasflow of 0.6 MMscf/d under once-through


Figure 3: This diagram shows the design of the laboratory direct injection test rig commissioned in June.

and recycled flow conditions at temper-atures up to 319˚F and pressures up to1,100 psig.

During a typical test, pure methaneor nitrogen gas will be mixed withappropriate amounts of pure H2S gasand the mixture will be continuouslyfed to the system and metered. Thescavenger will be fed from a pressur-ized tank in lieu of pumps and meteredusing a rotameter. The scavenger willbe injected into the pipe loop using asmall nipple, quill or atomization nozzlefrom a pressurized storage tank. Gas-sampling taps are provided at conven-ient intervals. The gas and liquid exitsthe system and enters a separator. Thegas then proceeds to a booster com-pressor, which compresses the gas backup to inlet pressure. Any additionalcomponents to achieve the desiredcomposition are added back to the gas.The spent liquid will be sent to

disposal, recycled and/or sampled asnecessary. This unit will allow GTI tocollect significantly more data under awider variety of conditions and moreprecisely control the test conditions.

The purchase of various equipmentitems such as compressor, gas-liquidseparator, heater, cooler, carbon bedsand storage vessel is complete. The con-struction of the negative pressure cham-ber (Figure 4) and compressor room arecompleted and the work on building thepipe loop is underway. The setup isscheduled to be commissioned by theend of June 2003.

GTI Offers Services forTesting of New ScavengingAgents and/or New MassTransfer DevicesGTI is set up to carry out research projectsrelated to H2S scavenging for interestedparties. The staff involved in these projects

is experienced in field operations andcertified regarding H2S safety.Through the course of the variousscavenger projects GTI has beeninvolved in during the past decade,the organization has amassed a largedatabase on direct-injection scaveng-ing that has proved useful for designand troubleshooting of applications.In late 2003, GTI will be offering par-ticipation opportunities in a follow-up JIP to the current program thathas focused on developing a modelfor direct injection scavenging.Testing new scavengers and contac-tor devices in the new testing systemat Des Plaines, Ill., as well as in thefield system in McAllen, Texas, andimproving the computer model areall on the table for the program workscope, which the participants willfinalize. GTI also is interested in car-rying out projects directly for clients.Recent work has included design ofdirect-injection scavenging installa-tions based on the GTI patent atstorage field installations, and field-testing of proprietary scavengers is

being discussed with several clients. GTIcontinues to offer and support the GTIScavenger CalcBase program for towerapplications of scavengers and will devel-op a commercial version of the direct injec-tion model in the future. ✧

For more information on GTI gas process-ing products and services, or to join the JIPdescribed in this article, please contactDennis Leppin at GTI. Portions of this arti-cle were reproduced from an earlier GasTipsarticle from the Fall of 2000. For a completelisting of published test data, literature refer-ences and related information, the readeris referred to Fundamentals of H2SScavenging for Treatment of NaturalGas, by Fisher et. al., published in the pro-ceedings of the Ninth GRI Sulfur RecoveryConference, 1999. Additional detailedinformation on scavenging has been com-piled in the collected proceedings of the GRISmall-Scale Sulfur Recovery Conferences,GRI-00/0085.


SOUR GAS TREATMENT

Figure 4: Construction of the negative pressure chamber is already complete.

STRIPPER WELL UPDATE

Reducing the dependency onoverseas countries wouldrequire finding new resources,

but it would also need to include main-taining production from wells producingin the United States. Because many ofthe oil and gas fields in this country aremature, the production from these wellshas declined and will continue to do so.Sooner or later, most of these wells willfall into the stripper well category.

A stripper well is defined as a wellthat produces less than 10 b/d of oil orless than 60 Mcf/d of gas. Numbersreleased by the Interstate Oil and GasCompact Commission for 2001 showthere are 403,459 stripper oils wells inthe United States producing an averageof 2.15 b/d of oil and 234,507 stripper gaswells producing an average of 15.8 Mcf/d(IOGCC 2002). Stripper wells operate onthe lower edge of profitability andbecause of that, when wells owned bymajors reach that level of production,these companies usually sell them tosmall independent operators with loweroverhead or more regionally-specific port-folios. These wells are very important tothe energy security of the United States,as they represent 15% of the oil and 7% ofthe gas produced. However, continuedproduction from these wells is increasinglydependent on new technologies, whichwill keep them economical.

Recognizing that most stripper wellsare operated by smaller independentoperators that have neither the fundsnor the staff to develop new tech-nologies, the U.S. Department ofEnergy through the National Energy

Technology Laboratory (NETL) devel-oped and sponsors the Stripper WellConsortium (SWC). The SWC offersoperators across the United States aforum to discuss with technologydevelopers the operating problems theyface in their daily operations.

The operators play an integral part indeveloping and selecting projects forfunding, assuring the relevance andtimeliness of the research. A presentationof each proposal is provided to the SWCmembers, which allows all members toask questions and comment on the pro-posed work. The actual selection ofprojects is made by the Executive Council,which is comprised of seven elected mem-bers from the SWC membership.

The SWC held its third annual meetingMay 5-6, 2003, in Pearl River, NY, where27 proposed research projects were pre-sented and reviewed for possible SWCfunding. Of these, 10 proposals wereaccepted for full funding and three pro-posals for partial funding (Table 1). A totalof $1.156 million was committed by theSWC for the co-funding of these 13 projects.A brief description of each of the projectsselected for 2003 is provided below.

The SWC has provided $2.25 million inco-funding to support a total of 26 projectsin its first 2 years. All the first-year projectshave been completed and are scheduled tobe released to the SWC in June 2003. Thesecond-year projects are nearing comple-tion. A brief description of the projectsfunded in 2001 and 2002 as well asadditional information about the SWCis available on the SWC Web site atwww.energy.psu.edu/swc.

Field Testing of the Vortex Oiland Gas Unit for DownholeApplications – Vortex Flow LLCIn 2002, Vortex Flow was awarded agrant by the SWC to research, designand lab-test a downhole tool using thepatented and patent-pending vortextechnology. The technology takes a dis-organized single or multi-phase flow andtransforms it to a spiral flow with anassociated boundary layer that runsalong the inside wall of the pipe. Thevortex flow created by the technologyreduces the friction that causes pressuredrops as fluids (gas or liquids) flowthrough a pipe. The object of applyingthe technology in a downhole setting isthe reduction of pressure drops in a tub-ing string. Initial tests have shown thetool has the potential to reduce pressuredrops in tubing strings, thus increasingproduction of gas and oil in low-flowratestripper wells.

Several tool designs were manufac-tured and later tested at Texas A&MUniversity. Initial tests results indicatedthe final tool design reduced the pressuredrop up the tubing string and reducedthe required gas flow needed to liftliquids up the wellbore.

The objective of this project is to field-test the tool developed in the 2002 project.In this project, eight downhole tools will beinstalled in operating wells and the produc-tion data collected, analyzed and comparedwith pre-tool production data to determinethe tool’s effectiveness. The ability to trans-fer the Vortex technology to a downholeapplication will allow for greater tech-nology leverage and will provide a simple


By Gary Covatch, NETLConsortium Selects 13 New Projects to Aid Stripper Well OperatorsThe recent war with Iraq reminded Americans of the need for the United States to become less dependenton foreign energy sources.

means of improving production frommany operating stripper wells.

Chamber Lift—A Technology for ProducingStripper Oil Wells: Stage II –The Pennsylvania State UniversityArguably, the largest expense with theoperation of most stripper oil wells andmany stripper gas wells is the liftingcosts associated with the removal of fluidfrom the wellbore. The predominantartificial lift method used is rod pump-ing. Much of the equipment is outdated

and the maintenance costs large andincreasing. The problem the operatorfaces is how to upgrade the productionsystems at low enough capital cost thatthe typical well can show a reasonableeconomic return on investment.

In 2001, the SWC funded the devel-opment of a chamber lift system as analternative to existing lifting technologies.The concept of the system is that gas isinjected into the oil column via a small-diameter tubing string set in the produc-tion tubing. This gas then displaces theaccumulated fluid to the surface via the

annular space between the injectionstring and the production string. Theprocess is controlled using a sensor andmotor valve at the surface.

The project was broken down into threephases: a laboratory prototype, a field testand a computer modeling of the process. Todate, the laboratory studies have been com-pleted with synthetic oil and begun withfield crude. Field tests have demonstratedthe feasibility of the technique and the com-puter modeling of the process begun. Thisproject is a continuation of the 2001 projectin which additional laboratory tests with



Project Topic: Organization

Field Testing of the Vortex Oil and Gas Unit for Downhole Applications Vortex Flow LLC

Chamber Lift – A Technology For Producing Stripper Oil Wells – Stage II The Pennsylvania State University (Penn State)

Low Cost Wireless Communications-Based Pressure and Temperatures Tubel TechnologiesGauge for Production Optimization Applications

Design and Construction of a Low Cost Portable Oil/Water Production Testing Unit Advanced Resources International

Produced Water Treatment: Developing a Project to Market a Program to Texas A&M UniversityAllow the Sale of Treated Oilfield-Produced Brine for Beneficial Use

Building and Testing a New Type of Compressor for Stripper Well W&W Vacuum & Compressors Inc.Production Application

Plunger Conveyed Chemical System for Plunger Lift Wells Composite Engineers

Enhanced Real-Time Propellant Activation During Downhole-Mixed Fracture ReatimeZone Inc.Stimulation Process for Low-Permeability Stripper Wells

Pressure-Volume-Temperature Study of the Interaction of Nitrogen and Crude Oil Penn State

Sonication Stimulation of Stripper Well Production in East Gilbertown Field, Tech Savants Inc.West-Central Alabama

Restimulation of Three Under-Stimulated Shallow Gas Wells Coupled with the Lenape Resources Installation of Pumping Equipment to Accelerate Post-Stimulation Fluid Removal (partially funded)

Locating the End of Tubing for Efficient Production of Gas Colorado School of Mines (partially funded)

Modification of the GOAL PetroPump for Open-hole Applications Brandywine Energy & Development Co. (partially funded)

Table 1: Projects Selected for Funding by SWC in 2003.


field crude will be performed as well as com-puter modeling and additional field testsnecessary to define its applicability.

Low-Cost WirelessCommunications-BasedPressure and TemperaturesGauge for ProductionOptimization Applications –Tubel TechnologiesHydrocarbon producers are faced with sig-nificant challenges to maintain a well’s oper-ational and production cost-effectivenessbecause of large changes in electricity rates indifferent parts of the United States, volatilityof oil and gas prices, and unexpectedrequirements for intervention in the wells.Optimization of the processes required toproduce hydrocarbons constitutes an ongo-ing concern in the oil and gas industry. The

goal of this project is to develop a low-costgauge based on an existing commercialhigh-end wireless gauge developed by TubelTechnologies to monitor pump perform-ance, monitor fluid level to optimize liftingoperation and to lower lifting costs, andmonitor bottomhole pressure to optimizedrawdown and for buildup tests. Thebuildup tests will provide reservoir pressureinformation for the optimization of thehydrocarbon production.

This project will research, develop andtest a lower-cost, high-reliability, real-timewireless gauge composed of compressionalacoustic waves-based wireless communica-tions transmitting data in real time. The datawill be transmitted through the productiontubing, strain gauge pressure sensor and atemperature sensor for measurements ofdownhole pressure and temperature, as well

as a surface module to acquire the transmittedsignal from downhole and process the data.The new wireless gauge can be deployedanywhere in a production and injection well.The gauge will utilize low-power electronicsand sensor technology to acquire and processin real time well data related to productionand formation parameters. A battery packwill provide power for operation of the sys-tem downhole, and the battery operationallife is expected to be in excess of 5 years.

Design and Construction of a Low Cost PortableOil/Water Production Testing Unit – Advanced Resources InternationalThere are many marginal waterfloodplays operated around the country, such asOak Resources Inc.’s properties in Carter


Stripper wells are important to U.S. energy security, representing 15% of the oil and 7% of the gas produced.

County, Okla. As a matter of course, routineproduction testing of all wells is a standardpractice necessary for obtaining oil-waterproduction ratios. However, standard low-cost methods often lead to erroneous meas-urements because of low sampling fre-quency and the non-homogeneity of theproduction fluids. This non-homogeneityoften occurs because of variations in the pro-duction stream related to the flow regimeand its composition. Although productiontesting units are available with the capabilityof increased sampling frequency, therebyreducing the error because of fluid homo-geneity (increased sampling in shorter timeframes yields a significantly more represen-tative composition), these units can be cost-prohibitive (up to $50,000) to the marginal oiloperator. As a result, the operator often mustsacrifice accuracy for cost savings.

To meet this need, the AdvancedResources International project team willconduct a thorough review of possibleunit components, highlighting theiradvantages with regard to cost and relia-bility. This will culminate in a design rec-ommendation to Oak Resources Inc.,which will critically review the designprior to prototype construction. Field-test-ing will be concerned with sampling pro-duction streams from about 30 oil wellswith the new unit as well as the unitsemployed by Oak Resources.

Restimulation of Three Under-Stimulated Shallow Gas Wells Coupled with the Installation of PumpingEquipment to Accelerate Post-Stimulation Fluid Removal – Lenape ResourcesTens of thousands of gas wells were com-pleted in the Appalachian basin in the1970s and 1980s. The majority of thesewells were completed using the so-called“limited entry” perforation technique – alimited number of perforation spreadout over hundreds of feet of a target inter-val – coupled with a hydraulic fracture

stimulation, which utilized proppantconcentrations that current technologyconsiders inadequate. This limited entrytechnique often resulted in uncertain frac-ture geometry and a range of results. Aftercompletion, standard practice fluid recov-ery operations normally resulted in themajority of completion fluid remaining inthe wellbore/fracture years after the initialcompletion. As a result, a large number ofwells exist that have only produced asmall fraction (often less than 20%) of theoriginally estimated gas-in-place with con-servative drainage estimates. Such wellsmay generally be identified by their abilityto build shut-in well head pressure to with-in 75% to 80% of original shut-in pressure,yet they may exhibit a very low flow ratesoon after the initiation of production.

In an effort to demonstrate thesereserves are economically recoverable,Lenape Resources will re-stimulatethree shallow gas wells in its Lakeshorefield, Chautauqua County, NY. The fol-lowing steps will be performed as partof the project:

• perforate a selected small (10ft to15ft) pay interval with a high per-foration density (four shots/foot)

• pump a hydraulic fracture treat-ment containing about 60,000 lb ofproppant at a maximum final sandconcentration of at least 6 lb/galof fluid

• immediate ly insta l l pumpingequipment with surface facilitiessufficient to handle increased fluidvolumes

• collect production data and reportresults to SWC.

Locating the End of Tubing forEfficient Production of Gas -Colorado School of MinesRemoval of water and hydrocarbonliquids from gas wells is increasinglyrecognized as an important topic forlow-permeability gas reservoirs. A keyfactor is the location of the end of tubing(EOT) in the casing relative to the vari-ous gas-bearing formations that havebeen completed. If not removed, liquidsin the casing will cause two detrimentalconsequences. First, the backpressure ofaccumulated water on the perforationscauses decreased production rate. Second,back-flow of water from the casingthrough the perforations to the forma-tions can produce a “water block” thatprevents gas flow. There is little agree-ment in the engineering community onthe appropriate location for the EOT.

To address this problem, the ColoradoSchool of Mines will conduct a literaturesearch on the technology and begin conceptdevelopment for future model developmentfor properly locating the end of tubing foreffective production of gas. The work alsowill include flow loop testing.

Produced Water Treatment:Developing a Project to Marketa Program to Allow the Sale ofTreated Oilfield-ProducedBrine for Beneficial Use – Texas A&M UniversityA public/private/academic partnershipled by Texas A&M University has beencreated to identify mechanisms to payfor the treatment costs incurred in desali-nation of oil field brine. This project will



A public/private/academic partnership led by Texas A&M University has been created to

identify mechanisms to pay for the treatment costs incurred in desalination of oil field brine.


demonstrate that an unconventionalsource of fresh water can be obtained byproduced water treatment/desalinationto provide fresh water for beneficial use.This unconventional source of freshwater can then be used for industrialpurposes to substitute for scarce freshwater resources planned for communitywater needs. The value of this newresource makes it important to encour-age oil and gas operators to institutesuch practices where practical.

This partnership consists of the aca-demic researchers at Texas A&M Univer-sity, manufacturer Tarlton Supply, oiland gas producer Burlington Resourcesand the staff at the Texas RailroadCommission. Tests will be conducted atthe Burlington Resources facility sup-porting their drilling operations in theBarnett Shale play in North Texas. Waterproduced from fracturing will be treated.Once treated, the fracturing fluids canthen be re-used for subsequent welloperations. This eliminates the need fortransporting fresh water from the TrinityRiver and the need to haul recoveredbrine to offsite disposal wells. It isexpected that this cost savings in waterhandling plus the value of the freshwater resources saved by re-use will besufficient to pay for brine treatment/desalination. Estimates show more than40 million gal of fresh water could besaved in the Fort Worth Basin alone.

In 2001, the SWC funded Texas A&Mefforts to remove regulatory roadblockspreventing beneficial use of treated pro-duced water. The regulatory agency inTexas for the oil and gas industry (TexasRailroad Commission) recently has issued a

letter endorsing the A&M program andpledging to work with local and state agen-cies to implement projects.

The project’s objectives are: • to identify market mechanisms that

provide incentives to those willingto pay the costs of developing thisnew and unconventional source offresh water

• to demonstrate treatment/desalinationof oil field wastewater for re-use.

New technology used to process thewater produced with oil and gas opera-tions removes impurities and creates afresh water resource that can be used forbeneficial purposes. The project willconsist of short- and long-term field test-ing with full-size process trains to gatheroperations data on the desalinationprocess. This information will then beused to present the case for underwritingthe costs of this treatment.

Modification of the GOAL PetroPump for Open-hole Applications – Brandywine Energy & Development Co.During the past 2 decades within theAppalachian Basin, several tens of thou-sands of shallow oil and gas wells (100ftto 300ft) have been completed usingopen-hole techniques with multiplenotched, fractured and produced zones.These wells are often configured with 7-in.to 85/8-in. steel casing cemented throughthe water table aquifers, then open rockhole wellbore (61/4-in. to 77/8-in.) to thetotal depth of the well. These wells fol-low a similar production performancehistory as their predecessor-cased wells,that history being several months of

flush production followed by decreasingwell pressure and yield of oil and gas.These wells, like many others, fall with-in a relatively short period into the cate-gory of stripper well production. Down-hole pressure in these wells declines to apoint where the well is no longer able tolift the fluid in an unassisted manner tothe surface. Often in these multi-zonecompletion wells, an uphole zone willact as a thief for downhole higher-pres-sure producing zones, further complicat-ing their operation and production. Inongoing stripper well production fromthese wells, beam pumps, tubing velocitystrings, tubing and plungers, and otherconventional techniques often are employedwith some finite success. Most of thesetechniques do not allow the well to produceitself down (gas and oil) to something closeto the formation pressure. The net result ofthis is non-captured reserves and higheroperation cost for gas and oil produced.

The objectives of this project are toperform the engineering design requiredto apply the unique operational effi-ciencies of the GOAL PetroPump withstate-of-the-art reworking of openholeoil and gas wells. This project will buildupon the successful results of previousprojects in which the GOAL PetroPumpwas developed for cased holes. TheGOAL PetroPump is an elegant solutionfor the automatic lifting of fluids from oiland gas stripper wells. The simple designof the tool’s onboard valve controlallows it to free-travel within the well-bore, accumulating a predeterminedvolume of fluid above the tool, closing theself-actuating valve and delivering that fluidto the surface. The tool is “smart” in bothdirections, dropping downhole when pres-sure at the wellhead is low or reduced bydownhole fluid accumulation. The tool issmart uphole as well, using below-tool for-mation pressure to lift the tool and fluid(oil/brine) to the surface, subsequently free-floating in the wellhead lubricator andallowing downhole pressure/gas to flow tothe process unit. At such time as pressure


New technology used to process the water produced with oil and gas operations removes impurities and creates a fresh water resource

that can be used for beneficial purposes.

has declined below tool control pressure,the tool drops once again, repeating theautomatic pumping cycle.

Testing of the GOAL PetroPump Toolunder an existing SWC project in cased-perforated stripper wells has demon-strated 11/2- to three-fold improvedproduction at a fraction of the servicenecessary to operate other stripper welloperating systems. The current tool isdesigned to operate in downhole condi-tions of brine, oil, gas and condensateunder rigorous in-well chemical and pres-sure conditions. The tool will operate inwell conditions with pressure ranges of30psi to 600psi, lifting 0.1 bbl to 40.0 bbl offluid per tool cycle for 41/2-in. cased wells.

Building and Testing a New Type of Compressor for Stripper Well Production Application – W&W Vacuum & Compressors Inc.A novel type of variable capacity com-pressor has been developed to solvecompressor problems encountered inlow deliverability gas production opera-tions. The Weatherbee Positive Displace-ment Compressor/Vacuum Pump, apatented device, has the largest volumedisplacement-to-size ratio of any devicein the world. The spherical geometrydesign provides the largest internal vol-ume-to-surface area ratio possible sothat with each 360° revolution almost allof its internal volume is displaced.

The Weatherbee Pump also has aunique design feature in its capacity con-trol mechanism, which allows the rate ofthe device to be changed to meetincreased or decreased demands withoutincreasing the rotations per minute ofthe input shaft. This volume control fea-ture works like a throttle on an engine;set on high it can easily handle high vol-umes, and by throttling back the mech-anism, volumes are reduced, therebysaving on energy usage and operatingcosts. This device uses only the energy

necessary to compress the amount of gasthe well is actually producing. Thiscapacity control feature is a major sellingpoint for a majority of applications. Theease of sizing makes one pump appro-priate for various volume requirements.This feature will be particularly beneficialto applications where compression require-ments fluctuate or where volume can onlybe estimated and may vary drastically, as ingas well compression.

The Weatherbee Pump provides the fol-lowing advantages as compared to existingproducts of similar output capacities:

• substantially reduced size and weight• the versatility of the volume control

mechanism• reduced energy requirements• less maintenance and lowered

operating costs• ability to operate the pump with

input shaft turning either clockwiseor counter-clockwise

• ability to reverse the direction of flowwithout disconnecting the pump orchanging rotational direction of theinput shaft

• ability to perform a dual functionsimilar to one-half motor and one-half pump/compressor.

The objectives of this project will beto evaluate the new compressor conceptby constructing a model and testing itin a controlled environment. Once theprototype model has been proven, itis expected an additional project willbe undertaken to test the pump in afield application.

Plunger Conveyed ChemicalSystem for Plunger Lift Wells –Composite EngineersAs more demand is placed on the aginggas wells in the United States, there is aneed to better preserve the integrity ofthese wellbores. Many deep, marginalgas wells have been sold off to smallerindependents that cannot afford toreplace tubing strings, repair casing leaksor even add packers to patch these olderwells. Without mechanical failures, thesewells will continue to produce gas foryears. Research suggests 87% of plungerlift wells fail because of mechanical fail-ures, such as holes in tubing and/or cas-ing. These problems are mostly because ofcorrosion and aggravated tubing wearfrom plunger/tubing abrasion. In thepast, many attempts have been made toapply chemicals to plunger lift systemwith little success.

In this project, a simple and inexpensivechemical plunger lift system will be devel-oped and field-tested. It is projected onlysimple modifications will be required forthe plunger lubricator cap and plunger.Both components can be swapped out onexisting systems with common tools inless than an hour, typically. It is believedthe proposed system modification willpreserve the integrity of the wellboremechanics and in some cases extend awell’s ability to produce at a lower gas-to-liquids ratio based on today’s commonratio calculations. Scale, paraffin, hydro-gen sulfide, etc., can be treated on a con-tinuous basis with this system.



The Weatherbee Pump also has a unique design feature in its capacity control mechanism, which

allows the rate of the device to be changed to meetincreased or decreased demands without increasing

the rotations per minute of the input shaft.


Enhanced Real-TimePropellant Activation DuringDownhole-Mixed FractureStimulation Process for Low-Permeability Stripper Wells –ReatimeZone, Inc.The objective of this project is to develop anddemonstrate enhanced reservoir stimulationprocesses for stripper wells. Proprietary andpreviously untested experimental processeswill be tested that utilize a novel, chemicallyinduced in situ fracturing process combinedwith hydraulic fracturing stimulation.

One process includes the downholeblending of a mixture of propellants and var-ious activator agents or oxidizers, which arepumped separately (and safely) for reactionand generation of secondary fracturing energyin the hydraulically induced reservoir frac-ture. The propellants may be safely pumpeddown the casing for later staged admixturewith oxidizers to generate an energy releasein the near wellbore and formation fractures,concurrent with hydraulic fracturing. Thus,secondary fractures are generated to aug-ment the primary induced fractures createdby hydraulic fracturing. Theoretically thisprocess should result in significantly greaterfracture length extension and enhancedhydrocarbon flow to the wellbore.

The proposed admixture of propellantsand oxidizers, including encapsulated ortime-delay propellants and activators,occurs concurrent with ReatimeZone’spatented downhole-mixed stimulationprocess, whereby one stimulation compo-nent is pumped down the casing while thesecond stimulation fluid (gases and/orproppants may be included in either fluid)is pumped down the tubing and blendeddownhole. A second activated propellantfracturing approach includes pumping a

propellant-laden fluid into the reservoirfractures and then subsequently pumpinga second oxidizer-laden fluid into saidfractures, with the option of pumping afluid separation pad as deemed necessaryby the operator. This simple well comple-tion system is safe and easily utilized atthe wellsite and will enable dramaticimprovements in reserve recovery effi-ciency, safety, cost savings and overallreservoir fracturing success in terms ofobtaining extended fracture propagation.The field tests for this project will be per-formed in the Permian Basin.

PVT Study of the Interaction of Nitrogen and Crude Oil – The Pennsylvania State UniversityMembrane-generated nitrogen has severalapplications in the oil field. It is commonlyused in energized fluid drilling and work-overs, and in secondary and tertiary recov-ery projects. The nitrogen created usingmembrane technology is non-reagentgrade and contains oxygen as its principalcontaminant. The amount of oxygen gen-erated in the separation process varies fromnear-zero mole percent to as high as 5 molepercent and is a function of adjustment tooperating parameters of the equipment.However, the reality of the process is thatthe lower the amount of oxygen in terms ofmole percent, the lower the volume of gasgenerated. In most field operations, theoperators attempt to generate the maxi-mum volume of gas the physical condi-tions permit. Limitations generally are fromincreased corrosion of tubular goodsand/or the increased tendency for the for-mation of emulsions in produced fluids.

Therefore, the objective of this project isto develop a fundamental understanding of

the phase behavior of nitrogen-oxygengases in the presence of hydrocarbons. Toaccomplish this, extensive laboratory testswill be conducted using a conventional PVTapparatus. In order to generalize the resultsof these experiments, the resulting data willbe used to develop a computer programcharacterization of these fluids in the pres-ence of oil. The need for this generalizationis to provide to the producer a tool thatwould permit the design and optimizationof the projects involving these fluids.

Sonication Stimulation of Stripper Well Production in East Gilbertown Field, West-Central Alabama – Tech Savants Inc.This project will evaluate the use of sonica-tion as a stimulation tool in oil wells.Sonication energy, produced by convertingelectrical energy to mechanical energy,enters and moves laterally within the oil-bearing formation being stimulated, increas-ing the mobility of the oil through theaddition of energy, by lowering the oil’sviscosity and (perhaps) by cleaning thewellbore and perforations.

To demonstrate the effectiveness of usingsonication to stimulate production, threefield tests will be performed in the EastGilbertown field in west central Alabamausing various combinations of power inten-sity and frequencies. Following each of thefield tests is a 6-week period where theimpacts of the test are evaluated in terms ofincreased production of oil and water, varia-tions in production during time and the lat-eral extent of the impacted zone as reflectedin nearby wells. The final report will containall the data and test procedures, economicdata, conclusions and recommendations. ✧

For more information, please contact authorGary Covatch at [email protected],(304) 285-4589.

ReferencesInterstate Oil and Gas Compact Com-mission, 2002. Marginal Oil and Gas: Fuel forEconomic Growth, 2002 Edition.


The objective of the ReatimeZone, Inc. project is to develop and demonstrate enhancedreservoir stimulation processes for stripper wells.


HYDROCARBON MIGRATION

Clean-burning, energy-rich nat-ural gas is an increasinglydesirable hydrocarbon resource.

Gas can be retained in a basin for hundredsof millions of years (as in the Anadarko)yet vents almost continuously in activebasins such as the Gulf of Mexico Basin.Five years ago, the Gas Research Instituteawarded a research contract to CornellUniversity to examine the way gasmoves in the deeper portions of a veryactive basin. Could the capillary forcesthat arise when gas is present in grain-size layered sediments produce the verylow permeability surfaces, called seals,that divide basin interiors into compart-ments of variable and often veryhigh overpressure, and could thisaffect gas and hydrocarbon migration?Laboratory experiments reported from aprevious GRI-funded study suggestedthis was possible (Shosa and Cathles,GCSSEPM, 2002). But could it bedemonstrated in the field?

To be sure to catch all relevant processes,the GRI study cast its investigative net overa large (79-mile by 124-mile) area of the off-shore Louisiana Gulf of Mexico (Figure 1).What was caught was not so much animproved understanding of seals, which iscommented on only briefly in this article,but a clear view of unanticipated and pos-sibly more important processes. The studydiscovered and documented the dramaticand systematic effects gas can have on oilthrough a process called gas washing. Inthe north of the study area, more than 90%by weight (wt%) of the n-alkanes in reser-voired oil have been carried off by gas. Thepattern of washing decreases in a regularfashion to zero in the southern end of thestudy area. Modeling shows this variation

is expected from the changing pat-tern of sediment deposition.Modeling also shows the gaswashing and observed decrease inoleanane and increase in sulfur-bear-ing bensothiophenes to the south(the next clearest chemical trends inthe study area) are possible only ifvery little petroleum is retained inmigration conduits between thesource and the surface. The washingseems to take place in the deepestsand in any area, for example, thefirst sand encountered by upward-migrating hydrocarbons. The analy-sis shows the petroleum system inthe northern Gulf of Mexico is aflow-through system in which onlyabout 10% of the petroleum thatescapes from the source strata isretained in basin sediments and morethan 90 wt% is vented into theocean. The venting is happeningtoday through hundreds of seafloorsites, and known reservoirs have been filledvery recently. Therefore, the chemistry ofthe gas and washed oils carry informationon the current pattern of subsurface petro-leum migration relevant to exploration forsubsurface hydrocarbon resources.

The Offshore Louisiana Study Area Figure 1 shows a GoCAD image of thetop of salt (gray surface with spiky saltdomes) in the study area, which hence-forth will be called the GRI Corridor, andstratigraphic layers from four sites where3-D seismic data from the industry wasacquired and interpreted. The stratigraphy,all chemical analyses, and selected physicaland petroleum data are assembled in a

GoCAD project that is included with thesix-volume final report available fromGRI (GRI-03/0065). Corridor sourcerocks have a generative potential of1,400 billion bbl of oil and 8,600 Tcf ofgas; 2.6 billion bbl of oil and 45 Tcf of gashave been discovered. The top of overpres-sure (12 lb equivalent mudweight surface),determined from mudweight data in 2,131wells, is a highly irregular, spiky surfacethat cuts thousands of feet across stratig-raphy in many areas (Figure 2). Many,but not all, of the spikes are related tosalt domes. Temperature gradients canchange from about 65˚ to 76˚F per 0.62miles over distances of about 31 miles in acheckerboard pattern, which would dra-matically affect hydrocarbon maturation.

By Dr. Larry Cathles, Cornell UniversityGas: A Messenger from

Subsurface ResourcesA detailed chemical and modeling analysis of a 77-mile by 124-mile area of the offshore Louisiana Gulf ofMexico shows how gas venting from deep sources alters shallower hydrocarbons and carries informationthat could guide exploration.

Figure 1: This figure shows the location of the GRI study corridor in the offshore Louisiana Gulf ofMexico Basin. The base is the top of salt compiledfrom 2-D seismic data. Strata interpreted from 3-Dseismic data at four locations also are shown. SMI 9 is ChevronTexaco’s South Marsh Island 9 saltpiercement-related field, SEI 330 in Pennzoil’s (Devon Oil) South Eugene Island Block 330 field, and the southernmost stratigraphic package containsConocoPhillips’ Jolliet field.


Chemical analyses of 138 un-biodegradedoil samples show remarkably regulartrends in gas washing (Figure 3) andsource-related biomarker indices.

The spikes in the top of overpressuresurface complicate relating this surfaceto hydrocarbon phase separation of arelatively constant composition petro-leum. Leak zones appear to be localized

in faults and shearzones bounding saltsheets and diapirs.Once established, theypersist and becomeincreasing methane-r ich. Away fromspikes, the top ofoverpressure surfacecould be a phaseboundary, and itsdepth might be atleast part ly con-trolled by petroleumchemistry. Sufficientdata to test this pos-sibility was unableto be assembled. Thetemperature patternis significant and inter-esting. The general

temperature distribution in the corridoris that expected. Local anomalies are par-tially related to salt and variations in sedi-mentation rate, but that is not their fullexplanation, and they remain enigmatic tosome degree. Oil chemical variation turnedout to be the most interesting, surprisingand process-significant data.

Hydrocarbon ChemistryGas washing is measured bycomparing the mole fractions ofn-alkanes in an oil with the dis-tribution expected if the oil wereunaltered. In unaltered oils, themole fraction of n-alkanes decreaseexponentially with carbon num-ber, Cn. Figure 3 shows the n-alkane mole fractions in oneTiger Shoals oil peel off from theexponential trend at n~24. Theshaded zone is the missing oil.In this case, the missing oil rep-resents about 90 wt% of theoriginal Cn>10 oil. The north-south profile in Figure 3 plotsthe n-alkane removal in 138unbiodegraded oils cross theCorridor. More than 90 wt% of

the n-alkanes has been removed by gaswashing in the northern end of theCorridor (Tiger Shoals). All the oils therehave break numbers of ~24 and show~90 wt% oil removal. The washingintensity decreases in a reasonably regu-lar fashion from north to south. Nowashing is observed at the south end ofthe Corridor.

The chemistry of the Corridor oils isextensively discussed in the report citedabove. After gas washing, the nextmost process-significant aspect of theoil chemistry is the clear presence ofoleanane in the north but not in the southand a dramatic increase in sulfur-bearingbenzothiphenes to the south. This resultis interpreted to come from the matura-tion of two source beds: a carbonateJurassic one that extends uniformly acrossthe Corridor and a silicate Eocene onethat extends across only the northern halfof the Corridor. Eocene-sourced oilsshould contain oleanane, since theirsource is younger than mid-Cretaceousand plants containing oleanane hadevolved, and should be sulfur-poorbecause iron from the shale will precipi-tate sulfur as pyrite in the source. Jurassic-sourced oils, on the other hand, should besulfur-rich because carbonates containinsufficient iron to precipitate the sulfuras pyrite at their source and are too old tocontain oleanane.

The importance of these observationsbecomes clear when the evolution of theCorridor is reconstructed and petroleumgeneration and migration modeled. TheJurassic source lies at about a 9-miledepth in the Corridor. Unless the petro-leum retention in migration conduitsabove the source is less than ~0.5% ofthe pore space in the sediments, nopetroleum can escape the surface. Themigration fraction must be smaller thanthis because oil and gas are venting athundreds of seafloor localities. For theoil to have an Eocene signature, such ascontaining oleanane and being sulfur-poor, the later-generated Eocene oil mustdisplace the earlier-generated Jurassic oil.


Figure 2: A subset of the data defines the 12 ppg equivalent pressuresurface (white points) displayed against the krieged representation ofthe same 12-lb mud surface. The yellow square is South EugeneIsland Block 330. The krieged surface represents the pressure datareasonably well but fails to capture the full height of the peaks.

Figure 3: A total of 138 oils are analyzed for gas washing(left). The percent mass depletion of n-alkane compo-nents ≥C10 is defined as the gap between an unalteredoil with exponentially decreasing n-alkane mole frac-tions and the sample oil (shaded area). The graph on the right shows the regular decrease in the percent of n-alkane mass removed by gas washing from north to south across the GRI Corridor.

This is possible only if the migrationpore fraction is less than ~0.05%. If thisis the case, all the chemistry fits nicely.Figure 4 shows at a migration pore frac-tion of 0.025% the oil at Tiger Shoals (inthe north) is 89% Eocene and 51%Eocene in the middle of the Corridor.Furthermore, because the Jurassic sourceis now generating gas, the gas-oil ratio inthe migrating hydrocarbons is high enoughin the north and middle of the section(Figure 4b) to wash the Eocene oils asobserved. For 90 wt% oil removal, about4 lb of gas are required to wash each poundof oil. The migrating gas-oil ratio decreasesto the south such that we expect no gaswashing at the southern end of theCorridor, as observed.

A final matter of importance is thatequation-of-state modeling of the washingprocess indicates that the break number(Figure 3) is a direct measure of thedepth at which the oil is washed.Combining this with Corridor geologyat the four sites where 3-D seismic datasuggests the gas washing occurs in thedeepest sand at any locality. Hydro-carbons can be delivered at the rateneeded to fill known reservoirs asrecently as geologically indicated ifcollected from areas ~10 miles to 12 milesin radius (the scale of the salt-with-drawal minibasins in the area). Gas andoil mix in the deepest sand, and the oilis washed there. The hydrocarbons then

escape at a few localities along the faultedmargins of minibasins.

Conclusions and ImplicationsOil chemistry requires the petroleumsystem in the northern Gulf of Mexicobasin to be a flow-through system inwhich very little hydrocarbon isretained between the source and thesurface, and almost all (>90%) thepetroleum that escapes its source ventsinto the ocean. About 30% more hydro-carbons than have been produced andconsumed by humans throughout theentire petroleum era have vented intothe ocean from the small Corridor.Admittedly, this occurred during a fairlylong period of time (about 10 millionyears), but clearly humans and natureare promoting the same basic process(the venting of hydrocarbons).

Because so much gas is required towash the oils as observed, the washingprocess reflects major aspects of thesubsurface flow system. Overall, thepattern of washing in Figure 3 is regu-lar, but significant variations in wash-ing intensity occur in its mid-section.The variable washing in this area mustreflect variations in flow and mixing inthe migration conduits. For example,areas where oils are relatively intenselywashed must connect to subsurfacezones where gas is preferentially trans-mit ted compared with oi l , and

conversely areas where oils arecomparatively unwashed mustconnect to migration pathwaysthat transmit relatively little gas.Structures along major migra-tion conduits will have agreater probability of beingf i l led with hydrocarbons.Thus, analysis of the gas wash-ing pattern could help guideexploration to structures morelikely to be filled and morelikely to be filled with oil orgas. Washing may have othereconomic implications. Forexample, washing may cause

asphaltenes to precipitate in the sub-surface, and gas-washed oi ls maytherefore be less prone to precipitatethem in seafloor transmission pipes.✧

AcknowledgementsThe Gas Research Institute (GRI) carried outthis research at Cornell University, with achemical analysis subcontract to The WoodsHole Oceanographic Institution also supported.Many researchers and students worked on theproject during its lifetime. They are co-authorsin the GRI report. Steven Losh and MikeWizevich at Cornell, and Jean Whelan andLorraine Eglinton at Woods Hole were theprincipal contributors to the work summarizedhere. Peter Meulbroek discovered and mod-eled gas washing of the type described in hisCornell Ph.D. dissertation. The author wouldalso like to acknowledge the exceptionallyable guidance and support of Robert RichardParker, the GRI project manager for most ofthis project. Further information is availablefrom the final report (which includes aGoCAD project and spreadsheets of alldata), GRI-03/0065. Information is alsoavailable from the author, Lawrence M.Cath les , Depar tment o f Ear th andAtmospheric Sciences, Cornell University,Ithaca, NY 14853, (607) 255-2844,[email protected]; and RobertW. S ieg f r i ed , Associate Director EarthSc iences , Gas Techno logy Ins t i tu te ,(847) 768-0969, [email protected].



Figure 4: The gas-oil mass ratio of hydrocarbons migrating at the present day (a) is compared with thefraction of the oil in the migration conduits that is Eocene oil (b).

Kilometers Kilometers(a) (b)

HYDRATE FLOW ASSURANCE


Natural gas hydrates, whichoccur in permafrost and sub-sea sediments or in thick lay-

ers on the deepsea floor, are now consid-ered as a potential energy source for thefuture. The U.S. Geological Survey esti-mated in 1995 that U.S. hydrateresources total about 320,000 Tcf. Onthe other hand, gas hydrates also cancause serious operational problemswhen they form “slugs” inside gas pipe-lines, plugging valves and other trans-port facilities.

Traditionally, methanol and glycolshave been used by the industry to inhibithydrate formation in pipelines. Whenthese “thermodynamic inhibitors” areinjected in very large quantities – 30 wt%to 60 wt% – they alter the chemicalpotential of the aqueous or hydratephase and cause hydrate to dissociate(dissolve) at lower temperatures orhigher pressures. However, use of thermo-dynamic inhibitors can cost $60,000/d.There are some new-generation hydrateinhibitors described in the literature(Kelland et al; 1995), including, “kineticinhibitors” (KI) and anti-agglomerants(AA). The inventors of these materialshave made claims about their value, butthe industry has largely continued to usemethanol as an inhibitor. There is not yetsufficient confidence in new-generationinhibitors to warrant their wide use indeepwater field operations.

Kinetic inhibitors do not affect thethermodynamics of hydrate formation;instead, they delay hydrate nucleationand growth. They can be beneficial insome cases. Anti-agglomerants prevent

By Dr. Ram Sivaraman, Gas Technology InstituteUnderstanding the

Mechanisms of HydrateNucleation and InhibitionThe Hydrates Flow Assurance Facility at Gas Technology Institute (GTI) provides tools for understanding themechanisms by which hydrates form and grow.

Figure 1: GTI Acoustic Resonance Spectrometer

the aggregation of hydrate crystals,which allow these tiny crystals to bepumped through a gas line or valvewithout plugging. Both can be effectiveat low concentrations.

Understanding the mechanisms ofhydrate nucleation and formation will helpimprove knowledge of hydrate inhibitionand can lead to development of efficientnew inhibitors that can substantially reducethe costs of inhibitor treatment. GTI’sHydrate Flow Assurance Facility isequipped with state-of-the art instrumenta-tion and analytical equipment that can helpthe industry evaluate the potential benefitsof various inhibitor treatment options.

GTI Research of the Impact of Low-Dosage Inhibitors (LDIs) on HydratesThe solution to gas hydrate problems lies inthe development of new-generation hydrateinhibitors. Industry prefers to use inhibitorsat low-dosage levels in order to comply withstringent environmental regulations andcontrol costs. GTI has developed a worldclass hydrate flow assurance facilityequipped with state-of-the art technologiesin three laboratories at its corporate head-quarters campus in Des Plaines, Ill. In thisfacility, GTI has proven capabilities forscreening for the best low-dosage KI or AAand can help identify cost-effective inhibitorsfor use in deepsea pipeline operations.

An article published in the summer2002 issue of GasTIPS described the broaduse of laser imaging technology at GTI forhydrate management. The focus of thisarticle is GTI research on the kinetics andmechanism of hydrate formation and dis-sociation, with and without inhibitors. GTIhas a variety of acoustic (Figures 1-3) andcalorimetric tools (Figures 8-9) for con-ducting this research and has used thesetools to study the impact of thermo-dynamic inhibitors, KI and AA at variousdosages on hydrates formation.

Laboratory MeasurementsAcoustic Resonance TechnologyUpdate—Acoustic resonance technology

offers powerful insights into manyaspects of gas hydrates research. Whenacoustic waves are propagated through agas mixture confined to a sphere atreservoir conditions, the signal output atthe receiver carries all the changes it hasgone through during the phase transitionof the mixture and provides valuable infor-mation of hydrate onset and dissociation.

The high-speed digitization of acousticspectra of a reservoir fluid, which hasgone through hydrate phase transition,allows researchers to understand eventsthat occur very rapidly. The acoustictechnique is preferred for murky reser-voir fluids that cannot be studiedusing optical techniques to detect hydratesonset. By analyzing the acoustic signatures,



Figure 2: Acoustic Resonance Spectrometer control system.

Figure 3: Liquid nitrogen cooling system control.


powerful insights into the evolution ofthe event may be realized. Acoustic dataanalysis can provide quantitative datavaluable for developmental research.

The acoustic tool at GTI is an auto-mated 25mm spherical acoustic reso-nance spectrometer developed for preci-sion sonic speed measurements in livereservoir fluids. The system is capable ofpressures of 0 to 42 megapascals (MPa)or 6,000 psia and has a temperaturerange of 450˚Kelvin to 225˚Kelvin. Theheart of the system is a 25-mm spherewith two transducers. One transducer(transmitter) propagates acoustic waves

into the sphere in which the gas mixtureis confined to the reservoir pressures.The second transducer (receiver) receivesthe acoustic signal that has gone throughthe phase changes along with the gasmixture when the temperature condi-tions were changed. The system isshown in Figures 1 through 3. The sys-tem control has a function generator thatexcites the transmitter through an ampli-fied sine wave signal and generatesacoustic waves inside the sphere. Thesignal received is amplified by a low-noise amplifier and then sent through aLockin amplifier to pick out a clean

second radial mode (Figure 4) with ahigh signal-to-noise ratio. All this equip-ment is interfaced to the computer tocontrol test operations and acquire data.The temperature is controlled by a pro-portional temperature controller andmeasured by a 100-ohm platinum resist-ance thermometer. The pressure ismeasured through a Ruska differentialpressure gauge coupled with a pressurecontroller. Custom-made software hasbeen developed at GTI and integratedwith LabView.

The digital image of the radial modesignal is stored along with temperature


Figure 6: Comparison of current data for natural gas hydrate with models. Figure 7: Comparison of current data for gas hydrate with 20 wt%methanol with literature data and models.

Figure 4: Second radial mode resonance frequency peak. Figure 5: Acoustic determination of hysteresis of natural gas hydrate formation and dissociation.

and pressure data. Because of the sym-metry of the sphere, radial resonancemodes prevail rather than the tangentialmodes. The second radial mode wasidentified and tracked during coolingand heating runs. The software tracks aselected radial resonance mode duringthe temperature changes of the spheresuspended in a vacuum-jacketed bath.The cooling and heating of the systemsassociated with the equipment havebeen modified to accommodate thedynamic measurement mode using liq-uid nitrogen heat exchange coils, finsand double-walled vacuumed stainless-steel jackets for better temperature con-trol and low heat losses. Temperatureand pressure measurements along withthe radial mode frequencies are moni-tored in real time and recorded by thecomputer. The second radial mode reso-nance signal obtained for the natural gasmixture is shown in Figure 4. Figure 5presents the hysteresis of natural gashydrate formation and dissociation asdetermined from the acoustic data. Theacoustic frequency vs. temperature traceis the replica of the sonic speed vs. tem-perature for the second radial mode fromthe following sonic speed relation for agas confined in a sphere (Raleigh, 1896;Moldover 1986):

Where v is the sonic speed in meters/sec-ond, a is the radius of the sphere(25mm), f20 is the frequency of the sec-ond radial mode and γ20 is the respectiveeigen value (7.72525184) for the sphere.The sharp change in the frequency at theonset of hydrate phase transition isbecause of the sharp sonic speed changeat the entrapment of natural gas by thewater molecules to form hydrate crys-tals during the cooling process.During the heating process at the hydrateequilibrium temperature, the dissociationis completed and the mixture goes back toa single phase, confirmed by the overlap ofthe traces in Figure 5.

The hydrate onset wasdetermined to be 51.73°F(10.96°C) at a frequency of17,410Hz and a pressureof 1,154 psia, as shown inFigure 5. A close compari-son of GTI laboratoryresults with literature data(Ng and Robinson, 1985)and various models (HYSYS,2001, Sloan 1990) showsagreement (Figures 6-7)for a system without andwith methanol thermody-namic inhibitor, respectively.

Calorimetric Measure-ments Update—GTI estab-lished calorimetric meas-urement capabilities at

2 π a f20

20v



Figure 8: Differential Scanning Calorimeter at GTI flow assurancelaboratory.

Figure 9: The robotic arm and sample tray assembly of the Differential Scanning Calorimeter.


the GTI flow assurance facility forthree reasons:

• cost-effective control of hydrate for-mation in subsea production andfluid-transportat ion ne tworks ,to provide an acceptable margin ofsafety for hydrate inhibition over arange of subsea conditions

• improved characterization of hydratesas an energy resource, based onresearch to improve hydrate detectioncapabilities and to better understandmechanisms of hydrate formationand dissociation in laboratory-formedhydrates representative of Gulf ofMexico hydrates

• the collection of heat capacity datafor field samples from the Gulf ofMexico, Alaska and the CascadianMargin.

The differential scanning calorimeter(DSC) is a powerful tool to examinethe impact of inhibitors on the nucle-ation, growth and control of hydrates. Itis of great value in determining the effi-ciency of various inhibitors in the con-trol of hydrates at low dosages, infor-mation that could translate into millionsof dollars for a producing company

because of safer drilling and increasedgas production with minimum down-time. DSC measurements help researchersbetter understand how hydrates formand dissolve, leading to new tools thatcan help operators of pipelines andstorage systems keep the gas flowing tocustomers and ensure the safety ofgas-industry workers. Research resultswill also help the industry developenvironmentally friendly and low-costnew inhibitors to control hydrates.

The calorimetric tool installed at theGTI flow assurance facility is a MettlerToledo DSC 821 with a robotic armassembly (Figure 8-9) that can handleabout 35 samples in a single loading.Special high-pressure sample pans areused for field-sample heat-capacitymeasurements. The system was cali-brated by melting pure indium and bis-muth and by freezing pure water. Tetrahydro furan (THF) forms a Structure Ihydrate similar to that of methanehydrate, so calorimetric study using themodel THF hydrate system is analogousto the study of methane hydrate for allevaluation purposes. A predeterminedamount of THF and water mixture (1:17)

samples were taken in the 10-mg to 15-mgrange from all solutions and sealed in40-µL aluminum crucibles. Then thecrucibles were loaded in a robotic trayin a sequential order. Insertion tempera-ture of samples was kept at 77ºF (25ºC).One by one, the samples were cooledto –58ºF (-50ºC) to form hydrate andthen heated back to 77ºF to dissociatethe hydrate, at a 41ºF (5ºC)/min rate.The tests were repeated to get concor-dant values. Heat flow vs. temperatureand time were recorded for each sample.A trace analysis program was used toevaluate onset and dissociation temper-ature of THF-water hydrate from the heatflow vs. temperature data for sampleswith and without inhibitor. The resultswere analyzed to evaluate the impact ofinhibitors in controlling hydrate. A closecomparison was made of the efficiency ofmethanol, polyvinyl pyrrolidone, polyvinylcaprolactam and an anti-agglomorent(at different and low dosages) on StructureI THF hydrate (Figures 10 and 11). Theresults indicated that 20% methanol wasable to suppress the onset of crystallizationby 60.8ºF (16°C). However, 1% of PVCapwas able to suppress the hydrate


Figure 10: Comparison of low dosage methanol effects on tetra hydrofuran hydrate.

Figure 11: Comparison of the effects of a proprietary inhibitor on tetrahydro furan hydrate.

onset by 44.6°F (7ºC). The selected anti-agglomerant was also effective enoughto suppress the hydrate crystallizationby 53.6°F (12ºC).

Hydrate nucleation and growth kineticshave been investigated through timetemperature transformation (TTT) curvesusing the DSC, with and without 0.5%of PVP kinetic inhibitor. The experimentswere performed by rapidly quenching thesample to the experimental temperatureand the subsequent time until crystal-lization was measured. When performedover a range of temperatures, the resultswill give rise to the TTT curves as shownin Figure 12. The TTT curves separate thenucleation and growth kinetics. Theminima or the “nose” of the TTT curveindicates the maximum growth rate.So the best performance of an inhibitoris measured on the basis of the amount ofshift of the nose of the curve to longertimes and lower temperature. Comparisonof current crystallization data for theTHF model system with and withoutthe kinetic inhibitor shows good agree-ment with literature data (Koh et al.,2000) as shown in Figure 12. Figure 13presents the most recent heat capacity

measurements completed for a fieldhydra te sample f rom the Gul f o fMexico supplied by the U.S. NavalResearch Laboratory.

Field Testing and Future PlansField tests at the recently completedGTI/CEESI hydrate test loop at Nunn,Colo., will begin soon, with the meas-urements of gas hydrate formation anddissociation with and without lowdosages of methanol, using the GTIlaser imaging tool installed on theloop. GTI subcontract work for aDOE/CEESI project, Hydrate Control inGas Storage Wells and Gathering Linesduring Rapid Withdrawal Operations,has begun.

An addition of a T64000 Raman Spec-trometer to GTI’s Hydrate Flow Assurancefacility is in progress. The installationwill be completed during the summer2003. This will enable GTI to make real-time structural transition measurementsin natural gas hydrates, from Structure IIat low pressures to Structure I at highpressures, and to understand the plugdissociation kinetics. Test results areexpected to help the gas industry predict

the plug dissociation time as a functionof pressure and structure.✧

ReferencesRaleigh, J.W.S.: “Theory of Sound,”

Dover; New York. Sec.331 (1896).Moldover, M.R.; Mehl, J.B.: Greespan,

M.J.: “Gas-filled spherical resonators:Theory and Experiment,” J Acoust. Soc.Am.79, 253 (1986).

Ng, H.J, Robinson, D.B.: “Fluid PhaseEquilibria,” 21, 145 (1985).

HYSYS, Hyprotech, AEA Technology:“Process modeling using HYSYS work-shop course book” (2001).

Sloan, E.D., CSMHYD software, From:Clathrate Hydrates of Natural Gases, NewYork: Marcel Dekker, Inc. (1990).

Kelland, M.A., Svartaas, T.M., andDybvik, L.: “Studies on new gas hydrateinhibitors.” SPE 30695.

Koh, C.A.: “Controlling natural gashydrate formation and decomposition. Finalreport.” Contract No. 5094-260-2839. GasResearch Institute, Chicago, IL March (2000).

For more information, contact Dr. RamSivaraman at [email protected].



Figure 12: Time temperature transformation curves comparison of theeffects of PVP inhibitor on nucleation of tetra hydro furan hydrate.

Figure 13: Heat capacity vs. temperature data of a DSC scan for a field samplefrom the Gulf of Mexico showing ice and hydrate.

NEW PUBLICATIONS

NATURAL FRACTURECHARACTERIZATION USINGPASSIVE SEISMIC ILLUMINATION

Research by Lawrence Berkeley NationalLaboratory for Gas Research Institute(GRI) investigated the potential of usingmulticomponent surface sensor arraysand passive seismic sources in the formof local earthquakes to identify and char-acterize potential fractured gas reservoirsnear seismically active regions. In theirwork on passive seismic fracture detec-tion, researchers developed models forstudying elastic wave propagation inreservoir structures containing multiple,finite-length fractures. They also pur-sued an imaging method for fracturelocation and characterization using multi-component, passive seismic data recordedon a surface array.

Price: $35 for GTI members; $60 fornon-members, plus shipping and handling.

Document number GRI-03/0036. 21 pages. Final Report.

Order by E-mail from [email protected] or call (630) 406-5994.

PRODUCED WATERMANAGEMENT HANDBOOK

Designed for use by producers, this doc-ument presents data on the practices andcosts associated with produced watermanagement in oil and gas basins infive Rocky Mountain states (Colorado,Montana, New Mexico, Utah andWyoming) and five Mid-continent states(Illinois, Kansas, Louisiana, Michiganand Oklahoma). About 250 producerswere interviewed. The document alsosummarizes pertinent federal and stateregulations. Management methodsreviewed include injection, evaporation,surface disposal, reverse osmosis,freeze-thaw evaporation and downholegas/water separation, as well as otherrecycling/reuse strategies.

Price: $200 for GTI members; $250

for non-members, plus shipping andhandling.



EVALUATING POTENTIALECOLOGICAL IMPACTS AT E&PSITES: A COMPILATION OFSCREENING CRITERIA

Use of screening criteria for risk manage-ment decision making at hazardous wastesites helps operators to focus attention onsites that may truly benefit from the eco-logical risk assessment (ERA) process.However, not every site needs an ERA.This study is the first published, coordi-nated effort to identify precedents forusing screening criteria useful for riskmanagement at exploration and produc-tion sites. The criteria evaluated fall intothree broad categories: environmental per-formance criteria, wildlife exposures andregulatory protection.

Price: $35 for GTI members; $60for non-members, plus shipping andhandling.



DEVELOPMENT OF STIMULATIONDIAGNOSTIC TECHNOLOGY

This report summarizes 11 years ofdevelopment (1991-2002) of stimula-tion diagnostic technology in the areasof in situ stress, natural fracturing, stim-ulation processes and fracture diagnos-tics. Work done during this lengthyprogram included stress, natural-fractureand st imulat ion analyses ; M-Siteexperiment work; development of micro-seismic diagnostic processing algo-rithms and software; downhole tilt-

meter analysis; and service applicationsof microseismic technology as a diag-nostic tool for the petroleum industry.The field experiments described havehelped producers optimize hydraulicfracturing and field development.




HYDRAULIC FRACTUREDIAGNOSTICS

This report provides details about thedevelopment of the theory, hardware andsoftware for hydraulic fracture mapping,plus efforts to develop improved micro-seismic and downhole tiltmeter hydraulicfracture mapping technology. These tech-nologies are used to map treatments innatural gas wells in order to optimizestimulation and field development. Forexample, work on microseismic monitor-ing included evaluation of existing third-party seismic arrays; development of soft-ware needed to transform a researchsystem developed by Sandia NationalLaboratory into a robust, field-ready pack-age; and investigation of microseismicsource mechanisms. Tiltmeter researchfocused on development of new tools topermit wider application, improvementsto offset-well tools and upgrades tothe current software analysis package.Appendices describe related field evalua-tion work as well as subcontractor reports.





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COGA: 15TH ANNUAL ROCKYMOUNTAIN NATURAL GASSTRATEGY CONFERENCE

Aug. 4-6, DenverAmerica is confronting an energy dilem-ma aggravated by peaking and decliningproduction in its traditional natural gasprovinces. The gas-rich basins of theRocky Mountains are home to a“Persian Gulf of Gas” that is centrallylocated, minimally explored and justbeginning to be harvested. Details at www.coga.org

GASWEEK CONFERENCE &EXHIBITION: INCORPORATINGGAS SUPPLY EXPO

Sept. 23-25, HoustonThe GasWeek conference is a uniqueblend of business and technology issuesthat impact the industry, from pro-duction through consumption. Expertsthroughout the industry will addresshigh-level strategic sessions and in-depthindividual sector challenges. Details at www.gassupplyexpo.com.

SOCIETY OF PETROLEUMENGINEERS (SPE) 2003 ANNUAL TECHNICALCONFERENCE AND EXHIBITION

Oct. 5-8, DenverThis event at the Colorado ConventionCenter will include presentation of morethan 500 technical papers in 13 topicareas on subjects ranging from drilling,well completion and well stimulation toformation evaluation, reservoir monitor-ing, and management and information.More than 200 exhibitors also will takepart. Details at www.spe.org.

NATURAL GAS TECHNOLOGIESII: INGENUITY AND INNOVATION

Feb. 8-11, 2004, PhoenixThis is the second Gas TechnologyInstitute-sponsored conference and exhi-bition designed to showcase new anddeveloping natural gas technologiesfrom across the industry. To be held atthe Pointe South Mountain Resort, theconference is co-sponsored by TheStrategic Center for Natural Gas of the

U.S. Department of Energy’s NationalEnergy Technology Laboratory. Details at www.gastechnology.org.

14TH INTERNATIONALCONFERENCE & EXHIBITION ONLIQUEFIED NATURAL GAS (LNG)

March 21-24, 2004, Doha, QatarThis triennial conference is sponsored byGas Technology Institute, the InternationalGas Union and the International Institute ofRefrigeration, with additional sponsorshipsupport from many large corporations andorganizations involved in the LNG industry.Details at www.lng14.com.qa.

INTERNATIONAL GAS RESEARCHCONFERENCE (IGRC)

Nov. 1-4, 2004, Vancouver, B.C., CanadaHeld every 3 years, IGRC is recognizedworldwide as the major forum devotedto the exchange of the most recentnatural gas research, development anddemonstration results. This will mark theninth presentation of the IGRC. Details at www.igrc2004.org.


EVENTS

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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 and Gas Processing Center1700 S. Mount Prospect RoadDes Plaines, IL 60018-1804Phone: (847) 768-0908; Fax: (847) 768-0501E-mail: [email protected]

GTI E&P and Gas Processing Research (Houston)222 Pennbright, Suite 119Houston, TX 77090Phone: (281) 873-5070; Fax: (281) 873-5335E-mail: [email protected]/GTI: Phone: (281) 873-5070 ext. 24TIPRO/GTI: E-mail: [email protected]

IPAMS/GTI Office518 17th St., Suite 620Denver, CO 80202Phone: (303) 623-0987; Fax: (303) 893-0709E-mail: [email protected]

OIPA/GTI Office3555 N.W. 58th St., Suite 400Oklahoma City, OK 73112-4707Phone: (405) 942-2334 ext. 212 Fax: (405) 942-4636E-mail: [email protected]

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

U.S. Department of Energy National Energy Technology Laboratory Strategic Center for Natural Gas3610 Collins Ferry RoadMorgantown, WV 26507-0880Web site: www.netl.doe.gov/scng

National Energy Technology LaboratoryStrategic Center for Natural Gas 626 Cochrans Mill RoadPittsburgh, PA 15236-0340

National Petroleum Technology OfficeOne W. Third St.Tulsa, OK 74103-3519Web site: www.npto.doe.gov

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

CONTACT INFORMATION

gastips spring 2003 - citeseerx

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