Perspectives From The Chairman

Environmental Corner . . . . . . . . . . . . .3Tech Transfer Track . . . . . . . . . .4–6State-of-the-Art Summary . . . . . .7–9

DOE Digest . . . . . . . . . . . . . .10–11Industry View . . . . . . . . . . . . . . . .12PTTC Tech Info . . . . . . . . . . . . . .13Upcoming PTTC Events . . . . . . . . .15PTTC is a national not-for-profit informa-tion network formed in 1994 by oil andnatural gas producers. Programs are fund-ed by matching funds from the USDepartment of Energy (DOE) with fundsfrom State Governments, Universities,State Geological Surveys and Industry.This program would not be possible with-out contributions from the DOE Office ofFossil Energy through the National EnergyTechnology Laboratory (NETL).

In This Issue

P e t r o l e u m T e c h n o l o g y T r a n s f e r C o u n c i l W W W . P T T C . O R G

Vol. 11, No. 1 1st Quarter 2005

DOE Natural Gas & OilR&D Funding at High Risk

Those of us working closely with DOEare well aware that the Administration'sFY06 Budget proposes "orderly termi-nation" of DOE's natural gas and oilR&D program. With this terminology,"at high risk" is certainly a true state-ment. Around the domestic oil patch it'ssurprising how many people don't knowabout this plan for stopping investmentin technologies for proven reserves thatare increasingly difficult to recover.

Recent historical funding levels forDOE natural gas and oil R&D havebeen in the $75 million per year range.At that level, DOE can support strategiclonger-term R&D (Hydrates), fielddemonstrations of emerging technolo-gies (Technology Development withIndependents), technologies targetingmature stripper well operations (theStripper Well Consortium) and technol-ogy transfer (PTTC) that stimulatesapplication of underutilized or newtechnologies. DOE is also an advocate

Brian Sims, Independent from Madison, Mississippi, took over asPTTC's Chairman in mid-March. His leadership culminates years ofinvolvement in PTTC's Eastern Gulf Region and on the NationalBoard of Directors. Sims has 23 years of experience in oil and gasexploration, development and production, principally in the onshoreGulf Coast Region. Prior to 1991 Mr. Sims worked 10 years as ageologist in various capacities for Clayton W. Williams, Jr., Inc. inJackson, Mississippi and Houston, Texas. He received his B.S.degree in geology from Millsaps College in Jackson. He is past pres-ident of the Mississippi Geological Society and is a member of sev-eral oil and gas associations.

Here's the environment the E&P industry faces as I begin my stint at PTTC's helm. Strainednatural gas and oil supply, combined with unpredictable volatility in the pricing market haschanged the way we do business today. Certainly activity has increased and there are furtheropportunities to be pursued, however the risk in decision making has also increased propor-tionally. Human and equipment resources utilized by industry are at the upper limits acrossall sectors. Product prices are high, but cost of equipment/services is also up so there is thatever-present pressure on profit margin. Independent producers will have to adapt in order tocontinue to supply the majority of the nations natural gas needs and play a significant role inbrownfield reserve production from marginal wells.

To realize the opportunities in front of them, producers must work smart, which ofteninvolves integrating new technologies or approaches into the way they do business. Learningabout these newer technologies in a time-efficient manner is critical. That's why I've madethe commitment I have to PTTC and its "Connection" role. Part of that connection role ishelping industry understand, participate in, and benefit from federal investments in naturalgas and oil R&D. Those investments themselves are under pressure as the U.S. strives forfiscal discipline in government.. Its time to fulfill the promise made on a common oilfieldbumper sticker of the past— "Lord, just give me another oil boom and I promise I won'tscrew it up." As an industry let's deliver — for ourselves and the country.

In the next year I'm focusing my attention on three areas where I think PTTC can improveupon already solid services.

Volunteer direction. PTTC's activities deliver value when its workshops, newsletters, casestudies, and websites address those technology concerns domestic producers face. We havean existing network of volunteer advisors at the regional and national level and we get feed-back from the thousands who come to our activities every year. We find though that "themore specific one gets" in expressing what they want to learn about, the more on target thetopics, subtopics and speakers in our workshops become. One of my goals is to impress uponPTTC's audience the importance of "communicating to" their regional Producer AdvisoryGroup. When producers run with knowledge they gain, we also need them to share their casestudies and provide the data to demonstrate the impact our technology transfer activities arehaving.

Leverage. Everyone is busy, so it is critical that when producers do spend time learningabout new technology they get the most for the time invested - practical bottom line insightsmust be delivered and that's what PTTC does best. For those in outlying areas where its notfeasible to attend, I want PTTC to improve at making insights and information from work-shops available online. Online training is not quite like being there, but it can be close. Doingso also helps PTTC better leverage its financial and human resources.

Cont. on page 2

Cont. on page 2

2

News In General

Meeting AlertsSPE/ICoTA Coiled

Tubing Conference

April 12-13, 2005Woodlands, TX

http://www.spe.org/spe/jsp/meeting/0,2460,1104_1535_2540652,00.html

Network News

Cont. from page 1, Perspectives From The Chairman

Permanence for PTTC. Federal dollarsthrough DOE's natural gas and oil program,state/university cost-share matches, andindustry contributions (primarily time andexpenses) currently provide PTTC'sresources. It's no secret that the federalresources are what starts the whole process.Stabilizing that federal investment for thelong-term is critical for PTTC's permanence.There are other federal opportunities we arelooking at to diversify or expand activities.With consistent funding, state contributionswill remain strong. PTTC has performed mul-tiple analyses demonstrating the impact tosupport this public funding. Permanence alsoinvolves increasing industry's "green dollar"contribution. PTTC delivers value to the ser-vice sector by cost-effectively connectingwith producers, so we're working with themto increase their participation. The transfer oftechnology insights improves the skill set ofindividual professionals within producers andthe consultant sector. We're looking at waysfor individuals, and possibly the companiesthat employ them, to get more involved.

Service companies and especially the largeservice companies are becoming more andmore focused on the large international mar-

kets. PTTC has played an extremely impor-tant role in helping the service companiesunderstand the needs of the independents andfocus some research and training towardstheir needs. Still, the major R&D dollars inthe oil service sector come from the majorservice companies, which are international,and those dollars follow the highest return oninvestment, which is typically higher volumeproducing wells outside the U.S. Since 80%of our domestic production comes from inde-pendents that typically lack the ability to testnew technology and the service providershave many opportunities to test outside theU.S., this leaves domestic producers in atechnology vacuum. Those technologies com-ing from the international arena generallyneed adaptation for the low flow volume,lack of natural flow and smaller hole sizes indomestic wells.

In closing this article, let me state that I wel-come input from all concerning PTTC'sstrategic direction. Feel free to contact me(bsims1@jam.rr.com) or Don Duttlinger,PTTC's Executive Director (dond@pttc.org).PTTC exists to serve the domestic industry.Help us continually improve that service.

IPAA Oil and Gas Investment Symposium

April 18-20, 2005New York, NY

http://www.ipaa.org/meetings/MeetingInfo.asp?ID=51

SPE Production Operations Symposium

April 17-19, 2005Oklahoma City, OK

http://www.spe.org/spe/jsp/meeting/0,2460,1104_1535_2739324,00.html

IADC/SPE Managed Pressure Drilling Conference

April 20-21, 2005San Antonio, TX

http://www.spe.org/spe/jsp/meeting/0,2460,1104_1535_2672599,00.html

Southwestern Petroleum Short Course

April 20-21, 2005Lubbock, TX

http://www.pe.ttu.edu/SWPSC/index.html

Michigan Field Experiences, Focus on the Antrim: A full day (14 speakers), 12 exhibits and threecores on display. Bill Harrison, Michigan Basin Core Research Laboratory, points out a feature in acore. 185 people spent their day effectively attending this workshop co-sponsored by MichiganSatellite Midwest PTTC, Michigan Basin Geological Society, and Northern Michigan SPE.

Williston Basin Horizontal Well &Petroleum Conference

April 24-26, 2005Regina, Saskatchewan, Canada

http://www.ir.gov.sk.ca/Default.aspx?DN=4025,3383,3384,2936,Documents

SPE ATW: Modeling &Optimization of Smart Wells

April 25-26, 2005Huntington Beach, CA

http://www.spe.org/spe/jsp/meeting/0,2460,1104_1535_3097949,00.html

Offshore Technology Conference

May 2-5, 2005Houston, TX

http://www.otcnet.org/

Michigan Field Experiences: Focus on the Antrim

DEA Challenges for Deep Gas; What Are Our Limits?

May 24-25, 2005Galveston, TX

http://www.iadc.org/conferences/DEA_2005.htm

for our industry providing valuable informa-tion to counter unnecessary regulations, aswell as what incentives are best to assuredomestic supply. All these are now at risk.

The only way the budget will be restored isthrough Congress and the Appropriationsprocess. Congress has reorganized this yearand a new subcommittee now provides fund-ing for DOE. Many committee members arenot familiar with our industry or the DOEFossil Energy Program. Congress must be bet-ter informed about the impact the termination

of DOE's programs will have on you, yourcompany and domestic production—both nearand long term. Now is the time to express youropinion about the resources that circulate backthrough the industry, exhibiting a multipliereffect in the domestic economy. TheIndependent Petroleum Association ofAmerica provides a convenient service forexpressing your views. (http://grassroots.ipaa.org/lookup.asp?g=ipaa) Elected repre-sentatives value your informed industryinsights.

Cont. from page 1, DOE R&D Funding at High Risk

3Network News

Environmental Corner

Natural Gas Leak DetectionSystems Tested at RMOTC

In late September 2004, DOE's NationalEnergy Technology Laboratory sponsoredfield tests of advanced technologies forremote sensing of natural gas leaks at theRocky Mountain Oilfield Testing Center(RMOTC) in Wyoming. RMOTC simulated apipeline system about 7.5 miles long with 15leak sites with rates ranging from 1 scfh to5,000 scfh. There were different leak releaseoptions, even some decoys, so technologiesbeing tested were truly put to the test.

Tested technologies included: passive infraredmulti-spectral scanning, laser-based differen-tial absorption LIDAR (Light Detection andRanging), hyperspectral imaging, and tunablediode laser absorption spectroscopy. Sensorsystems were mounted in an unmodifiedautomobile, a helicopter, or a fixed-wing air-craft. Equipment providers included En'UrgaInc., ITT Industries, Inc. LaSen, Inc.,Lawrence Livermore National Laboratories,and Physical Sciences, Inc.

Test results confirm that many of the leaksites were found. General observations fromthe test results are:

· Leak rates of 500 scfh or higher weredetected at least 50% of the time.

· Leak rates of 100 scfh were only detect-ed 15% of the time.

· Leak rates of 15 and 10 scfh were onlydetected about 5% of the time.

· The 1 scfh leak rate was never detected.

· There were a large number of "falsepositive" leak sites identified.

With a week of testing, some equipmentproviders were able to make improvementsduring the week, while other providersdefined modifications for future work. Therewere also lessons learned about proceduresfor conducting future leak detection fieldtests.

The full report (7.3 mb) is available online atwww.netl.doe.gov/scngo/Natural%20Gas/publications/t&d/final%20Report_RMOTC.pdf.

DOE Releases LNG Safety Study

DOE recently released a Liquefied NaturalGas (LNG) safety and security study conduct-

ed by Sandia National Laboratories. Whileaccepted standards exist for the systematicsafety analysis of spills or releases from LNGstorage terminals on land, no equivalent setof standards exists for safety or consequencesof LNG spills over water. The report reviewsseveral existing studies of LNG spills withrespect to their assumptions, inputs, modelsand experimental data.

The following conclusions, which are only apartial list, were developed by Sandia:

· Risks from accidental LNG spills, suchas from collisions and groundings, aresmall and manageable with current safe-ty policies and practices.

· Consequences from an intentionalbreach can be more severe than thosefrom accidental breaches, but theseintentional breach risks can be signifi-cantly reduced with appropriate security,planning, prevention and mitigation.

· The most significant impacts exist with-in approximately 500 m of a spill, due tothermal hazards, with lower publichealth and safety impacts beyondapproximately 1,600 m.

· Although large, unignited LNG vaporreleases are unlikely, they could spreadover distances greater than 1,600 m (to2,500 m for a nominal intentional spill).

Sandia noted that modeling the dynamics anddispersion of a spill over water is hamperedby (1) very limited historical and empiricalinformation since current LNG ship designand safety procedures have reduced accidentsgreatly and (2) the experimental data that areavailable are more than 100 times smallerthan spill sizes currently being postulated forsome intentional events.

The full Sandia report is available online atwww.fe.doe.gov/programs/oilgas/storage/lng/sandia_lng_1204.pdf.

Canadian Provinces Added toTwo DOE Regional

Sequestration PartnershipsDOE recently announced that Alberta andBritish Columbia have joined Saskatchewanand Manitoba as Canadian partners in theRegional Carbon Sequestration Partnershipsprogram. The Department of Energy selectedseven original partnerships in August 2003.With the addition of organizations fromAlberta and British Columbia, the partner-

ships now include 216 organizations spanning40 states, three Indian nations, and fourCanadian provinces.

Plains CO2 Reduction Partnership. InJanuary 2005 Alberta joined Manitoba andSaskatchewan as Canadian provinces partici-pating along with nine states (from Iowa toMontana/Wyoming) in the Plains CO2Reduction Partnership. Alberta shares manyof the geologic and physiographic character-istics of the existing partnership region. TheAlberta Energy and Utility Board and AlbertaEnvironment will contribute information onAlberta CO2 sources, transportation infra-structure, and the vast geologic formations tothe partnership's geographic information sys-tem and decision-support tools. DucksUnlimited Canada will expand their work oncharacterizing the potential for Prairie PotHole Region Wetlands in Alberta to sequestercarbon and offset other greenhouse gas emis-sions through future restoration projects.

West Coast Regional SequestrationPartnership. British Columbia joined sixstates in the West Coast Regional CarbonSequestration Partnership in December 2004.British Columbia has a significant amount ofhydrocarbon-bearing sedimentary basins thatcould be used to store CO2 while simultane-ously enhancing recovery. Within these sedi-mentary basins are saline reservoirs that havehuge potential storage capacity but need bet-ter characterization. In addition, several min-eral deposits exist that could be used to per-manently store carbon dioxide by convertingit to a solid material. The British ColumbiaMinistry of Energy and Mines, which hasprevious experience characterizing their geo-graphic area for sequestration opportunities,has created a database of potential sequestra-tion sites, CO2 sources, and transportationinfrastructure.

View DOE techline at www.netl.doe.gov/pub-lications/press/2005/tl_sequestration_cana-da.html. For information on all regionalsequestration partnerships, visit www.fossil.energy.gov/programs/sequestration/partner-ships/index.html.

EPA’s Natural Gas STAR Program

Producer’s Tech Transfer WorkshopCo-sponsored by Devon Energy Corporation

April 20, 2005Oklahoma City, OK

http://yosemite.epa.gov/oar/gasreg.nsf/content/Producers2.htm

4Network News

Tech Transfer Track

Horizontal Barnett Shale Wells, To Cement or Not

Horizontal drilling is now commonly used inthe Barnett Shale. Pinnacle Technologieslooked at Devon Energy's first 23 horizontalwells in the "Core" area. All horizontal pilotwells were cased for borehole stability and,by number were about equally cemented andun-cemented. The laterals were 1,000-4,000ft in length. Current waterfracs are large, andwith longer horizontals, multiple stage fracsare required.

Pinnacle noted that, "while cemented hori-zontal wells allow for more control of frac-ture initiation locations, problems are oftenencountered in achieving fracture initiation.Excessive near wellbore pressure losses withaccompanying low injection rates and hightreating pressures are often observed incemented wells. Procedures to alleviate theproblem including re-perforating, jet cuttingholes, acidizing, and pumping gel and sandslugs are not 100% successful. These stepsadd time and cost compared with a problem-free treatment."

The logical question then becomes, to cementor not. Pinnacle evaluated production data, ona MMCFD/1000 ft of horizontal lateral lengthbasis, for "cemented" versus "uncemented"wells. There is a compelling graph (Fig. 4) intheir newsletter that reveals that uncementedcompletions have a statistical productionadvantage over cemented completions in thepilot area.

The article is an interesting read. Those play-ing the Barnett are urged to read the entirearticle. Excerpted from PinnacleTechnologies, Inc. Winter 2005 newsletter,which can be viewed online at www.pin-ntech.com/subs/newsletters_list.html.

Missed the CO2Conference in Midland?

The annual CO2 Conference in Midland hasbecome the premier CO2 flooding event inthe industry. Those of you with an interest inCO2 flooding who were unable to attend lastDecember's event are encouraged to read anextended summary published in the American

Oil and Gas Reporter's February 2005 issue.Developed by Steve Melzer, director of theConference, the article briefly summarizesseveral case studies from fields in severalstates and the interplay of CO2 flooding withthe growing carbon sequestrationmovement.

USGS Yukon Flats (Alaska) O&G Potential

Yukon Flats is a region of low, forested hillsand flatlands with numerous streams andlakes, situated generally to the east of theTrans-Alaska Pipeline System in east-centralAlaska. U.S. Geological Survey (USGS) sci-entists recently finished their first detailedassessment of the undiscovered oil and gaspotential of the Yukon Flats TertiaryComposite Total Petroleum System.

The assessment indicates the probable exis-tence of technically recoverable oil and gasresources, with mean estimates of about 5.5trillion cubic feet of undiscovered natural gas,173 million barrels of undiscovered oil, and127 million barrels of natural-gas liquids inconventional accumulations. These volumesare those that are technically recoverableusing current technology and that have thepotential to be added to reserves in a 30-yearforecast span. The assessment was based on acomprehensive review of available informa-tion, including new data from USGS fieldand laboratory studies.

No petroleum production has been obtainedfrom Yukon Flats, with the one exploratorywell finding small quantities of natural gas.

The Yukon Flats National O&G AssessmentFact Sheet 20045-3121 is available athttp://pubs.usgs.gov/fs/2004/3121.

Generating Pipeline-ReadyNatural Gas From Abandoned

Coal MinesA unique technology developed by EngelhardCorporation is enabling a Southern Illinoisgas producer to treat and sell gas from aban-doned coal mines and contaminated natural

gas that would otherwise remain unrecoveredin shut-in wells. By implementing EngelhardMolecular Gate adsorbent-based technology,Grayson Hills Energy, LLC is removingwater, nitrogen (N2) and carbon dioxide(CO2) from gas produced from its coal minesand natural gas wells.

A system is offered as a prefabricated, modu-lar plant based on patented Molecular Gateadsorbent materials and separation process. Itis generating significant interest among gasproducers due to its economical processingcost, easy start-up and operation, and envi-ronmental friendliness.

The Engelhard technology enables GraysonHills Energy to treat up to 2.5 MMscfd. Thesystem is located at the wellhead and is pow-ered by an on-site gas-driven generator thatuses tail gas from the Molecular Gate adsor-bent-based process as fuel. The facilityincludes an integrated dehydration unit toremove water and simultaneously removesabout 7% carbon dioxide and 12% nitrogenwhile delivering product with less than 4%nitrogen; as required by the interstatepipeline. The process operates by adsorbingcontaminants at high feed pressure whiledelivering the product sales gas with minimalloss of pressure. This ability to delivermethane at near feed pressure minimizescompression requirements. The technology isoffered as a modular packaged plant throughan engineering and fabrication partner.

For more information, visit Engelhard's web-site www.engelhard.com/Lang1/xDocID54651F74B5FA4F78B7454D4E19D0CDF8/xDocTable_Market/Tab_Overview/MarketID54651F74B5FA4F78B7454D4E19D0CDF8.

PTTC recognizes that products and services featured in “Tech Transfer Track” may not be unique and welcomes information about other upstreamtechnologies. PTTC does not endorse or recommend any of the products or services mentioned in this publication, even though reasonable steps aretaken to ensure the reliability of information sources. Input can be directed to HQ@pttc.org.

7th Annual Unconventional Gas Conference

(Canadian Society for Unconventional Gas &Petroleum Technology Alliance Canada)

Nov. 8-10, 2005Calgary, Canada

Soliciting presentations, contact KerriMarkle at kmarkle@csug.ca

5Network News

Tech Transfer Track

ASP Process For MatureOklahoma Fields

Cano Petroleum (Cano) is a recently formedindependent that specializes in increasingproduction from mature fields using enhancedrecovery methods, and field proven alkaline-surfactant-polymer (ASP) flooding is one ofthe key tools in their arsenal.

Recent Oklahoma acquisitions where Cano isexploring ASP flooding include theDavenport Unit (Prue Sandstone) in LincolnCounty and the Nowata Field (BartlesvilleSandstone). In the Davenport Unit Canodrilled and cased two new wells. Data andlogs from these new wells are helping designan ASP process for this field. Design of thechemical program is anticipated by year-end2005 with the program expected to com-mence soon thereafter. Chemical design isalso underway in the Nowata Field, where itis believed that an additional 20-30% of theOOIP could be recovered through ASP flood-ing. As with the Davenport Unit, designshould be completed during 2005. Surtek Inc.(www.surtek.inc) is working with Cano indesigning the ASP processes.

Surtek's website summarizes performance inASP projects. In the Daqing Field in China, apilot recovered 25% of the OOIP. In a 760-acre Canadian project 14.9% of the OOIPwas recovered. Chemical costs for differentprojects, cited in Surtek's website, range from$0.79 to $3.74 per bbl of incremental ASPoil. With current oil price trends, that type ofperformance leads to opportunities.

Three critical steps in ASP process design are:· Fluid design· Fluid-rock compatibility· Linear and radial core flooding

Surtek notes that it typically takes from six tonine months to complete the different stagesof testing for ASP evaluation. Field executionincludes proper mixing and injection ofchemical solutions, quality control, and moni-toring produced fluids and chemicals.

Content excerpted from "ASP TechnologyImproves Oil Recovery," American Oil andGas Reporter, February 2005. Readers arealso encouraged to view (1) an interview withCano staff in February issue of SPE's Journalof Petroleum Technology www.spe.org/spe/jpt/jsp/jptmonthlysection/0,2440,1104_0_3431816_3432514,00.html and (2) Surtek'swebsite.

OTC 2005 DistinguishedAchievement Awards

The Offshore Technology Conference's(OTC) Distinguished Achievement Awardsfor 2005 are:

For Individuals goes to Kim Vandiver for hisnumerous technical breakthroughs in thedynamics of vortex-induced vibrations thathave enhanced the design of structures to with-stand high ocean currents.

For Companies, Organizations, andInstitutions recognizes Kerr-McGee Oil andGas Corp. and Technip for their successfulglobal relationship that has pioneered anddelivered three generations of spar floating pro-duction systems in nine years.

See OTC press release (www.otcet.org/2005/index.html for further information.

Web-Based E&P Data ViewingZebra Geosciences WebDataViewTM is aweb-based well log, seismic, image and docu-ment viewing tool. It provides high quality,rapid visualization for a broad range of E&Pdata within a web browser and without theneed for a download. Petris Technology andZebra Geosciences have now collaborated toprovide WebDataViewTM as a viewing toolwithin PetrisWINDSTM Enterprise system.

See Petris Technology press release www.petris.com/pdfs/pr_Petris_ZebraGeo_11Oct2004.pdf and visit Zebra Geoscience's websitewww.webdataview.com/ for moreinformation.

6Network News

Tech Transfer Track

Intelligent ESP PumpingSystems Pay Off

Dick Ghiselin, Hart's E&P, developed aninteresting article summarizing the currentgeneration of intelligent pumping systems forelectrical submersible pumps (ESPs). Mostsystems have the capability to piggybacktelemetry and control signals on the powercable itself. With a single cable serving dou-ble duty as power and telemetry/control line,environmental feed-throughs at the wellheadand pump are not affected. Sensors can beinstalled that measure most anything.Technology providers have developed datamanagement, display and analytical routinesto realize the value from the data collected.Wells with commonalities can be groupedwhen it makes sense, and reports can be gen-erated to compare results against design crite-ria for a single well or group of wells.

Benefits include: protecting pumps that occa-sionally pump off through automatic shutoffs(and automatic restarts), providing automaticalarms and exception reports to focus fieldresources, detecting changing reservoir condi-tions, and sensing wear and predicting failureso service can be scheduled rather than reac-tive.

Decreasing time between failure is an obvi-ous driving force, but probably equally asvaluable is avoiding an ESP pumping sub-optimally for years.

Excerpted from "Pumps Pay Off," Hart'sE&P, March 2005 viewable online at www.eandpnet.com/ep/0305coverstory.htm.

New Higher PerformanceSucker Rod Connection

Permian Rod Operations, Odessa, Texas, hasdeveloped a new high performance suckerrod connection, PRO/KCTM. It consists oftwo pins, one coupling, and one couplingcenter torque button. This connection can beapplied to all new or inspected used rodstrings, API or non-API sizes.

Couplings are machined to achieve an end-face width as large as possible for maximumpin shoulder contact area. Pins are machinedso that all pin ends have exactly the samedimension from the shoulder to the pin endand the shoulder and pin nose are exactly truerelative to each other. Pin ends also receivewet fluorescent magnetic particle inspectionand are shot-peened to improve micro-finishand enhance fatigue resistance.

The torque buttons are locked into place sothe connections always break on the sameside during work over. Pre-load is confirmed

by measuring actual pin stretch with a dialindicator; this provides a connection withequal contact pressure on both pin shoulders,equal pre-load stretch of both pin necks andequal contact pressure of both pin nosesagainst the center torque button, creating apre-load stretch at the coupling center.

In tension and torque tests, the connectionoutperformed standard API connections by250% in tension and torque tests. In fatiguetesting, the connection lasted an average of 6times more cycles than API connectionsunder the same cyclic load conditions. In a3,900 ft progressive cavity-pumped well ineastern New Mexico with conventional rodconnections, 15 failures with multiple rodstring failures had been experienced in a 38-month period when conventional connectionswere used. With the new connection, therewere five failure events observed in a 13 ½-month period, but the failures were not relat-ed to the rod connection.

For further information, visit Permian RodCorporation's website www.permianrod.com/.

First Ever Rotary-Steered,Casing-Drilled Well

ConocoPhillips, Tesco Corp and SchlumbergerLtd. successfully drilled the first ever rotary-steered, casing drilled well in the Lobo Field inSouth Texas. ConocoPhillips has been drillingvertically with casing there since July 2001,having now casing drilled some 100 wells. Ofthese, only 10% have been in the directionalmode and those without rotary steering.Beyond reducing flat time by eliminating trips,casing drilling (in the Lobo environment)reduces trouble time—there is less lost circula-tion and pipe sticking. ConocoPhillips hasreduced trouble costs from $92,000/well toabout $26,000/well over the last two years.

Part of the incentive for "proving" the conceptis taking casing drilling offshore. Proving theconcept in an onshore well whose trajectorymade moves typical of offshore wells offeredadvantages. In this well a 5,500-ft interval wasdrilled using 7-in casing and Schlumbergers 4¾-in PowerDrive rotary steerable system. Thedirectional profile included a build to 30º ofinclination and a drop back to 6º while makingan azimuth change of 145º simultaneously.Using a rotary-steerable assembly during cas-ing drilling means adding a mud motor andmeasurement-while-drilling (MWD) tool. TheMWD tool was placed below the mud motor.

Excerpted from "ConocoPhillips AchievesIndustry First With Rotary-Steered CasingDrilling," Oil and Gas Journal, Jan. 10, 2005,and "Ready For The Offshore Reckoning,"Offshore Engineer, December 2004.

Devon Donates $2.3 Million toOklahoma State University

Devon Energy recently donated $2.3 million toOklahoma State University to build anadvanced 3-D visualization laboratory and tofund scholarships and fellowships. The 3,300-square-foot Devon Energy GeologyLaboratory will facilitate interaction betweenstudent recipients and Devon geoscientistsworking on real-world field projects.Completion of the lab is expected by fall 2005.

The laboratory will include an advancedgraphic station, screens, projectors andEthernet links enabling the use of cutting-edge technology with high-speed Internetaccess. In addition, two-way communicationbetween the laboratory and Devon researchteams will enhance interaction. In addition,the Devon Energy Scholars Program willfund graduate geology fellowships and under-graduate scholarships for geology and engi-neering students.

View full press release online www2.okstate.edu/pio/devon_energy.html.

Texas RRC Approves ASR’sHydro-Impact Technology as

Enhanced Recovery TechniqueFollowing a review of field performance inOxy's Elk Hills, the Texas RailroadCommission recently approved an applicationto treat Applied Seismic Research's (ASR)Hydro-Impact Technology (HIT) as anenhanced recovery technique, granting it taxabatement advantages.

ASR's HIT tool uses seismic wave stimula-tion technology to shake loose trapped oil. Itproduces shockwaves with a power rangingfrom 2 to 10 million watts and a pressure atthe wave front in excess of 3,000 psi. Theshockwaves are claimed to cover distances ofmore than a mile. ASR's rental agreement forthe U.S. market calls for an up-front paymentof $30,000, and $6,500 per month thereafter.

Oxy Elk Hills has been using seismic wavesfor stimulation since October 2003. Oil pro-duction was declining and was at 1,800 bopdbefore the seismic pilot. After the seismicactivity, oil production increased to more than2,200 bopd. Oxy Permian estimates that in 24months an additional 124,000 barrels of oilwill be produced, based on a 5% increase inoil cut/oil production. ASR's modeling showsrecovery could be considerably higher.

For more information, see ASR's full pressrelease http://sev.prnewswire.com/oil-energy/20041215/DAW02415122004-1.htmlor contact Bill Wooden (ph 972-381-4236).

7

State-of-the-Art Summary

Network News

Between the two extremes of the climatechange debate—denial that warming is takingplace on one end of the spectrum and hyper-bolized consequences and demands for drasticeconomic sacrifice at the other end—a middleground is forming that relies on technologicalinnovation. The idea is that a near-term solu-tion could be to capture and permanently store(sequester) carbon dioxide (CO2) emissionsfrom our largest and most concentrated streams(power plants, refineries, etc) in geologic for-mations. This approach would allow us to con-tinue to use our most abundant and inexpensiveforms of energy (oil, gas and coal) while reduc-ing carbon dioxide's contribution to globalwarming. The US Department of Energy seesthis approach as one possible transition to aneventual zero-emission, hydrogen-fueledfuture, and is deeply involved in helping todevelop the technologies needed to enable sub-surface geologic sequestration on a wide scale.

The oil and gas E&P industry can play a lead-ing role in this effort. Well acquainted with theinjection of high-pressure gases, the industrycan provide a link between the capture of CO2for environmental benefit and the injection ofthat CO2 for incremental oil or gas recovery.The best near-term opportunity for safely andeconomically sequestering CO2 may lie at theoriginal source of much of that nasty carbon,our own oilfields and coalfields.

Once cost effective techniques are developed tocapture CO2, there are significant volumes ofeconomically recoverable oil that can be pro-duced in conjunction with its storage. Nearlyall of this resource lies in older fields, many ofwhich are now being operated by independentproducers. This article outlines the effortsunderway and the estimated size of the poten-tial "prize" that might be producible under dif-ferent scenarios of technological growth andeconomic stimulation.

DOE Research Goal isEmission-Free PowerProductionThe Department of Energy's (DOE) CO2sequestration program, managed by theNational Energy Technology Laboratory, iscomprised of two primary elements: a coreR&D program and a regional sequestrationpartnership program, both of which providesupport for the development of FutureGen, a

$1 billion industry/government partnership todesign, build and operate a coal gasification-based, nearly emission-free, coal-fired electrici-ty and hydrogen production plant. The goal ofthe sequestration element of the program is toenable captured CO2 to be separated and per-manently sequestered in depleted oil and gasreservoirs, unmineable coal seams, deep salineaquifers, or other formations. DOE also man-ages a variety of other research designed toreduce emissions (e.g., power generationequipment improvements) or to develop othermeans of disposal than geologic sequestration(e.g., oceanic storage).

Efforts in the core R&D program, underwaysince 1998, focus on technologies for carbon

capture, sequestration, and storage as well asmonitoring, mitigation and verification. Theregional partnership initiative, announced inNovember 2002, is comprised of seven partner-ships of state agencies, universities, and privatecompanies that form a nationwide network tohelp determine the best approaches for captur-ing and permanently storing gases that can con-tribute to global climate change. The partner-ships include 216 organizations spanning 40states, three Indian nations, and four Canadianprovinces. Geographical differences in the useof fossil fuels and the options for sequestrationdictate that a regional approach is necessary.The primary purposes of the regional partner-ships are to develop the framework needed tovalidate and potentially deploy carbon seques-

Carbon Dioxide Storage: Opportunities for the E&P Industryby Karl Lang with Hart Energy Publishing, LP

Region

Midwest

Southeast

Southwest

West Coast

Big Sky

Plains

Midwest GeologicSequestrationConsortium

TotalFunding

$3.51 MM

$2 MM

$2.15 MM

$2.15 MM

$2 MM

$2.75 MM

$3.25 MM

TotalPartners

31

13

25

47

14

29

21

E&P Industry Partners

BPDTE Energy

Advanced Resources Intl.

Advanced Resources Intl.Burlington ResourcesChevronTexaco ERTCChevronTexaco PermianBUConocoPhillipsKinderMorgan CO2Marathon Oil Co.Oxy Permian Ltd.Yates Petroleum Corp.

Advanced Resources Intl.BPChevronTexacoConocoPhillipsKinderMorganOccidental PetroleumShell Oil CompanyTerralog TechnologiesWestern States Pet.Assoc.Oxy Permian Ltd.Yates Petroleum Corp.

Amerada HessEagle Operating, Inc.Fischer Oil and GasNorth Dakota Pet.Council

IOGCCKY Oil and Gas Assoc.IN Oil and Gas Assoc.IL Oil and Gas Assoc.

LeadOrganization

Battelle Mem. Inst.

Southern States Energy Board

New Mexico Tech

California Energy Commission

Montana StateUniversity

University NorthDakota

Univ. Illinois and ILGeol. Survey

States

IN, KY, MI, MD,OH, PA, WV

AL, AR, FL,GA, LA, MS,NC, SC, TN,

TX, VA

AZ, CO, KS,NE, NM, OK,TX, UT, WY

AK, AZ, CA,NV, OR, WA

ID, MT, SD,WY

IA, MO, MN,ND, NE, MT,SD, WI, WY

IL, IN, KY

Table 1: DOE Regional Sequestration Partnerships

8

State-of-the-Art Summary

Network News

tration technologies. These partnerships willcharacterize each region's CO2 sources andsinks, evaluate alternative sequestrationapproaches, study regulatory and infrastruc-ture requirements, and develop publicinvolvement and education mechanisms. Thetimeframe for this effort is two years andDOE funding is roughly $2 MM per partner-ship, with co-funding by the partners at aboutone-third of the total. The largest representa-tion of the oil and gas E&P industry in themembership of the regional partnerships isfound in the West Coast and Southwestregions. Eleven producing companies andfive industry associations are representedoverall (see Table page 7).

One product of the partnership program is anonline GIS database (www.natcarb.org) thatcontains data on CO2 sources (refineries,power plants, chemical plants, etc.) nation-wide. The map layers also depict oil and gasfields, Federal lands, aquifer areas, and awealth of information (you will need a littlepatience and a high-speed internet connec-tion). Individual CO2 emissions sources canbe clicked on to reveal plant information. Thedatabase is best populated in the IllinoisBasin as far as oil and gas fields, but theonline system is being added to on a regularbasis.

According to Robert Finley of the Universityof Illinois, the Midwest GeologicSequestration Consortium (www.sequestra-tion.org) has submitted a proposal to DOEfor Phase II of the partnership program thatincludes potential field tests with 10 operatorsin the Illinois Basin. The list of companiesincluded: Bretagne GP, ContinentalResources, Gallagher Drilling, Covington Oil& Gas, Shakespeare Oil, Murvin Oil, OelzeProduction, Team Energy, and HowardEnergy. A utility, Ameren Corp., also pro-posed two coalbed methane injection tests. Ifthis Phase II project is approved, only fourfield tests will be selected. However, the levelof interest from independent producers wasstrong. DOE is currently evaluating all of thePhase II proposals received from the partner-ships.

Carbon Dioxide Sequestrationand Oil and Gas RecoveryCO2 can, of course, be injected into depletedoil reservoirs as part of an enhanced oilrecovery (EOR) process. This has been suc-cessfully carried out for decades in a number

of Permian Basin carbonate reservoirs, pri-marily using purchased CO2 produced andpiped from naturally occurring reservoirs inColorado and New Mexico. The driver hereis recovery of a portion of the 30 to 40 per-cent of the reservoirs' oil remaining in placeafter secondary waterflood operations, notCO2 sequestration. Supercritical CO2 canbecome miscible with the oil, acting as a sol-vent to reduce residual saturation. Naturally,EOR operations have been focused on mini-mizing the amount of CO2 that remainssequestered per barrel of oil recovered (about2000 scf or less per barrel), as this CO2 is apurchased injectant.

Alternatively, CO2 could be injected into areservoir that is still producing primary oilbut which is nearing the end of its producinglife. A credit for CO2 storage would shift theeconomics of enhanced oil recovery and alterfield practices to optimizing CO2 storage.Use of depleting oil reservoirs amenable toCO2 EOR as a sequestration option, couldprovide a value-added benefit in terms ofincremental revenue from enhanced oil pro-duction which could partially offset the costof CO2 capture, which currently is notinsignificant.

Captured carbon dioxide could also be inject-ed and sequestered in depleted gas reservoirs.The fact that gas was trapped in such reser-voirs over geologic time supports the notionthat they are safe repositories for carbondioxide over the long term. In many cases theinfrastructure for injection (surface pipingcompressors, wells) still exists.

The CO2 storage capacity of domestic oil andgas formations has been estimated at roughly150 billion metric tons of CO2, or roughly 30years worth of current U.S. emissions (ARI,2003). Depleting oil reservoirs can't meet allpotential CO2 sequestration needs, but theycould provide an early opportunity forsequestration at relatively low cost. Some ofDOE's core R&D is investigating trappingmechanisms for CO2 and developing reser-voir management strategies that simultane-ously maximize CO2 sequestration and oilrecovery.

Another option also aligned with the oil andgas industry is sequestration in coal seamsthat are too deep or too thin to be mined eco-nomically but are candidates for methaneextraction. Primary "coal bed methane"recovery methods, dewatering and depressur-

ization, leave a fair amount of the methane inthe reservoir. Enhanced methane recovery canbe achieved by sweeping the coal seam withnitrogen or CO2. The CO2 preferentiallyadsorbs onto the surface of the coal, releasingthe methane. Two to three molecules of CO2are adsorbed for each molecule of methanereleased. The maximum domestic capacityfor CO2 sequestration in coal seams has beenestimated at 90 billion metric tons CO2, 40billion metric tons of which is in Alaska(ARI, 2003). Like depleting oil reservoirs,unmineable coal seams could be a good earlyalternative for CO2 storage. One potentialproblem however, is coal swelling. It hasbeen observed that when coal adsorbs CO2 itswells in volume, restricting the flow of CO2into and the flow of methane out of the coal.Work is underway toward minimizing thesenegative effects.

In addition, the potential for CO2 storage informations saturated with brine is enormouscompared to oil reservoirs and coal beds andpotentially could contain hundreds of year'sworth of CO2 emissions. However, much lessis known about injecting into saline forma-tions than is known about injecting into oilreservoirs and coal seams. A portion ofDOE's core R&D is focused on improvingour understanding of these saline formations.

Field Experience With OilfieldCO2 SequestrationTwo large CO2 sequestration projects havebeen underway for a number of years: anEOR project at Weyburn Oil Field in Canadaand injection into a deep saline formation inthe Sleipner Gas Field in the North Sea. Inaddition, a relatively small-scale (one days'worth of CO2 from an average coal-firedpower plant) field test supported by the DOEprogram is also underway.

The Weyburn project began in 1999. Itinvolves the transport of CO2 through a 202-mile pipeline from a coal gasification plantnorth of Beulah, ND to the Weyburn oil fieldnear Regina Saskatchewan. Before buildingthe pipeline, the Dakota GasificationCompany released most of the CO2 into theatmosphere. The CO2 (96 % pure) is com-pressed to 2200 psi before being delivered tothe pipeline. At Weyburn, the gas is injectedinto the producing zone, a 100-ft thickMississippian carbonate at a depth of about4700 ft. The 70-square mile field area con-tains more than 1000 wells.

On a daily basis, about 100 MMcf (5000metric tons) of CO2 are transported andinjected. As of March 2004, about 106 Bcf ofCO2 had been injected and over the project'slifetime a total of 466 Bcf (22 million metrictons) will be sequestered. The operator,EnCana Corporation, estimates that an addi-tional 130 million barrels of oil will be recov-ered over the next 30 years as a result of theCO2 injection.

The world's first CO2 capture and storageproject actually began in 1996 in the Sleipnergas field offshore Norway. The operator(Statoil) processes the produced gas to reduceits CO2 content from 9% to 2.5% before sale.If the extracted CO2 were released to theatmosphere, Statoil would be required to paya tax of about US$45 per metric ton, so thecompany injects the CO2 into a regionalsaline aquifer via a single, highly deviatedinjection well. Over the past nine years theSleipner operation has injected over 7 millionmetric tons of CO2 and the operational planis to continue to inject for another 15 years.The saline aquifer has the potential tosequester 600 billion tons of CO2.

A more recent injection project funded byDOE (part of the core R&D program men-tioned earlier) is underway in the SouthLiberty oil field northeast of Houston. Thebrine-filled injection zone in this field is asandstone zone within the Frio formation, at adepth of about 5000 ft, on the flank of a saltdome. The site was selected due to its prox-imity to a large concentration of powerplants, refineries and chemical manufacturingplants that emit CO2. The Gulf Coast regionemits roughly 520 million metric tons of CO2each year. The Frio sands in this region havebeen estimated to be capable of storingbetween 200 and 358 billion metric tons. Forthis project, injection of about 3000 metrictons from a nearby refinery took place over athree-week period. A number of monitoring,diagnostic and modeling activities have takenplace or are underway. The project aims totest these tools and techniques for character-izing a CO2 injection operation, as well as to

demonstrate that CO2 can be safely injectedand securely stored.

Regional Strategies for CO2-EORAnticipating a time when economics willsupport the simultaneous capture and storageof CO2 and the enhancement of oil produc-tion, DOE has undertaken a fresh look at thepotential for enhanced oil recovery from CO2injection in the nation's older reservoirs.Using the CO2-PROPHET model developedby Texaco for DOE, Advanced ResourcesInternational (ARI) evaluated major reser-voirs in six regions of the country:Oklahoma, onshore Gulf Coast, Illinois,onshore California, offshore Louisiana andAlaska. The model was used to determine theeconomic (>15% ROR BFIT) resource. Foreach region, the analysts evaluated alternativeoil recovery strategies and scenarios. The firstscenario assumed CO2-EOR technology asapplied in the past (Traditional PracticesScenario). The second scenario assumed thatall of the lessons of past CO2-EOR technolo-gy are applied using state-of-the-art technolo-gy and oil price averages $25/Bbl, but CO2supply costs remain high at a per MCF costof about 5% of oil price (State-of-the-ArtScenario). The third scenario examines howthe potential for CO2-EOR could beincreased through a strategy involving statetax reductions, federal tax credits, royaltyrelief and/or higher oil prices that wouldtogether be equivalent to a $10 per barrel liftin oil price (to $35) received by the producer(Risk Mitigation Scenario). In the fourth sce-nario low-cost CO2 is assumed to be avail-able at a per Mcf cost of about 2% of oilprice (kept at $35/Bbl), from existing naturalsources and industrial sources via CO2 cap-ture technologies (Ample Supplies of CO2Scenario).

The results for the four areas of interest tomost independent producers (onshore lower-48 states) show that at reasonable long-termoil prices of $25-$35 per barrel, there aresubstantial potential recoverable reserves

obtainable from CO2-EOR if a reliable, rea-sonably priced source of CO2 can be found(Table 2). Given that some believe that oilprices might move considerably higher thanthat range, and that up to 30% of the totalresource was not evaluated, these totals couldbe conservative. On the other hand, the lackof existing CO2 gathering and distributioninfrastructure in these areas will make it cost-ly to deliver CO2 at prices in the 2 to 5% ofoil price range, even if new technology low-ers the cost of CO2 capture and separation.Some sort of favorable tax treatment couldhelp to alleviate this risk.

So, while the idea of widespread applicationof CO2-EOR outside of the traditionalPermian Basin area may seem farfetched, aradical change in the cost of capturing EOR-ready CO2 or a radical shift in the valueassigned to removing CO2 from the atmos-phere could change the picture. The resourceremains there, waiting for the right set of cir-cumstances.

Note: This article was prepared with inputfrom three primary sources: The NETLCarbon Sequestration website atwww.netl.doe.gov/, an article by KamelBennaceur (and others) in the Autumn 2004issue of Schlumberger's Oilfield Reviewavailable at www.slb.com/, and draft copiesof ARI's reports: Basin Oriented Strategiesfor CO2 Enhanced Oil Recovery. Thesereports are expected to be published in thenear future and will be available on the DOEwebsite at www.doe.gov/.

9Network News

State-of-the-Art Summary

60.5%90%

68.7%58.5%

OklahomaCaliforniaIllinoisGulf Coast Total

State-of-the-Art28901830370

18606950

Risk Mitigation45603500470

43309860

Ample CO2 Supplies47403980470

3570*12,760

Region Fraction of Region’sEUR Evaluated

Economically Recoverable Resourceby Scenario (MM Bbls)

*Ample Supply Scenario includes $25 oil rather than $35 as the others

Table 2: Economically Recoverable Resource from CO2-EOR

Reprinted with permission of Gulf Publishing

10Network NewsNetwork News

DOE Digest

DOE Announces 10 Microhole Drilling Awards

In late January DOE announced 10 projectawards, involving $7.7 million of DOE fundsand $6.8 million of industry partner funds.

Geoprober Drilling Inc. (Texas). This pro-ject calls for drilling three wells with an inno-vative composite coiled tubing (CT) drillingsystem. Goal is to confirm the capability todrill microhole exploration wells in waterdepths ranging up to 10,000 feet. Cost sav-ings, projected at 59% over that for conven-tional wells, would come by using a smallerdrilling vessel and by eliminating the need todeploy and retrieve a large riser.

Gas Technology Institute (Illinois). This pro-ject will test a next-generation microhole CTrig, MOXIE. The MOXIE experimental rig,fabricated by Coiled Tubing Solutions, wasdesigned specifically for CT and microholedrilling to 5,000 ft. depths. First deployed forinitial testing in a Kansas gas field last year,the rig was able to drill 280-400 ft. p/h.

Confluent Filtration Systems LLC (Texas).Researchers will seek to develop a revolution-ary elastic-phase, self-expanding tubular tech-nology called CFEX. The goal is to developself-expanding well casings to any diameter.

Tempress Technologies (Washington). Thegoal is to develop a small, mechanically-assisted, high-pressure waterjet drilling tool.A downhole intensifier would boost the pres-sure that can be delivered by CT, maximizingdrilling rates. That in turn would overcomethe limited reliability, power, and torque ofsmall-diameter drill motors.

CTES LP (Texas). Researchers will focus onimproving the performance and reliability ofmicrohole CT drilling bottomhole assemblieswhile reducing cost and complexity associatedwith drilling inclined/horizontal laterals greaterthan 2,000 ft. This would be accomplished byinducing vibration along the CT drill string,which would eliminate the need for a down-hole drilling tractor to mitigate friction.

Technology International Inc. (Texas). Thisproject entails developing and testing a down-hole drive mechanism and a novel drill bit fordrilling with CT. The high-power turbodrillwill deliver efficient power at relatively highrevolutions per minute and low bit weight.The more durable drill bit will employ high-temperature cutters that can drill hard andabrasive rock in 3½-inch boreholes.

Ultima Labs Inc. (Texas). This project isintended to combine existing technologies formeasurement-while-drilling (MWD) and log-ging-while-drilling (LWD) into an integrated,inexpensive measurement system to facilitate

low-cost CT drilling of small-diameter (3½inch) wells at depths shallower than 5,000feet. Two prototypes are to be delivered.

Baker Hughes Oilfield Operations Inc.(Texas). Researchers will seek to provide awireless system to help steer drilling in amicrobore. Plans call for developing a down-hole bidirectional communication and powermodule and a surface CT communication link.

Gas Technology Institute (Illinois). Thisproject entails designing, developing, andevaluating a counter-rotating motor drillingsystem for reducing costs associated withdrilling wells targeting unconventional gas.By concentrating the weight on the drill bit ina smaller area and by addressing the limitedtorque on a CT drill string, this wouldincrease CT drilling effectiveness.

Confluent Filtration Systems LLC (Texas).This project is designed to prove and developa concept for a self-expanding, high-flow sandscreen that could be constructed from a widerange of materials. Plans call for deployingthe technology in a demonstration well.

View DOE Tech Line at www.netl.doe.gov/publications/press/2005/tl_microhole_selec-tions.html.

Kansas Exploring EnhancedCBM from Landfill Gas (LFG)

Currently about 4.5 MMCFD of LFG is col-lected from the Johnson County, Kansas land-fill. About half of the gas is methane and theother half is largely CO2. Now this gas isprocessed on the surface, resulting in about 3MMCFD of pipeline quality gas. In a DOE-supported project, the Kansas GeologicalSurvey and other partners are exploring thepossibility of injecting untreated LFG intosubsurface coalbeds. Since coal readilyadsorbs CO2, the coal would act as a naturalprocessing agent, replacing the current sur-face processing equipment. Methane in theinjected LFG would flow through the reser-voir. Additional CBM gas would be producedfrom enhanced CBM.

Good idea, but will the concept work. In theproject the local geology will be evaluated todetermine structure, stratigraphy, depth andthickness of underlying coal seams. Coalsamples will be obtained and their propertiesand reservoir conditions ascertained.Response of the samples to LFG gas will bedetermined. With this data, reservoir simula-tion will explore the economic potential. Alisting of major U.S. landfills overlying coal-bearing strata will be developed.

View DOE project fact sheet at www.netl.doe.gov/publications/factsheets/project/Proj324.pdf.

High-Pressure, Jet AssistedDrilling Tested at RMOTC

In partnership with DOE's National EnergyTechnology Laboratory, Maurer Technology,Inc. of Houston developed an innovativedrilling system that uses high-pressuredrilling mud to drive a special mud motor andbit with small diameter drilling jets. High-pressure drilling mud in conjunction withsmall diameter jets results in very high veloc-ity fluid streams. These streams cut kerfs inthe rock at the bottom of the hole allowingthe mechanicalcutters to easilybreak the rockledges, therebysignificantlyincreasingdrilling rates.

This systemwas field tested in a new well drilled in theRocky Mountain Oilfield Testing Center inWyoming last year at depths of approximate-ly 4,300 to 5,200 feet. During the test,drilling pressures exceeded 7,500 psi at mudcirculation rates of 200 gpm. The drilledinterval included a variety of lithologies,ranging from clean, high porosity sandstoneto limestone, as well as shale and siltstone.

Significant increases in drilling rate were evi-dent over specific intervals, from two toseven times the conventional historicaldrilling rate. In some areas drilling rates hadto be limited to allow proper cleaning of thehole. Difficulties were encountered with thehigh-pressure mud motor and nozzles in thedrill bits. The mud motor's stator, which hadaged during the project, failed downhole. Thetest was completed by drilling conventionallywith the rig's rotary table, high-pressuredrilling swivel, Kelly hose and mud pump.The RMOTC drilling crew also had to over-come some mechanical problems to operatethe surface equipment used by the new high-pressure system. Overall, surprisingly fewproblems were encountered showing thathigh-pressure, jet-assisted drilling can be con-ducted using conventional commerciallyavailable equipment. Rig modifications wereminimal and not cost-prohibitive. The mostcostly item was the high-pressure mud pump.

This field demonstration concluded DOE'sinvolvement in this project. This technologyis now available for commercialization byother companies. For more information oncommercialization, contact MaurerTechnology Inc. (John Cohen, email jco-hen@noblecorp.com).

Content excerpted from RMOTC's fall 2004newsletter (www.rmotc.com/Today/fall-news.pdf.

11Network News

DOE Digest

Stripper Well Consortium (SWC)Selects 2005 ProjectsLow-Cost Portable Production Well Tester(Oak Resources, Inc. —Oklahoma). Currentlow cost portable testers ($10,000) are notaccurate enough. First generation portable elec-tronic test units were about $125,000 (afterprototyping and proving). Second generationelectronic testing units with capabilities acrossthe full range of well conditions developed dur-ing an existing SWC project cost about$80,000. This project will develop and test 10field/area-specific units. Since full capabilitiesare not required for field/area-specific units,anticipation is that cost can be driven down to$25,000 range. Product acceptance and marketforces would then further lower the price range.

Interaction of N2/CO2 Mixtures with CrudeOil (Pennsylvania State University—Pennsylvania). A nitrogen huff and puff processhas been ongoing in the Big Andy field in east-ern Kentucky for over 6 years. The nitrogenobtained through membrane separation tech-nology contains up to 5 percent oxygen. A priorSWC project investigated the phase behavior ofN2/O2 gases in the presence of hydrocarbon.Field experience has indicated that periodicinjection of CO2 mixed with nitrogen improveswell performance. This project will evaluatethe behavior of N2/CO2 injection and itsimpact on the recovery process using crude oilsfrom the Big Andy Field and the Chipmunksandstone in New York.

Uncovering Bypassed Pay in CentralOklahoma (Schlumberger Consulting Services(Schlumberger)—Oklahoma). Schlumberger,the University of Oklahoma (OU) and SandResources will develop a methodology touncover behind pipe potential in mature oilfields. Sand Resources operates 12 stripperwells in the NW Noble Field in ClevelandCounty. Senior OU petroleum engineering stu-dents with faculty guidance are evaluatingundeveloped, behind-pipe reserves.Schlumberger, through the use of its MovingDomain Software, will aid in the evaluationand, at the same time, develop a methodologythat would be made available to other opera-tors. Schlumberger will identify areas withpotential within a five-county region(Cleveland, McClain, Oklahoma, Garvin andLogan counties).

G.O.A.L Automated Casing Swab for OpenHole Completions (Brandywine Energy andDevelopment Company, Inc.—Pennsylvania).Beam Pumps, tubing velocity strings, smalldiameter tubing and plungers and other con-ventional techniques are often employed withsome finite success in open-hole completions.This project will refit two existing 6.25"or larg-er open-hole completions with a re-fit well sys-tem comprised of a slip lined 3.0" or 4.0" IDspooled non -metallic tubing, metal to nonmetal connectors, open hole packer assembly,casing stand /stop, and modified G.O.A.L.

PetroPump with unique variable diameter sealcups to automatically lift fluids.

Desalination of Brackish Water and Disposalinto Waterflood Injection Wells (Texas A&MUniversity—Texas). A joint venture has beencreated for a two-year pilot project in Andrews,Texas, for inland brackish ground water(BGW) desalination with byproduct disposalinto an operating waterflood. Andrews will useTexas A&M's mobile desalination unit. SWCfunds will be related to the oil field brine dis-posal operation. ExxonMobil will inject theconcentrate from the reverse osmosis processin their Means field waterflood, realizing costsavings in make-up water requirements.

New Technology for Unloading Gas Wells(Colorado School of Mines (CSM)—Colorado). This project will evaluate a varietyof devices. Work will include: (1) studying baf-fle assemblies, (2) resolving the discrepancybetween lab and field performance of vortextools, (3) transient design simulation of gaswell loading and unloading, and (4) test a gas-flow powered pump. One-day short courses onliquid lifting using CSM's flow loop for hands-on demonstration will be continued.

Wedge Pump for Casinghead PressureReduction (W&W Vacuum & Compressors,Inc.—Texas). The patented Weatherbee WedgePump is thought to have significant advantagesover conventional equipment for casingheadpressure reduction. Existing technology cannotpull the volume of vacuum (throughput) neces-sary and it struggles handling typically highBTU casinghead gas without running intoproblems handling liquids. This project willbuild three prototype models and a test stand tosimulate common wellhead conditions.Prototypes will be bench tested.

Effect of Completion & Production Practiceson Recovery from Knox Formation (JamesEngineering, Inc.—Ohio). Various drilling,completion, and production methodologieshave been applied to the Knox Formation(Rose Run Sandstone and the BeekmantownDolomite). Completion and production techni-cal issues include: cased-hole versus open-holecompletions, matrix acidizing versus fracturestimulation, perforation concentration andinterval selection, fluid removal methods,paraffin treatments, operating wellhead pres-sures, gas sales line pressures, as well as gener-al operating procedures. This study will evalu-ate the critical factors associated with comple-tion and production practices and the effect onthe ultimate reserves predicted.

Real Time Remote Field Monitoring of PlungerLift Wells (Tubel Technologies, Inc.—Texas).This project will develop a low cost surfacesystem to monitor the plunger lift process inwells, transmit well production streaming audiosignals to remote locations, monitor in realtime the performance of the entire field anddetermine if and when the wells stop produc-ing. This new system will acquire the informa-

tion generated by plunger movement and moni-tor the fluids and gas being lifted. The informa-tion will be transmitted to a central control areawhere the operator can listen. An automatedcomputer system will also be developed.

Demonstrating Hydroslotter Technology inNew York Wells (Hydroslotter Corporation—Canada). Hydroslotting is a two-step abrasivehydrojet completion process. The first step cutstwo 180°-phased slots through the casing,cement, and deep (up to 10 ft) into the forma-tion. The second step cycles proprietary reme-dial chemical reagents via the newly createdslots. Effectively, near-wellbore damage istransferred to the distant slot tips. Hydroslottingwill be demonstrated in five different wellenvironments in three New York geologicalzones: Onondaga, Medina, and Theresa. Atleast one demonstration will be close to a gas-water contact.

Disproportionate Permeability Reduction inGelled Polymer Systems (University of Kansas(KU), Center for Energy Research—Kansas).A two-well field test involving KU and VessOil Corporation, a Kansas independent, will beconducted to determine if the water productionrate following a polymer gel water shut-offtreatment can be reduced by a process in whichthe gel that has formed in situ is dehydratedfollowing placement by slow injection of oil.Oil flow channels formed by the dehydrationprocess exhibit preferential permeability to oilover water.

Non-Polymer Water Shut-off Treatment(IMPACT Technologies, Inc.—Oklahoma). Anon- polymer water shut off treatment wasdeveloped and field tested in Kansas by amajor in the 1970s and refined through furthertesting in the 1990s by an independent. Twelveinjection wells and one production well havebeen treated in 10 properties in central Kansas.This project will test the process in at least 23more wells. Process advantages include beingvery low cost (about 50% of current gel poly-mers), non-toxic, and easy to handle/ mix andpump in the field.

Further Developing PAAL's ElastomericCasing Plunger Cup Design (PAAL, LLC—Oklahoma). Older methods use cups with themajor outside diameter larger than the casinginside diameter. Since cup diameter withPAAL's design cup diameter is smaller than thecasing inside diameter, cups do not experienceunnecessary wear during descent. Wells withtapered casing strings, as well as those previ-ously excluded due to squeeze cement casingleak repairs, can be produced. Much remains tobe determined though about elastomers. Thisproject will modify an existing PAL casingplunger to provide test chambers to expose var-ious elastomers to downhole conditions.

For more information visit www.energy.psu.edu/swc.

12Network NewsNetwork News

Industry View

Prior interviews have provided the perspec-tives of a larger technology provider and indi-vidual innovators. Closing the loop on inter-views about technology commercializationand uptake, PTTC sought input from AliDaneshy, Daneshy Consultants, Intl. In addi-tion to his technical expertise in several areas,Daneshy is well known for his insights on"technology uptake." He has authoredcolumns in Hart's E&P, plus led the recentSPE Advanced Technology Workshop on"Accelerating Technology Acceptance." Hisinsights to questions posed by PTTC follow.

Q: It is self-explanatory that both produc-ers AND technology providers MUST BEINVOLVED for uptake of newer technolo-gies in a timely fashion. Prior interviewshave focused on the technology develop-er's perspective. From your experienceworking both sides of the equation, whatdo you think the producer needs to bringto the table for timely uptake to occur?

A: Acceptance and successful use of new tech-nology is not a trivial task. It requires technical,operational and leadership skills, as well as aprogressive attitude. More specifically, theseinclude;

1. Strong technical backbone related to thenew technology. The more complex orrevolutionary the technology, the strongerthe required backbone and the difficulty tointegrate the new with the old.

2. Willingness and ability to take risk. Thewillingness is mostly a personal trait.Ability is related to access to financialresources, as well as the culture and busi-ness drivers of the organization.Organizations need to adopt businessmeasures that reduce the immediate riskof being an early technology adopter.

3. A healthy mix of long and short term busi-ness objectives. The value of many tech-nologies comes from their long term use.

4. Time. Maturity of use and operational reli-ability of the new technology improveswith time. So does the ability to knowhow and where to apply it. Just as readinggolf instruction manuals does not make aperson a golfer, reading about new tech-nology does not make an expert. Oneneeds to go through the learning process,which involves actual hands-on experi-ence.

5. Visibility and measurement. There is nodisagreement about the long term value oftechnology. If so, it needs to be includedas one of the direct measures by whichsuccessful business practices are identi-fied.

6. Involvement. All new technologies maturewith use. During this phase an involvedand interested user can play a pivotal rolein the speed and direction of technologymaturity.

Q: The circumstances of a very smallproducer, mid-sized independent, largeindependent and major are quite differ-ent. How does what the producer bringsto the table vary with the size of compa-ny?

A: Larger companies are more process andpolicy-driven than smaller ones. While theseimprove cost and operational efficiency andpredictability, they also may hinder innova-tion and risk-taking. Larger companies aremore likely to have access to broader in-house technical skills, but this also slowsdown the decision-making process. The tech-nical staff in smaller companies has a largerinvolvement in purchasing decisions than inlarger companies. Larger companies havemore elaborate purchasing processes thatoften discourage acceptance of new technolo-gy in favor of lower direct costs. Emphasison cost is even more dominant in NationalOil Companies for whom direct cost is oftenthe only mechanism for awarding contracts.

The reorganization of large companies intosmaller Business Units and Asset Teams wasintended to create the best of both worlds; theefficiency of a large company together withthe speed and focus of a small company.While in many regards this has been a suc-cessful business strategy, it is doubtful that ithas helped accelerate acceptance of new tech-nology. Within the oil and gas industry, thegeneral opinion is that small and mid-sizeOperators are more receptive to new technol-ogy than the Majors. This point has a tremen-dous impact on the use of technology by theindustry. The profitability of a new technolo-gy depends on its ability to go beyond theinnovators and early adopters and becomeacceptable to early majority and pragmatists.This involves larger oil and gas and NationalOil Companies.

Market studies clearly show the slow adop-tion of new technology by the oil and gasindustry. Changing this market dynamic isgoing to be slow and will require awarenessand participation of all industry segments. Itwill require a change in industry businessphilosophy, shifting focus from short termcost to long term value. Major oil and gascompanies with their proven successfulrecord of implementing change are naturalcandidates to lead this effort.

Interview with Ali Daneshy, Ph. D., SPE Director, 2005-2008

Dr. Ali Daneshy is the Director of Petroleum Engineering Program at the University of Houston and a partner in Dapish Oil and Gas StrategyConsultants, which provides consultation services related to analysis, business planning, marketing and launch of new technology. He has over 30years of experience in the development and launch of new technology in the oil and gas industry. During his tenure at Halliburton he was the VicePresident of Integrated Technology Products and responsible for the launch of several novel technology-based business units, including EnventureGlobal Technology.

Dr. Daneshy has published extensively on innovation, use of technology, and novel strategies for profitable technology launch. He also conducts shortcourses on these topics for the oil and gas industry.

13Network News

CONTACT THE PTTC REGIONALRESOURCE CENTER IN YOUR AREA:

Appalachian RegionDirector: Doug PatchenWest Virginia University304-293-2867, ext. 5443Coordinator: Mark Hoffman, 304-293-2867 Ext. 5446www.karl.nrcce.wvu.edu

Central Gulf RegionDirector: Bob Baumann,Louisiana State University225-578-4400Coordinator: Don Goddard, 225-578-4538www.cgrpttc.lsu.edu

Eastern Gulf RegionDirector: Ernest ManciniUniversity of Alabama205-348-4319Coordinator: Bennett Bearden, 205-348-1880http://egrpttc.geo.ua.edu

Midwest RegionDirector: David MorseIllinois State Geological Survey217-244-5527Coordinator: Steve Gustison, 217-244-9337www.isgs.uiuc.edu/pttc

North Midcontinent RegionDirector: Rodney ReynoldsKansas UniversityEnergy Research Center785-864-7398Coordinator: Dwayne McCune, 785-864-7398www.nmcpttc.org

Rocky Mountain RegionDirector: Sandra MarkColorado School of Mines303-273-3107www.pttcrockies.org

South Midcontinent RegionDirector: Charles MankinOklahoma Geological Survey405-325-3031Coordinator: Michelle Summers, 405-325-3031www.ogs.ou.edu/PTTC/

Southwest RegionDirector: Robert Lee,Petroleum Recovery ResearchCenter, 505-835-5408Coordinator: Martha Cather, 505-835-5685http://octane.nmt.edu/sw-pttc

Texas RegionDirector: Scott Tinker,Bureau of Economic GeologyUniversity of Texas at Austin512-471-0209Coordinator: Sigrid Clift, 512-471-0320www.energyconnect.com/pttc

West Coast RegionDirector: Iraj ErshaghiUniversity of Southern California213-740-0321Coordinator: Idania Takimoto, 213-740-8076www.westcoastpttc.org

Michigan SatelliteWilliam Harrison III, W. Mich. Univ.269-387-8633http://wst023.west.wmich.edu/pttc.htm

Permian BasinBob Kiker, UTPB CEED432-552-3432www.energyconnect.com/pttc/pb/

Regional Roundup

1st Quarter 2005 Case StudiesPetroleum Technology Digest

Microturbine application reduces sourgas flaring, provides partial power(March)

Internet access to well information(February)

Volumetric balancing locates recover-able hydrocarbons (January)Petroleum Technology Digest is a joint project of GulfPublishing (World Oil) and PTTC. See case studiesonline at www.pttc.org/case_studies/case_studies.htm.Contact lcole@pttc.org.

Alerts Via E-Mail: Another PTTC Service

Mar. 24

Feb. 28

Feb. 8

Jan. 12

PTTC HighlightLeadership ChangeOccurs Within PTTCBoard

Central Gulf Region -New LA Parish WellReference Product

Online VideoPresentations FromPTTC, Interested?

Highlights fromDecember 2004Network News

Industry HighlightHalliburton's VariSealTM

Lightweight CementSystem

OTC's "Spotlight onNew Technology"Winners

Baker Hughes INTEQAutoTrak® RotaryClosed-Loop Drilling(RCLD) Systems

ATP Wins OffshoreEnergy AchievementInnovation/Technology"Award

DOE HighlightThe Quest for MethaneHydrates in GOMContinues

Gas Tips, Winter 2005

Microhole AwardsAnnounced, NewSolicitations for Oil &Gas R&D

Still Time For StripperWell ConsortiumProposals — Due February 8

Solutions from the Field: Online Technologies to Solve Problems

Faced by Independent Producers

PTTC Tech Info

American Oil and Gas ReporterTech Connection Column

MarchPTTC’s Online Information ResourcesStill Expanding

FebruaryConference Reflects Operators’ StrongInterest In CO2 Flooding

JanuaryUnconventional Gas Demands LearningWhat Practices Work Best

Summaries of PTTC region- sponsoredworkshops. For summaries of morethan 100 workshops (of more than1,000 conducted) and for a listing of theworkshops held, logon to: www.pttc.orgor for more details, contact 1-888-THE-PTTC, e-mail: hq@pttc.org. For someof the workshops the regions haveposted speaker presentations online.

Low Cost Methods for Improved Oil andGas Recovery — Based on a workshop con-ducted by PTTC's Central Gulf Region,January 27, 2005 in Shreveport, LA.

Sequence Stratigraphy for Explorationists— Based on a workshop conducted byPTTC's Eastern Gulf Region, January 12,2005 in Jackson, MS.

Converting Stranded Gas and LoweringPower/Operating Costs —Based on a work-shop conducted by PTTC's Texas Region onDecember 15, 2004 in Midland, TX.

Some Regional Recognition

Dr. Iraj Ershaghi, West Cost, Receives2005 SPE Western Region Award

For Tireless and Selfless Dedication

Bennett Bearden, CPG DPA, Eastern Gulf RegionElected Alabama's AAPG Delegate

Representing Alabama Geological Society

Reprinted with permission of Gulf Publishing

W W W . S E G . O R G

15Network News

Upcoming Events

PTTC’s low-cost regional workshops connect independent oil and gas producers with information about various upstream solutions. For informationon the following events, that are sponsored or co-sponsored by PTTC, call the direct contact listed below or 1-888-THE-PTTC. Information also isavailable at www.pttc.org/events.htm. Please note that some topics, dates, and locations listed are subject to change.

April 20054/6 South Midcontinent: Chart-Type Gas Meters and How To Calculate Gas Production (Oklahoma Marginal Well Commission) -

Wilburton, OK. Contact: 405-604-0460 4/6-7 North Midcontinent: TORP Oil Recovery Conference (Univ. of Kansas) - Wichita, KS. Contact: 785-864-73984/7 Eastern Gulf: The New Phase I ESA: "All Appropriate Inquiry" and The Nebulous Nature of Total Petroleum Hydrocarbons

(Mississippi State Board of Registered Professional Geologists) - Jackson, MS. Contact: 205-348-18804/12 South Midcontinent: Chart-Type Gas Meters and How To Calculate Gas Production (Oklahoma Marginal Well Commission) - Tulsa,

OK. Contact: 405-604-0460 4/13 South Midcontinent: Chart-Type Gas Meters and How To Calculate Gas Production (Oklahoma Marginal Well Commission) -

Oklahoma City, OK. Contact: 405-604-0460 4/13 South Midcontinent: Polymer Gel Technology - Norman, OK. Contact: 405-325-30314/20 South Midcontinent: Chart-Type Gas Meters and How To Calculate Gas Production (Oklahoma Marginal Well Commission) -

Ardmore, OK. Contact: 405-604-0460 4/20-21 Texas presentation: Wellbore Management and Produced Water Management (Bob Kiker @ Southwestern Petroleum Short Course) -

Lubbock, TX. Contact: 432-552-34324/21 Appalachian: Central Kentucky Trenton-Black River Outcrop Analogs; Final Project Review and Core Workshop (Kentucky

Geological Survey) - Lexington, KY. Contact: 304-293-2867 ext 54464/21-22 North Midcontinent: CO2 Flooding Potential in Kansas, workshop & field trips (KIOGA) - Russell, KS. Contact: 785-864-73984/22 Rocky Mountain: Subsurface Fluid Pressures and Their Relation to Oil and Gas Generation, Migration and Accumulation - Denver,

CO. Contact: 303-273-31074/27 North Midcontinent: Reading the Rocks from Wireline Logs (Kansas Geological Survey) - Lawrence, KS. Contact: 785-864-73984/28 North Midcontinent: Cased-Hole and Production Log Interpretation for Geologists (Kansas Geological Survey) - Lawrence, KS.

Contact: 785-864-73984/28 West Coast: Gas Field Technology - Sacramento, CA. Contact: 213-740-8076

May 20055/3-4 Texas: Petroleum Geoscience; Basics of Petroleum Generation, Migration, Trapping and the Oil Business (Ellison Miles

Geotechnology Institute) - Farmers Branch, TX. Contact: 972-860-46305/10-11 South Midcontinent: Morrow and Springer in the South Midcontinent (Oklahoma Geological Survey) - Norman, OK. Contact:

405-325-30315/12 Central Gulf: Low Cost Horizontal Well Technology - Lafayette, LA. Contact: 225-578-45385/12 Southwest/Texas: Horizontal Drilling - Hobbs, NM. Contact: 505-835-56855/13 Rocky Mountain: Geology of Horizontal Reservoirs; Past, Present and Future - A Core Workshop (RMAG, USGS) - Denver, CO.

Contact: 303-273-31075/16-20 Eastern Gulf Region: International Coalbed Methane Symposium (University of Alabama) - Tuscaloosa, AL. Contact: 205-348-18805/19 Rocky Mountain: SMT Kingdom Suite Data Loading - Golden, CO. Contact: 303-273-31075/20 Midwest: Pumpers & Well Operations Training (IOPA Tri-State) - Grayville, IL. Contact: 217-244-93375/235/23 Rocky Mountain: SMT Kingdom Suite 2d/3dPAK Interpretation Basics - Golden, CO. Contact: 303-273-31075/24 Rocky Mountain: SMT Kingdom Suite 2d/3dPAK Interpretation II - Golden, CO. Contact: 303-273-31075/24 Central Gulf: Productivity and Water Management in Potential of Inactive/Marginal Wells - Lafayette, LA. Contact: 225-578-45415/25 Rocky Mountain: SMT Kingdom Suite VuPak - Golden, CO. Contact: 303-273-31075/26 Rocky Mountain: GeoGraphix Overview and Refresher - Golden, CO. Contact: 303-273-3107

June 20056/7 Appalachian: Outcrop Analog for Trenton-Black River Hydrothermal Dolomite Reservoirs - Albany, NY. Contact: 304-293-2867 X 54466/7-8 Eastern Gulf workshop: PETRA Intermediate Cross Section Techniques (Mississippi Geological Society) – Raymond, MS. Contact:

205-348-18806/13-17 Rocky Mountain: Futures in Energy (Student Training/Internship) - Golden, CO. Contact: 303-273-31076/14 South Midcontinent: Natural Gas Balancing, Current Issues and Known Problems As Affected by JOA (Oklahoma Marginal Well

Commission) - Oklahoma City, OK. Contact: 405-604-04606/15 South Midcontinent: Natural Gas Balancing, Current Issues and Known Problems As Affected by JOA (Oklahoma Marginal Well

Commission) - Tulsa, OK. Contact: 405-604-04606/21 Southwest: Hydraulic Fracturing - Farmington, NM. Contact: 505-835-56856/26-7/1 Rocky Mountain: Futures in Energy (Student Training/Internship) - Pinedale, WY. Contact: 303-273-31076/26 7/1 West Coast: COMET 2005 - Los Angeles, CA. Contact: 213-740-80766/30 Rocky Mountain: Coalbed Methane Symposium (Rocky Mountain Association of Geologists) - Denver, CO. Contact: 303-273-3107

Position Name Affiliation City/StateChairman Brian Sims Independent Madison, MSVice Chairman Gene Ames III The Nordan Trust San Antonio, TXImmed. Past Chairman Brook Phifer NiCo Resources, LLC Littleton, CO

Appalachian Rick Goings Dominion E&P, Inc. Jane Lew, WVCentral Gulf Joe Jacobs Gas Masters of America, Inc. Monroe, LAEastern Gulf Karl Kaufmann Valioso Petroleum Company Flowood, MSMidwest Richard Straeter Continental Resources of IL Mount Vernon, ILNorth Midcontinent Mark Shreve Mull Drilling Co., Inc. Wichita, KSRocky Mountain Robert McDougall Westland Energy Inc. Cody, WYSouth Midcontinent Fletcher Lewis Fletcher Lewis Engineering Oklahoma City, OKSouthwest David Boneau Yates Petroleum Corp. Artesia, NMTexas Allen Gilmer Vecta Exploration, Ltd. Austin, TXWest Coast Chris Hall Drilling & Production Co. Torrance, CAAAPG Eddie David David Petroleum Corp. Roswell, NMIOGCC John King Michigan Public Service Comm. Lansing, MIIPAA Allan Frizzell Enrich Oil Corporation Abilene, TXSEG Hugh Rowlett ConocoPhillips Houston, TXSPE Ken Oglesby Oak Resources Inc. Tulsa, OKLarge E&P Companies Robert Lestz ChevronTexaco Houston, TXService Companies Mo Cordes Schlumberger Oilfield Services Houston, TXRegional Lead Orgs. Doug Patchen NRCCE - West Virginia University Morgantown, WVExecutive Director Don Duttlinger PTTC Houston, TX

PTTC’s National Board of DirectorsGuided by Independents for Independents

Interested in participating at the regional level? Call 1-888-THE PTTC

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PTTC Network News Staff:

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Kristi Lovendahl Editor

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Don Duttlinger Executive Director

E. Lance Cole Project Manager

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