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After several months hard work compiling aconcise operator-oriented manual on"Produced Water and Associated Issues,"PTTC's South Midcontinent Region recentlycompleted a series of workshops inOklahoma and Arkansas. The workshopswere held in cooperation with the OklahomaGeological Survey, Oklahoma's Marginal
Well Commission and SPE chapters in Tulsaand Oklahoma City.
The manual, developed by Rodney Reynolds(Kansas) and Bob Kiker (Texas), addresses akey constraint on oil production identified inPTTC's DOE-supported PUMP (PreferredUpstream Management Practices) project.The manual captures insights from numerousPTTC workshops held in prior years, pre-ferred practices for controlling well failuresfrom interviews with operators, and informa-tion from other sources. At its core, the man-ual addresses three key questions:
• Do you know if you're producing morewater than you have to?
• If so, do you know accepted techniquesfor reducing water production?
• If you must lift a lot of water, are yousatisfied that you are doing everythingyou can to control your operating costs?
The entire manual is online on PTTC's web-site (www.pttc.org). Plans are already inmotion to repeat the workshop in severalother regions during 2003.
PTTC's West Coast Region, also part ofPTTC's PUMP project, recently announcedthat $300,000 of supplemental funding hadbeen obtained from the California EnergyCommission (CEC). Work from this fundingwill focus on the sources of excessive waterproduction in California. Solution templatesshowing producers how to implement effec-tive water control methods appropriate fordifferent geologic environments inCalifornia will be developed. The funds alsoprovide for limited field demonstration.Additionally, Global Energy Partners hasincentive funds for field work to reducewater/power consumption in another ongo-ing program (www.cutopex.com) sponsoredby California Public Utilities Commission.
Maintaining A Strong Focus on Produced Water
Environmental Corner . . . . . . . . . . . . .3
Tech Transfer Track . . . . . . . . . .4-6
State-of-the-Art Summary . . . . .7-9
DOE Digest . . . . . . . . . . . . . . .10-11
Solutions From the Field . . . . . . .12
Upcoming PTTC Events . . . . . . . . .15
PTTC is a national not-for-profit informa-tion network formed in 1993 by oil andnatural gas producers. Programs are fund-ed primarily by the US Department ofEnergy’s (DOE) Office of Fossil Energythrough the National PetroleumTechnology Office (NPTO) and StrategicCenter for Natural Gas (SCNG) within theNational Energy Technology Lab (NETL).Other funding comes from state govern-ments, universities, state geological sur-veys, and industry contributions.
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. 9, No. 1 1st Quarter 2003
DOE Oil & Gas R&DFunding Trends
Continuing the trend of recent yearsthe Bush administration's FY04 bud-get proposes $26.6 million for naturalgas R&D and $15 million for oilR&D nationally. FY03 funding levelsrecently approved by Congress andawaiting the President's signaturetotal $89.6 million for oil and gasR&D, an 11% reduction from FY02levels. The FY04 budget proposed bythe administration represents a morethan 50% reduction (see table on page2). Historically, Congressional actionhas adjusted administration requestsupward, but it remains to be seenwhat direction Congress will take forFY04.
Cont. on page 2
PUMP Produced Water Workshops
2
News In General
Southwestern PetroleumShort Course
April 16-17, 2003Lubbock, Texas
www.pe.ttu.edu/SWPSC/index.htm
Meeting Alerts
11th Annual Williston BasinHorizontal Well Conference
April 27-30, 2003Saskatchewan, Canada
www.gov.sk.ca/enermine/geomines/williston/11-williston.htm
Offshore Technology Conference
May 5-8, 2003Houston, Texas
www.spe.org/otc2003/
AAPG Annual Meeting
May 11-14, 2003Salt Lake City, Utah
(see ad on page 14)
Bill and Linda Harrison at Western Michigan University in Kalamazoo provide valuable PTTCoutreach to Michigan industry, but PTTC is only part of their vision. There is an active cam-paign to provide a new building for the Michigan Basin Core Research Laboratory (MBCRL).Current space is filled to the walls with core and sample boxes which require a proper storageclimate. MBCRL is envisioned as a focal point for bringing together Michigan data from manysources making hard copy data available electronically and housing valuable cores.
DOE’s 4th AnnualSmall Business Conference
May 12-15, 2003Albuquerque, New Mexico
www.smallbusiness-outreach.doe.gov/annual/index.html
Network News
Michigan Crew Delivers
SPE 2003 Forum Series
July 13-18: Drilling Rigs of the FutureJuly 13-18: Eliminating Wastes & Emissions
July 20-25: Decommissioning & WellAbandonment
Park City, Utah
www.spe.org (meetings, 2003 calendar)
Many DOE programs are designed to encour-age environmentally responsible domesticproduction from marginal fields operated pri-marily by independent producers.Participation in the form of cost share fromindustry, state budgets and academia providessubstantial leverage for these programs. Butthe reality is that federal budgets are understrain and even programs with attractive ben-efits are undergreat scrutiny.
R&D programs bymajor producingcompanies havebeen significantlydownsized. The service sector is shoulderingmore of the R&D responsibility but stockmarket investors force companies to focus onshort-term results. Investment in the domesticenergy sector is severely challenged. All fac-tors combine to create an environment wheretechnologies appropriate for mature U.S.reservoirs receive inadequate resources fordevelopment or adaptation. In this environ-ment, there is a role for federal funding.
The federal government balances short-termand long-term objectives in providing reliable
and affordable energy to consumers acrossthe country. In the short term, DOE-support-ed R&D is making an impact in reducingrisks for smaller independent operators andmany would like that work to continue. Theseprojects would not be possible today withoutparticipation from DOE. This is exemplifiedin the California project (see article page 1)which focuses on improving energy efficien-
cy while dealing withvast amounts of pro-duced water.
The role for govern-ment in long-term,high-risk R&D invest-
ments is to ensure new technologies directedat more unconventional resources continue toenter the pipeline to commercialization sothey are available in the future. These pro-jects have significant potential for leveragingdeveloping technologies in other industriesfor application in the energy industry.Leveraging extends scarce resources andspeeds commercialization. Adequate fundingis essential to stimulate the continued flow oftechnology into the industry.
Cont. from page 1 New Board Leadership at PTTC
During a March 17 Board meeting inWashington, PTTC elected new leadershipfor its national Board. Effective immediate-ly, the new leaders are:
Chairman—James BruningBruning Resources LLC, Fort Smith, ARVice Chairman—Brook PhiferNiCo Resources Inc., Littleton, CO
PTTC thanks Immediate Past Chair ClarkSouthmayd, Jr., Oneok Resources Co.,Tulsa for his faithful service to PTTC.Watch for an extended interview with Mr.Bruning in the next issue.
Department of Energy Oil & Gas R&D BudgetFY02 (MM $)
ActualFY03 (MM $)
ActualFY04 (MM $)
ProposedNatural Gas
OilCombined
45.2 47.3 26.656.0 42.3 15.0
101.2 89.6 41.6
3Network News
Environmental Corner
eTools for Safety in Oil and GasWell Drilling and Servicing
Working with industry, the OccupationalSafety and Health Administration (OSHA)has developed an online eTool for WellDrilling and Servicing. This eTool, accessibleat www.osha.gov/SLTC/etools/oilandgas/index.html, is a stand alone, interactive, web-based training tool designed to augment com-pany safety programs. Current sections, eachwith additional submenus, include: site prepa-ration, drilling, well completion, servicing,plug and abandon, and general safety. TheAssociation of Energy Service Companies,along with representatives from the AmericanPetroleum Institute and InternationalAssociation of Drilling Contractors, workedwith OSHA in developing the eTool.
Ceramicrete-based Sealant forPermafrost Environment
In a project within DOE's Natural Gas andOil Technology Partnership (NGOTP), chem-ically bonded phosphate ceramic (CBC) bore-hole sealants are being evaluated for oilfieldapplications. CBCs are cement-like, rapid-setting dense materials with great tensile(connected porosity of <2 percent) and com-pressive (>8000 psi) strengths. They are self-bonding and bond with sandstones, shales,and other types of formation rocks.
CBC sets within hours, even in saline water,is stable in pH 3-11 environments, and is bothdrillable and machinable. It so happens thatCBC sealants also exhibit good properties atlow temperatures as might be encountered ina permafrost environment.
Argonne National Lab (ANL) is performinglaboratory tests to explore this niche per-mafrost application. In laboratory tests, char-acteristics of Ceramicrete-based sealant withClass C and F ashes was monitored at per-mafrost conditions. ANL has plans for furthertesting with hollow silica spheres, whichwould lower the thermal conductivity evenmore without altering pumping characteris-tics.
For further information about this nicheapplication or ceramic sealant work in general, contact Arun Wagh, phone 630-252-4295, email [email protected].
State Rules and Regulations on CD-ROM
The Interstate Oil and Gas CompactCommission (IOGCC) recently released anew CD-ROM, Summary of State Statutesand Regulations for Oil and Gas Production.
Coverage is provided for 37 states, plusIOGCC's international affiliates (Republic ofGeorgia and government of Newfoundlandand Labrador, Canada). Among others, topicsinclude: bond, casing and tubing, completion,documents required, drilling permit, spacing,underground injection, and unitization.Purchasers can join an automatic subscriptionlist to receive the summary update each year.The CD-ROM costs $30 and may be orderedonline (www.iogcc.state.ok.us). Hardcopy ina three ring binder with state dividers costs$105 and may be ordered by calling IOGCCat 405-525-3556.
Deepwater Well ControlGuidelines on CD-ROM
Deepwater well Control Guidelines by theInternational Association of DrillingContractors are now available on CD-ROM.Developed for those drilling in deepwater, theguidelines focus on well planning, well con-trol procedures, equipment and emergencyresponse and training. Included with theguidelines are a 2000 supplement that coversunplanned disconnects in deepwater drilling,riser margin overview, external loading ofBOP equipment and volumetric rating of sub-sea accumulator bottles. When purchasedonline (www.iadc.org), cost is $125.
Produced Water Life Cycle CostIn a recent SPE paper and article, ShellInternational shared data from their analysisof produced water management. Operatorsknow produced water is a major issue, butjust how major. Overall average cost consid-ering the total life cycle for Shell is $0.58 perbarrel.
Components of that overall cost include:Pumping (28%), De-Oiling (21%), Lifting(17%), Separation (15%), Filtering (14%),Injecting (5%).
The above may seem high, but think aboutproduced water's "true" cost. Shell notes thatan integrated approach is needed for individ-ual fields, if not even wells (i.e., one sizedoesn't fit all). Top priority is given to mini-mizing produced water volumes close to thesource. Effective water management startseven with the drilling phase. Thorough under-standing of reservoir geology, fluids andwater entry points is required.
For that water which must be produced, onemust look for ways to realize value.Waterflooding is a common example of real-izing value through injection. Beyond injec-tion, industry is working towards refiningtechnologies for cleaning up water for otherbeneficial surface use.
Extracted from "Water To Value—ProducedWater Management for Sustainable FieldDevelopment of Mature and Green Fields,"by Zara Khatib and Paul Verbeek in Journalof Petroleum Technology, January 2003, pp.26-28 (SPE73853).
Pollution-Free Power Plant ofThe Future
DOE Secretary Abraham recently announcedplans for building a prototype of the fossilfuel power plant of the future, dubbedFutureGen. This one billion dollar venturewill combine electricity and hydrogen pro-duction virtually eliminating harmful emis-sions, including greenhouse gases. DOE isasking the power industry to organize a con-sortium and provide at least 20% of the costs.Plans are for the plant to be built over thenext five years, then operated for at least fiveyears beyond that. The plant would be sizedto generate about 275 megawatts of electrici-ty, roughly equivalent to a mid-sized coal-fired power plant.
Carbon sequestration will be a primary fea-ture that will set the prototype plant apartfrom other power plants. Carbon dioxidewould be captured and sequestered in deepunderground geologic formations, which insome cases might be in hydrocarbon reser-voirs for additional recovery. The initial goalis to capture at least 90% of the plant's car-bon dioxide and even better capture may befeasible with technology advances.
Beyond operating virtually emission free,DOE anticipates that technology advanceswill significantly increase plant efficiency, asmuch as double conventional coal-burningpower plants.
In a related effort, DOE and the Departmentof State outlined plans for creating the inter-national "Carbon Sequestration LeadershipForum." The Forum will bring together min-isterial-level representatives to discuss thegrowing body of research and emerging tech-nologies for permanently isolating carbondioxide and other greenhouse gases. An inau-gural meeting is planned in Virginia duringJune.
For more information, see DOE's techlinewww.netl.doe.gov/publications/press/2003/tl_cslf.html and tl_futuregen1.html.
Regulatory Requirements forDrilling Waste Injection
February 2003, A New DOE Reportwww.npto.doe.gov
4Network News
Tech Transfer Track
PTAC CBM ConferenceProceedings Now Available
Proceedings from the 4th Annual CanadianCoalbed Methane Forum held last October inCalgary by the Petroleum TechnologyAlliance Canada (PTAC) are now available.The CD-ROM costs $200 Canadian.Proceedings for the 3rd conference are alsoavailable, costing $50 Canadian. To order,contact Brenda Belland, phone 403-218-7712, email [email protected].
PTAC is a Canadian not-for-profit associationthat facilitates collaborative research andtechnology development. It acts as a match-maker between those that have problems oropportunities and those that have potentialR&D solutions. PTAC brings stakeholderstogether to identify areas where R&D willmake a difference, and to launch specific pro-jects to address these problems or opportuni-ties. PTAC promotes industry participation inthe resulting R&D and assists with securingfunding from a variety of sources. PTAC alsofacilitates the transfer of commercial tech-nologies from other industrial sectors forapplication in the upstream oil and gasindustry.
PTAC hosts three types of events—work-shops, technology information sessions andforums/conferences. Workshops, which canbe co-sponsored by other associations andgovernment regulators, are utilized to clearlydefine industry challenges and opportunities.Technology Information Sessions are typical-ly conducted by PTAC R&D supplier mem-bers with an industry or government regulatorco-sponsor indicating the proposal or technol-ogy is "worthy of consideration." Forums/Conferences are conducted to communicateongoing or completed research results. VisitPTAC's website (www.ptac.org) to learnmore.
Drilling Well Classification System
The American Association of PetroleumGeologists and the American PetroleumInstitute have agreed on a system, developedby Lahee in 1944, for classifying drillingwells. Such a system aids in clarifying thedegree of technical, financial, and economicrisk of a proposed well. Classifications, andconcise explanations if needed, include:
• New Field Wildcat—far from producingfields and on a structure that has not pre-viously produced. If structure doesn'tcontrol production, location would be atleast 2 miles from productive area.
• New-Pool (Pay) Wildcat—new pools onstructure already producing, or if struc-ture doesn't control production, less than2 miles from productive area.
• Deeper Pool (Pay) Test• Shallower Pool (Pay) Test• Outpost or Extension Test—usually two
or more locations from nearest produc-tive area.
• Development Well• Stratigraphic Test—drilled without the
intention of being completed as a pro-ducer.
• Service Well—observation, injection,water supply, etc.
Excerpted from article in Go Gulf Magazine,Jan/Feb 2003, p. 24-25.
Expandable Technologies,Spreading Quickly
Industry usage of Expandable TubularTechnology (ETT) is growing rapidly. Somehave noted its potential impact might rank upthere with 3-D seismic and horizontaldrilling. After reading several recent articleson expandables, PTTC concurs with theassessment that expandables represent game-changing technology. So whether with a largeor small operator, one might as well get onthe learning curve.
In simple terms, the expandables processinvolves expanding steel by cold-working itdownhole to the required diameter.Expandable technologies refer to both slottedand solid expandable tubulars, associatedtools and accessories, and specialized systemsused to expand the special pipe.
Expandables have a language unto them-selves. One key term is EST (ExpandableSlotted Tubulars). ESTs are pipes with stag-gered overlapping slots cut axially along theentire length. Expansion up to 200% of origi-nal diameter can be achieved. Main applica-tions for ESTs are:
• Expandable Sand Screens (ESSTM)• Alternative Borehole Liners (ABLTM)• Expandable Completion Liners (ECLTM)
Solid Tube Expansion (STE) requires muchmore force than ESTs (remember, that isExpandable Slotted Tubulars). On expansion,the tubular changes in thickness and length,altering the strength and burst capacity of theexpanded pipe. There are numerous oilfieldapplications. STE technology can be used to:(1) create hangers and seals, (2) shut offunwanted perforations for water and gas, (3)strengthen existing corroded or worn casingand (4) retro-fit corrosion resistance.
Expandable technologies are workingtowards a single-diameter wellbore, whichwould eliminate typical telescoping casingdesign. Shell, an early and continuing player,estimates that STE technology has the poten-tial for reducing rig footprint by up to 75%,drilling muds by 20%, drill cuttings by 50%and cement by 50%. There are many targetsfrom offshore to deep Rockies gas whereexpandables could be employed.
Excerpted from "Expandable TubularTechnology," a supplement to World Oil,March 2003, sponsored by Weatherford.
Petris Enhances Internet Data Room Product
Petris Technology unveiled its Version 3.0 ofPetrisWINDS Internet Data Room at theNorth American Prospect Expo in Houston inJanuary. Increased flexibility in this latestversion enables users to quickly build theirown Internet Data Room. Version 3.0 incor-porates insights from Petris's three yearsexperience with sellers, buyers and transac-tion advisers.
Product flexibility makes it useful for collab-orative purposes beyond property transac-tions, including drilling and workover pack-ages, internal asset team management, andsharing data with outside partners.
The new version uses the ARC/IMS mapserver from Environmental Systems ResearchInstitute to provide map search capabilities. Itcan link to other Petris products and tools,including access to more than 50 E&P appli-cations from Petris's ASP (ApplicationService Provider) service, PetrisWINDSNOW.
The system is available over the Internet on amonthly rental basis. Visit www.petris.comfor an online demo of PetrisWINDS InternetData Room.
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.
5Network News
Tech Transfer Track
Kansas Geological SocietyLibrary Going Online
The extensive holdings of the KansasGeological Society are going online, all pos-sible due to advancements in scanning andstorage technology. Data from the state'ssouthern tier of counties is being tested andshould be available to subscribers in the firsthalf of 2003. Phase 1 includes about 30% ofthe library's data. Anticipation is that theentire collection will be scanned and onlinewithin 18 months to two years. The web-based system provides world-wide, 24/7access. A user is able to define a search anduse simple point-and-click operations to pickparticular wells and select individual docu-ments associated with the well. Documentscan be downloaded or printed. Cost for theeffort is currently estimated at $800,000 withnearly $500,000 of that received or pledgedso far. For more information, visit the pro-ject's website www.rfwgeolibrary.com.
Relays Reduce Field PowerDistribution and Equipment
FailuresOxy Permian, one of the largest oil producersin Texas operating more than 6,000 wells inthe Permian Basin alone, began installingrelays developed by Schweitzer EngineeringLaboratories in field environments in 1998.Oxy Permian's driving force was to under-stand vulnerabilities of their field power sys-tems and to reduce the failures so often expe-rienced during electrical storms. Results frominitial installations have prompted Oxy toconduct a system-wide optimization that is60-70% complete.
In looking at storm damage, Oxy was initiallyperplexed by residential power systems notbeing as vulnerable as oilfield power systems.Using relays, Oxy learned that what causedproblems during electrical storms was notlightning, but that the lightning amplifiedexisting problems. The source of the problemwas that 99% of the load was inductionmotors that behave differently from residen-tial load during upsets. Understanding that,they could then take appropriate action.
Electrical submersible pumps (ESPs) are oneespecially susceptible application. Every ESPshutdown can compromise equipment, poten-tially reducing pump life. Using Schweitzer'sSEL-701 relay and a special panel design,Oxy helped design a system that helps pre-vent motors from dropping off duringbrownouts or bumps. Eventually, the relaywill tell the motor to turn off. Oxy is also
planning to install the relay on beam-pumpedwells, which would eliminate the load cellthat sits on the rod. Eliminating the load cellwill eliminate the bulk of the failures becauseof the fact that load cells on the rod stringsfrequently separate from the pump-off con-troller, causing hundreds of failures eachyear.
Excerpted from "Relays Help Prevent Storm-Generated Power Failures," Oil and GasJournal, Jan. 13, 2003, p. 48-49. For infor-mation about specific relays, visit SchweitzerEngineering's website (www.selinc.com).
New Info Resource forMultilaterals
Estimates vary widely regarding how preva-lent multilaterals are, ranging from 10% to75% of the wells drilled each year dependingon the source. A joint-industry project formedin 1997, Technical Advancement ofMultilaterals (TAML), is known for its multi-lateral classification system. TAML believesthat multilateral technologies, despite theirincreasing use, are still not being used to theirfull potential. So TAML will focus on educa-tion for the next several years.
With this new focus, TAML will educate theindustry as a whole, from an industry per-spective, as opposed to the vendor communi-
ty perspective. TAML will develop and pro-vide operators and vendors with standardizedtender documents for bids. A standardizedquestionnaire will also allow operators toconverse with vendors in language both sidesunderstand. A selection guide will be anotherproduct. The purpose of TAML providing theinformation is analogous to an operator (apeer) making recommendations versusaccepting those of a vendor with admittedbias.
Technology transfer plans include presenta-tions, reservoir application data and shortcourses. There will be a strong web presencewith a public section of TAML:'s website(http://taml.altinex.no) containing case his-tories, technology and application updates,links, a bibliography, and more.
Excerpted from "TAML Refocuses OnEducating Industry On Multilaterals," byGuntis Moritis, Oil and Gas Journal, Feb. 10,2003.
Wellbore Schematics Made EZe-VIPR, a webbased software package devel-oped by WellEZ Information ManagementLLC, enables users to easily generate well-bore schematics. Users log onto the websiteand select the type of schematic to be con-structed from an option page. This launches a
Under the direction of Charles J. Mankin, PTTC's South Midcontinent Regional Director andDirector of the Oklahoma Geological Survey (OGS) and the Sarkeys Energy Center, OPIC(Oklahoma Petroleum Information Center) is coming together in Norman, Oklahoma. Operatedby the OGS, OPIC will house the Survey's Log Library, Core and Sample Library, PublicationsSales Office, and a conference center located across the street, making it the largest single petro-leum information center in the U.S.
The OGS log library contains the State's official log files for more than 367,000 wells, alongwith other logs, completion cards, and 1002A forms. OPIC also will house the BP core collec-tion, which is valued at about $2.5 million. This donation alone includes more than 100,000boxes of core samples and cuttings. There is room for more and additional donations are inprocess. Along with the cores, BP donated storage system components and core analysis equip-ment, including a fluoroscopic core scanning system that enables 360-degree evaluation.Publications and the Log Library are already operational in OPIC, and the Core Library shouldbe operational by fall 2003. OPIC is located at 2020 Industrial Blvd., near the prior PublicationSales/Marginal Well Commission site.
OPIC Coming Together in Oklahoma
6Network News
Tech Transfer Track
drawing tablet with appropriate associatedtools and images. Schematics are constructedby selecting an object, which is then draggedonto the drawing tablet where it can beresized and positioned. Once complete, userscan print or save as a pdf file. Data is storedon a central server, allowing multiple users toaccess the schematic. For further informa-tion, visit WellEZ's website at www.wellez.com.
Ziff Energy OperatingCost/Benchmarking Studies
In February Ziff Energy began collecting datafor its 4th Gulf Shelf Operating Cost Study.The study was last performed three years ago,assessing 1999 data. Participation is led byfour of the largest Gulf operators, who collec-tively account for more than a third of Shelfproduction. The study focuses on operationsin fields located in less than 1,000 feet ofwater and will analyze operating cost data for2002. It will feature extensive trend analysis,both on a company and field level.Participants will receive confidential, blinded,asset-level cost comparisons versus compara-ble assets, as well as detailed analyses of costdrivers. Delivery is scheduled for June 2003.For more information, contact Ziff EnergyGroup, phone 713-627-8282.
Ziff recently completed a benchmarkingstudy evaluating drilling costs and practicesfor gas wells in South Texas. The study ana-lyzed about 400 wells drilled by 12 operatorslooking at drilling and completion cost datafor 2001. Participants received a detaileddiagnostic report on each well, comparing itwith peer wells and identifying potential sav-ings in each cost category. Key metricsincluded $/ft, ft/day and $/Mcfe/day. Forshallow (less than 10,000 ft) normal-pressurewells, average drilling cost was $95/ft, butthe “best in class” well cost $53/ft or 44%less than average. Leading drilling practiceswere identified via questionnaire to partici-pants with Ziff then correlating specific prac-tices to performance. Operators who did notparticipate in this study may do so on a "late"basis by contacting Richard Tucker, [email protected].
Data Mining For Prospect Location
Data mining and statistical techniques avail-able to those looking for additional potentialin existing fields/basins where there typicallyare massive amounts of data include visualdata mining tools, cluster analysis, neural net-
works, decision trees and multiple regression.Data mining is a two-step process. First thereis visual data mining to identify patterns ofvisual interest, followed by applying algo-rithms such as decision trees.
When facing massive amounts of data, insome areas from thousands of wells, thehuman brain is limited in what it can absorbunless other tools are used. That is wherevisualization enters in as a tool for discerningpatterns. The use of different geometricshapes, size of data points and coloration areconstructive tricks that help add dimensional-ity to data. Data miners can increase dimen-sionality, up to as many as six levels, untilpatterns are discernible.
In the work documented in the referencedarticles, the authors mined data from morethan 6,300 gas wells drilled in BritishColumbia, Canada during the last 30 years,examining some 15 independent variablesagainst cumulative gas production (a highvalue being favorable). Free software, POV-Ray, which can be downloaded fromwww.povray.org, was used for plotting/visu-alizing the multi-dimensional day. POV-Raycan handle either scale or categorical data.Decision tree techniques along with certaincost/economic assumptions were further usedto quantify results.
Considering economics, their analysisfocused on predicting locations with cumula-tive production equal or greater than 3.392Bcf. For 23 well targets, the chance of "find-ing" that volume or greater was between 94%and 100%. They also found a second groupof 460 potential wells with a 63.1% to 66.6%chance of finding that volume or greater.What is the significance? The industry-widemedian value for reaching that volume orgreater is 14.9%. Data mining techniques pro-vide explorationists with scarce time "highprobability" locations where they can focustheir effort.
Excerpted from two-part series on data min-ing (Gas Well Development Through DecisionTrees; Data Mining Algorithm-DecisionTrees), James Cormier-Chisholm andChristian Sebastian, Oil & Gas Journal, Jan.20 & 27, 2003.
Finalists for MMS's2002 SAFE Awards
Fifteen finalists have been selected in theMinerals Management Service's (MMS's)2002 Safety Award For Excellence (SAFE)program. MMS presents annual awards infour categories to those who achieved the
best safety and pollution prevention perfor-mance records.
High OCS activity—Dominion Exploration &Production, Inc., ExxonMobil Corporation,and Newfield Exploration Company.
Moderate OCS activity—ATP Oil & GasCorporation, Bois d'Arc Offshore Ltd., HuntPetroleum (AEC) Inc., Nexen Petroleum,TotalfinaElf E&P USA, Inc., and WestportResources.
Drilling Contractor—ENSCO OffshoreCompany, Rowan Drilling, and TransoceanOffshore.
Production Contractor—Danos & CuroleMarine Contractors, Inc., Island OperatingCompany, and Wood Group ProductionServices.
Winners will be announced in an April 29threcognition ceremony in Houston(www.mms.gov/awards/index.htm).
O&G development maps for Illinois devel-oped by the Illinois State GeologicalSurvey are now available, costing $10.50per map. Each map is approximately a 3x3township grid and printed in three colorsat a scale of 2"=1 mile. The maps alsoinclude major roads, towns, pipelines, andrailroad tracks. Maps can be ordered bymail (Information Office, Illinois StateGeological Survey, 615 E. Peabody,Champaign, IL 61820), phone 217-244-2414, or email [email protected]. Visaand MasterCard are accepted.
Illinois O&G Development Maps
Produced Water Data Available Through KGS
The Kansas Geological Survey (KGS)makes an oilfield brine database availableat www.kgs.ukans.edu/Magellan/Brine/index.html. The database has 3,785 sam-ples with chemical analyses, of which1,473 have water resistivity measurements.The database will soon be augmented toinclude estimated water resistivities forsamples that have chemistry, but no waterresistivity measurements. KGS has ana-lyzed location of sample data (www.kgs.ukans.edu/ PTTC/News/ 2003/q03-1-4.html) and is particularly soliciting datafrom areas with scant coverage. To exploresubmitting data, contact Dana Adkins-Heljeson, [email protected].
7Network News
State-of-the-Art Summary
De-Watering Technologies Showcasedby Karl LangDe-watering gas wells was the topic of aworkshop held March 3-4 in Denver.Nearly 250 attendees listened to 33 pre-sentations focused on various approachesto the problem of economically optimiz-ing production from gas wells by mini-mizing the effects of liquid loading. The"Gas Well De-Watering Workshop" wasorganized and implemented by theArtificial Lift R&D Council (ALRDC),together with the American Society ofMechanical Engineers (ASME), theSouthwestern Petroleum Short Course(SWPSC) and Texas Tech University -Dept. of Petroleum Engineering (TTU).While space limitations do not permit usto discuss all of the papers individually,we have selected three topics on whichto comment from the wealth of excellentmaterial presented. The complete list ofpapers is available at www.wellanalysis.com. Copies of the actual presentations,currently available online for attendeesonly, may be made available to the gen-eral public at a later date at a cost.
Plunger Lift with the PacemakerPlungerPlunger lift, a technology widely used toremove liquids from gas wells, was thesubject of six papers. Two of these dealtwith the Pacemaker plunger, a newapproach to this traditional method ofartificial lift. Traditional plunger liftrequires shut-in time for the plunger tofall back to the bottom of the tubing andthen for the buildup of pressure to drivethe plunger back to the surface. Thisshut-in time results both in lost produc-tion and in the forcing of liquids backinto the formation. The Pacemakerplunger operates as two interdependentpieces (a piston and a ball), each ofwhich fall separately and are designed todo so against a significant rate of upwardgas flow (Figure 1). Once on bottom, theball seals off in a cavity in the piston.
Once the gas flow has driven both backto the surface a rod in the lubricator sep-arates the ball from the piston, enablingthe next cycle to begin. The result is thatonly 5-10 seconds of shut-in time percycle is required and liquids are notforced back into the formation.
A presentation by ChevronTexaco'sRobert Lestz described the results ofPacemaker installations in a variety ofTexas locations. In West Texas, a groupof ten wells showed a total increment of1200 Mcfd after conversion to thePacemaker plunger (Figure 2). Eight ofthese wells were converted from stan-dard plungers and two had been convert-ed from flowing. East and South Texasexamples showed even more dramaticresults, with some wells showing morethan 200% improvement in gas flow rateafter installation of the Pacemaker
plunger. In cases where soap was beingused to improve liquid lifting there werealso substantial savings in monthlychemical costs.
ChevronTexaco has employed thePacemaker in a wide variety of well con-figurations, including: tubing packercompletions, open ended tubing, mono-bore completions (no annulus), and as areplacement for capillary strings andstandard plunger lift. These applicationshave been in sandy environments, inconjunction with single well compres-sion, and even on both sides of a dualcompletion.
The primary benefit recognized by Lestzis the fact that there is practically noshut-in time. This minimizes productionfluctuations and means less interferencefor wells sharing the same facilities or
Figure 1—Different Size and Materials Pacemaker Plungers
8Network News
State-of-the-Art Summary
compression. The longer flow periodmeans more production and productionis not squeezed back into the formation.Stabilized production makes reservoiranalysis possible.
There are some limitations with thistechnology. It works best with low linepressure and at gas rates below ~150-200 Mcfd at FTP~ 80+ psia. Very highliquid rates impede the ability of the ballto fall and some problems can be pre-sented if the tubing is set too high, ifthere are shallow restrictions such asnipples in the tubing string, or if sandproduction is excessive. Finally, and thisis true for any new technology, peoplemust understand that the critical parame-ters are different than those for a con-ventional plunger lift installation and betrained to properly set the controller,troubleshoot and optimize. For vendorinformation go to www.mgmwellservice.com
Gas AugerMarathon presented the results of theirfield testing of their "gas auger" in the
Indian Basin field of Eddy County, NewMexico. The gas auger was developed tocombat operational difficulties associat-ed with producing free gas with sub-mersible pumping equipment. The pri-mary productive interval at Indian Basinis the U. Pennsylvanian Canyon &Cisco at a depth of 7500'. The reservoirconsists of 400-600' of carbonate. Thereis 6500 ppm H2S in the produced fluids.
Historically, wells in this field exhibit adramatic increase in water productionand an associated sharp decrease in gasproduction when they start to water out.Many wells flow 3-4 MMcfd before thewater encroachment and continue toflow 1-2 MMcfd with only 100-200Bwpd afterwards. Subsurface electricalpumps are used to produce the wells.
Gas interference is a problem with ESPsfor a number of reasons: poor coolingqualities, diminished efficiency anddown time. Because gas is produced upthe casing-tubing annulus Marathon isforced to run shrouded units and landthe pump intakes below the bottom per-forations. When gas is the cooling medi-um between the shroud and motor the
motors see higher temperatures and thisshortens the life of the motors and sealcomponents. In the case of some wellsthe problem was so severe that it wasnearly impossible to keep the pumpsrunning much less achieve optimumdrawdown. Free gas greatly diminishespump efficiency. This decreased effi-ciency means extra HP and more pumpstages are required to "pump" the gas.Down time associated with underloadsalso results from gas interference, lead-ing to lost production. Also, as the gaspasses through the pumps the stages,seal, and motor can go into upthrust.This can destroy pump stages over timeand can lead to sudden failure in the sealsection.
Marathon tried a number of convention-al approaches to dealing with this prob-lem, including shrouds, rotary gas sepa-rators, gas anchors, tapered ESP's, andothers, before developing the gas auger.The gas auger consists of a section ofconcentric tubing coupled with a seriesof external blades that are run below theperforated interval. The blades facilitatethe separation of gas from the liquid andthe concentric tubing string enables thegas to bypass the ESP more efficiently(Figure 3).
Augers have been installed in 13 wellsto date: Ten 7" models and three 9 5/8"models. Before and after tubing testsindicate a 75% separation efficiency.Marathon has successfully pulled andrerun 8 auger assemblies (and madesome improvements to theinstallation/pulling procedure along theway). Total BOEPD increase for augerinstallations is 3393 BOEPD, excludingproactive installations in new drill wells.On two wells, incremental productionhas totaled 1900 BOEPD from a$16,000 investment. On those two wellsalone Marathon recognized savings of$3200/month from decreased HPrequirements. The savings fromdecreased failure frequency is yet to bedetermined but could be significant.
Figure 2—Pacemaker Field Test Normalized Production from All Wells
9Network News
State-of-the-Art Summary
Chemical TreatmentsChemical treatments have been used tocombat liquid loading in gas wells, alongwith scaling and/or salting problems, formany years. Chemical foaming is used tolighten the hydrostatic load, enabling thewater to be lifted out by gas pressure.James Archer of Multi-Chem Group,LLC out of Sonora, TX presented apaper that outlined the critical parame-ters that should be analyzed before adecision is made to employ, or not toemploy, chemical foaming additives.
Application of foamingchemicals has pro-gressed from batchtreatments to constantapplication via concen-tric capillary tubing. Byallowing the chemicalinjection to take placeat the bottom of a well,other problems such asscaling can also betreated. Evaluating thewell is crucial to thesolution. Selection of afoaming agent isdependent upon con-densate ratio, requiredfoam quality and bub-ble size, presence orlack of an emulsion,and water chemistry.Testing of live fluids isnecessary, particularlyif additional chemicalcomponents are to beincluded to help pre-vent corrosion, scale,and salt deposition.
Archer provided threecase histories of suc-
cessful chemical de-watering. The first, aWilcox well in Webb County, Texas, wasproducing up tubing at 450 psig making5 barrels of total fluid per day but notresponding well to foaming agents.Sampling and analysis showed that thewell was actually producing about 25 to30% condensate. The well was subse-quently batch treated with 5 gallonsH2O, and 7 gallons foaming agent, downtubing and casing. An injection pumpwas then used to pump 8 gallons per dayof the selected foaming agent until thewell unloaded. Well went from 90 mcf to400 mcfd. The pump rate was reduced to
2 gallons per day and a rate of 375 to400 mcfd was maintained.
A Cotton Valley well in Bienville,Louisiana was flowing up tubing under apacker at 50 mcfd and had to be routine-ly shut in for pressure buildup and inter-mittently blown to a tank to unload, los-ing 2 to 3 days production per week.After analysis, the tubing was perforatedjust above packer and a foaming agentinjected in a 40% solution with 2% KCLwater at a rate of 15 gallons per day.Within two days after the foamer wasstarted, the rate was up to 385 mcfd. Theinjection rate was cut back to 8 gallonsper day, while the gas rate continued toclimb to 1200 mcfd.
A Wilcox well in DeWitt Co., Texas pro-duced 120 mcfd, 6 barrels of condensateand 8 barrels of brine per day butbecame plugged with salt every 2 weeksand had to be treated with fresh waterand shut-in for two days in order toreturn production. After analysis, a con-tinuous injection of a 20% solution offoamer in fresh water down hole througha ¼" capillary string was established at arate of 1.5 barrels per day. The wellresponded with a production increase to720 mcfd. Four months later, it contin-ued to produce approximately 720 mcfdwhile salting has been non-existent.
The variance in production fluids, con-densate ratios, and water make-up, caus-es various foaming agents to act withvarying results. Where complete studiesof water, foam testing, and evaluation offluid dynamics have been conducted,favorable results can be achieved. Usingfoaming agents to enhance gas well pro-duction provides a very cost-effective liftmethod, often greater than a 6:1 returnon investment in equipment and chemicals.
Author: Karl Lang, HART Publications. For further information, contact Lance Cole at [email protected].
Figure 3—Gas Auger Installation
10Network News
DOE Digest
Technology Advances ResultFrom DOE Class II Projects
Back in 1994, nine DOE-supported cost-shared field demo projects began in Class IIShallow Shelf Carbonate reservoirs. Later onin 2000, an additional six projects were fund-ed within DOE's Class Revisit program. Bynow the nine original projects have been fin-ished, while work is still ongoing in the sixClass Revisit projects. Projects are located inAlabama, Colorado, Kansas, the MichiganBasin, Oklahoma, Texas, Utah, and theWilliston Basin. Last December project per-formers gathered in Midland, Texas to sharewhat has been learned through the projects.DOE has summarized insights in its latestClass Act newsletter (Volume 9/1, Winter2003), available online at www.npto.doe.gov/CA/CAWin2003.pdf.
Highlights from a couple of projects follow.There were successes in other projects, andsome approaches didn't work as planned.Both positive and negative results have value.Readers are encouraged to review findingsdocumented in the Class Act newsletter andcontact project performers if further informa-tion is needed.
Recovery of Williston Basin Carbonates,Luff Exploration Company. In the initialClass project, Luff Exploration demonstratedhow seismic attribute analysis could be usedto characterize Red River/Ratcliffe targets. Itwas discovered that drilling on the flanks ofstructural features where porosity was betterdeveloped resulted in improved wells as com-pared to conventional wells located on top ofthe structure. Horizontal re-entry completionsproved to be an effective completion option.One demo site demonstrated waterfloodingusing horizontal injectors. In the later ClassRevisit project, an Intelligent ComputingSystem using neural networks and fuzzy logicfor reservoir analysis and risk assessment wasdeveloped. The ICS tool was used in theAmor Field to select sites for horizontal wellsin small structural features. Plugged oruneconomic vertical wells were re-enteredand drilled horizontally. Drilling in similarprojects using the ICS tool is planned during2003 and 2004. The ICS tool kit and instruc-tions may be downloaded at no charge fromwww.luffdoeproject.com. Project contact,Mark Sipple, Mark Sipple Engineering,phone 303-864-9734, email [email protected].
Optimizing Reservoir Performance in theHunton Formation, Oklahoma, TheUniversity of Tulsa (TU). In the WestCarney field, Hunton oil wells initially pro-duce at a very high water cut but, as oil and
high volumes of water are produced, thewater cut decreases. This behavior has beentermed retrograde oil cut. As the water/oilratio decreases over time, the gas/oil ratiofirst increases then decreases with time. Thisunique behavior led to rapid development ofmany Hunton wells in Oklahoma. To betterunderstand the why and how, and to deter-mine what other reservoirs might beamenable to this production process, the pro-ject team performed detailed reservoir charac-terization, including analyzing 27 cores, loganalysis, flow simulation and rate-time analy-sis of production data. Data indicate that theaquifer is limited, and water rate and pressureare declining as the field is produced.However, the bulk of hydrocarbon productionis through the water zone and dependent onit, such that wells that produce less water pro-duce less oil. Two workshops with an intrigu-ing title, Dewatering of the Hunton Reservoirin West Carney Field - Mystery Solved?, arescheduled, April 16 in Tulsa and April 21 inOklahoma City. For information about theseworkshops, contact Lori Watts, phone 918-631-2979, email [email protected].
Carbon Fiber Drill Pipe Usedin Short-Radius Horizontal
Re-EntriesEarly in 2003, Grand Resources Inc.,Oklahoma, used 2 ½-inch OD composite car-bon fiber drill pipe with 3 1/8-inch heat-treat-ed steel tool joints to drill short 70-ft radiusbuild portions in two horizontal re-entries.These re-entries in 5 ½-inch casing were in1,300 ft vertical wells in the Bird Creek Fieldin Tulsa County, Oklahoma. The wells wereoriginally completed in the 1920s. The pipeperformed favorably in the first well, but thesecond well encountered problems with thetool joint connections that the manufacturer isaddressing. After drilling a short portion ofthe horizontal legs, 30 ft and 60 feet in thetwo wells, the remainder of the laterals wasdrilled with standard steel drill pipe. The firstwell is now producing 12-15 bopd whilecompletion is in progress in the second well.Grand Resources will be using the compositedrill pipe in additional horizontal well boresin the coming months.
Advanced Composite Products andTechnology, Inc., Huntington Beach,California, developed the composite carbonfiber pipe in a DOE-supported project. It isexpected to be commercially available bysummer. Field testing of a larger 5 ½-inchOD pipe is planned this spring.
Although more expensive than steel drillpipe, the composite pipe has a big advantage.
It can remain bent for extended periods oftime while rotating without suffering fatigue,making it particularly well suited for short-radius horizontal applications. Plus it is muchlighter, weighing about half as much as steelpipe.
Information excerpted from DOE Techlineand article in Oil and Gas Journal, February24, 2003. For more information about thecomposite pipe, contact Brad Tomer (phone304-285-4692k, email [email protected]) or Gary Covatch (phone 304-285-4589, email [email protected]).
Produced Water TreatingMethod Impacts CBM Recovery
in Powder River BasinDOE released a study, Powder River BasinCoalbed Methane Development and ProducedWater Management, late last year. The study,performed by Advanced ResourcesInternational, found that 29 Tcf could be eco-nomically produced with surface water dis-posal, the current prevalent practice.Requiring that water be re-injected into shal-low fresh water zones would reduce recoveryto 27 Tcf, while requiring treatment byreverse osmosis would further reduce recov-ery to 18 to 22 Tcf.
The study's 39 TCF estimate of technically-recoverable reserves is among the highest ofa range of resource estimates. For reference,proven gas reserves in the lower 48 states isestimated at just over 180 Tcf. The study alsoconcluded that future development willrequire fewer wells than previously estimated.
For more information, visit DOE's NETLwebsite (www.netl.doe.gov/publications/press/2002/tl_cbm_powderriver.html) orcontact John Duda, DOE NETL, phone304-285-4217, email [email protected].
Four More Awards in DOE'sIndependents Program
In January DOE announced the four mostrecent project awards in its TechnologyDevelopment with Independents program. Inthis program, small independents (up to 50employees) can receive awards up to$100,000. 50% cost share is required.
Vecta Exploration, Inc. (Texas) will completea shear wave seismic study documenting theimaging quality, costs, and potential benefitsof combining S-wave and P-wave seismicdata. Conventional 3-D seismic survey meth-ods today use only compressional (P) waves,
11Network News
DOE Digest
which generally works well for identifyingstructural features. However, successfuldrilling depends not only on structure, but onlocating rock fractures, detecting porositytrends, and locating subtle areas of trappedoil. Combining S-wave with P-wave data pro-vides a more complete geologic "picture."
St. James Oil Corporation (California) willuse a new hydrochloric-phosphonic acid solu-tion to restore oil production in shut-in wellsin the Las Cienegas Field in Los Angeles.When shut down for more than a year, reacti-vated wells in this field typically produce 30to 50 percent less than prior to shut down dueto calcium carbonate scale buildup. The phos-phonic acid reacts with minerals in the rockto form a temporary protective film, allowingdeeper penetration and more effective reac-tion from the hydrochloric acid, inhibitingand reducing the formation of additional cal-cium carbonate scale.
Crystal River Oil and Gas LLC (California)will test a new polymer gel treatment processfor water shut-off in oil wells in the AlamedaField in Kingman County, Kansas. The newpolymer gel is comprised of two chemicals: apowdered polyacrylamide polymer, which isa strengthening agent, and chromic acetate.Together they form a high strength thickenedgel that will be pumped under high pressureinto the selected wells. Each well will be leftidle for 3-4 days, after which the wells willbe returned to production.
Team Energy LLC (Illinois) will test the feasi-bility of using specially designed instrumen-tation to control well pumping operations tolimit salt water production. Two types ofinstrumentation, a fluid density meter and aninductive electrical conductivity meter, willbe used simultaneously. Since the density andelectrical conductivity properties differbetween oil and water, the instrumentationshould be able to detect which fluid is in theproduced stream. The pump will be shutdown when water is detected. Performancewill be evaluated in two active pumpingwells, one idle well, and one flowing well inthe Illinois Basin in Posey County, Indiana.
Stripper Well ConsortiumProposals Due April 18
Those seeking funding from the DOE-sup-ported Stripper Well Consortium (SWC) dur-ing 2003 must submit abbreviated writtenproposals by April 18, plus present their pro-posal orally to the SWC in its spring meetingon May 5-6. Proposals are accepted onlyfrom Full Members (membership fee may beenclosed with proposal) and require 30% costshare. Period of performance for those win-
ning awards is July 1, 2003 to June 30, 2004.To see the diversity of topics being exploredwithin the SWC, review projects awarded lastspring. Information is posted on the SWCwebsite (www.energy.psu.edu/swc/ projec-toverview.shtml).
DOE Makes 10 Awards in itsPRIME Program
On March 11, DOE announced 10 awards forresearch within its PRIME Program. PRIME(Public Resources Invested in Managementand Extraction) differs from DOE's other oiltechnology R&D programs in that it stresseshigh-risk research on concepts that mayrequire five to 10 years to develop. A majorgoal is to develop new approaches that canlead to enhanced production of oil resourceson public lands.
Total cost of the 10 projects is $11.8 millionwith DOE providing $8.7 million or 74% ofthe funds and the performers the remainder.The projects are located in Alabama,California, Mississippi, Oklahoma, Texas,Utah and Wyoming. Topics span a range ofexploratory research efforts. Awards weremade in three areas.
Area 1 - Oil and Gas Recovery Technology
Stanford University: ExperimentalInvestigation and High Resolution Simulatorof In-Situ Combustion Processes
Rice University: Surfactant-Based EnhancedRecovery Processes and Foam MobilityControl
University of Southern Mississippi: Smart,Multifunctional Polymers
University of Wyoming: Fundamentals ofReservoir Surface Energy as Related toSurface Properties, Wettability, CapillaryAction and Oil Recovery from FracturedReservoirs by Spontaneous Imbibition
Area 2 - Drilling, Completion andStimulation
Terra Tek, Inc.: Smaller Footprint DrillingSystem for Deep and Hard RockEnvironment; Feasibility of Ultra-High SpeedDiamond Drilling
The University of Texas at Austin, Petroleum& Geosystems Engineering Department: AComprehensive Statistically-Based Method toInterpret Real-Time Flowing WellMeasurements
University of Tulsa: Development of NextGeneration Multiphase Pipe Flow PredictionTools
Area 3 - Advanced Diagnostic and ImagingSystems and Reservoir Characterization
University of Alabama: Basin Analysis andPetroleum System Characterization andModeling, Interior Salt Basins, Central andEastern Gulf of Mexico
The University of Texas at Austin, Bureau ofEconomic Geology: Elastic Wave FieldStratigraphy - A New Seismic ImagingTechnology
Texas Engineering Experiment Station, TexasA&M University: Interwell Connectivity andDiagnostic Using Correlation of Productionand Injection Rate Data in HydrocarbonProduction
DOE's tech line (www.fossil.energy.gov/tech-line/tl_prime_sel03.shtml) provides furtherdetails on the individual projects.
Alaskan Methane HydrateResearch Well to Demonstrate
New Arctic Drilling PlatformHot Ice 1, a dedicated methane hydrateresearch well, was spudded in the AlaskanNorth Slope in March. An industry team ofMaurer Technology, Inc., AnadarkoPetroleum Corporation and NobleEngineering and Development led the effortin the 3-year, $10+ million cost-shared coop-erative agreement with DOE. Obviously, theprimary focus is to gather data on methanehydrate occurrence and production, but theresearch well will also demonstrate a newArctic Drilling Platform, patented byAnadarko and constructed in Houston. Thisnew drilling platform allows for an extendeddrilling and testing season, from three or fourmonths to eight or nine months.
The new platform consists of 16 aluminumpieces with legs that screw into the soil.Because of the screw design, they don't haveto be as deep as pilings. It is light enough tobe transported by helicopter or a large all-ter-rain vehicle and assembled on site. Gravelroads and pads, which can leave long-lastingscars, aren't needed. It sits 12 feet off theground, high enough that animals don't haveto go around it. It can be used for exploratorydrilling and for production. It is big enoughto hold a drilling rig and auxiliary equipment.
Regardless of the outcome of Hot Ice 1, thereare other applications for the platform. Formore information contact the project's princi-pal investigator, Tom Williams, [email protected], with MaurerTechnology.
12Network News
Solutions From The Field
Applied DigitalSubsurface Mapping
April 18-19, 2002 (Mt. Carmel, IL)by PTTC’s Midwest Region
BOTTOM LINEThe University of Illinois has concentrated onimproved methods of digital mapping, includ-ing Trend Analysis and 3-D Modeling. TrendAnalysis is based on a method for differenti-ating regional and local components in a maparea. Three-dimensional modeling provides atool for visualization of the spatial distribu-tion of data collected by geologic, geophysi-cal, petrophysical and engineering means. Anexample of trend analysis would be todescribe an anticline as a local anomalyoccurring along a regional dipping surface.
PROBLEM ADDRESSEDPetroleum exploration depends on identifica-tion of anomalies between regional and localcomponents in a map area. Trend analysisprovides a tool for efficient discriminationand 3-D modeling is the best means for visu-alization of the data.
2002 RockiesCoalbed Methane Symposium
June 19, 2002 (Denver, CO)co-sponsored by PTTC’s Rocky MountainRegion, The Rocky Mountain Association ofGeologists (RMAG) and Gas TechnologyInstitute (GTI)
BOTTOM LINECoal-bearing basins in the United States arein competition for frontier coalbed methane
(CBM) resources. Acreage position andknowledge of the best geological and engi-neering methods for evaluation and develop-ing CBM resources are needed.
PROBLEM ADDRESSEDCBM plays in the San Juan, Powder River,Raton and Uinta basins are maturing, andlessons learned in these basins are not neces-sarily applicable for new plays and otherbasins. The goal of the 2002 CBMSymposium was to explore all the existingand emerging technologies and focus on howto apply them to new CBM plays, such as inBritish Columbia and eastern Kansas. Thenumber of participating companies, sponsorsand exhibitors indicate the high interest inCBM exploration and development.
Improving Oil Recovery UsingIntegrated Evaluation Techniques
April 23, 2002 (Wichita, KS)by PTTC’s North Midcontinent Region
BOTTOM LINEThe Kansas Geological Survey has developednew technologies and strategies to improveoil recovery from Kansas oil fields. The focushas been to provide increased access to publicdata through online digital programs, devel-opment of log analysis software, improvedreservoir characterization, modeling and com-puter simulations.
PROBLEM ADDRESSEDThe Kansas Geological Survey (KGS) carriesa responsibility to the independent operatorsin Kansas to provide data and advanced eval-uation and interpretation techniques for
hydrocarbon exploration and production.Individual operators do not have the facilitiesor manpower to accumulate and access all thepublic data collected by the state of Kansas.KGS researchers are able to improve meansof access to data, and demonstrate new tech-nologies and best practices through develop-ment of software, methodologies and casestudies applicable to Kansas oil fields.
Produced Water Dec. 4-5, 2002 (Farmington, NM)by PTTC’s Southwest Region
BOTTOM LINETo increase well/lease profitability, producersshould implement a strategy to reduce exces-sive water production. Industry has developedproven practices for determining if there real-ly is a problem, correctly diagnosing it andfinding the appropriate solution. Solutionscan range from the simple mechanical tochemical such as polymer gels. With properapplication and operator/provider coopera-tion, success rates with polymer gels canexceed 90%. Industry increasingly is lookingfor ways to treat produced water for benefi-cial use, but much R&D remains to be done.
PROBLEM ADDRESSEDOn average in the U.S., for every barrel of oilproduced, there are some 8-9 barrels of waterproduced. This high volume of producedwater significantly increases power consump-tion and operating costs and can cause envi-ronmental problems. Operators are constantlysearching for improved technologies to man-age the produced water issue, including eventreating it for beneficial use.
Solutions from the Field: Online Technologies to Solve Problems Faced by Independent ProducersSummaries of regional workshops recently sponsored or co-sponsored by PTTC are added to its national web site regularly. For more complete sum-maries, and for a listing of the hundreds of workshops that PTTC has sponsored since 1995, logon to: www.pttc.org. For more details, contact 1-888-THE-PTTC, e-mail: [email protected].
Alerts Via E-Mail: Another PTTC Service American Oil and Gas ReporterTech Connection Column
MarchUnderstanding Paraffin Is Necessary
First Step To Control Deposition
FebruaryEnvironmental And Cost Benefits
Result From Controlling Water
JanuaryNatural Fractures Among Keys toDeveloping Unconventional Gas
Invited Articles Applications Underscore Potential
of IOR Technologies
PTTC HighlightCalifornia providing $300Kto PUMP Project
"Produced Water AndAssociated Issues" ManualNow Online
From Operations ThroughStimulation Optimization,Case Studies forIndependents
Appalachian Region-NewGIS Capability for Trenton-Black River, CBM,Horizontal
Industry HighlightExpandable TechnologiesSpreading Rapidly
Reliable, Accurate HighWater-Cut Meter
Paraffin, Various Options forControl
CO2 Flooding ContinuesStrong
DOE HighlightDOE Selects 10 Projects forOil Research
Stripper Well Consortium Proposals Due April 18
Four More IndependentsProjects Receive DOEAwards
DOE Extends Due Date forRound 3 "Independents"Proposals to Feb. 10
Mar. 13
Feb. 27
Feb. 12
Jan. 16
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Regional Roundup
CONTACT THE PTTC REGIONALRESOURCE CENTER IN YOUR AREA:
Appalachian RegionDirector: Doug PatchenWest Virginia University304-293-2867, ext. 5443www.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 Alabama205-348-4319http://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.htm
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 Austin512-471-1534Coordinator: 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 III269-387-5488http://wst023.west.wmich.edu/pttc.htm
Permian BasinBob Kiker 432-552-3432www.energyconnect.com/pttc/pb/
1st Quarter 2003 Case StudiesPetroleum Technology Digest
Polylined tubing reduces downhole fail-ures
Bottom Line: Field results in the pastfew years have proven that using polylin-ers can increase uptime and save money -even over plastic coatings. Many opera-tors are using polylined tubing to reducewell failures from rod-tubing wear andtubing corrosion in artificial lift andinjection wells. BP America,ChevronTexaco, Conoco and Fasken Oiland Ranch have used polylined tubularsin over 41 wells with substantial savingsin operating costs.
Using capillary strings to unload gaswells and increase production
Bottom Line: ChevronTexaco has suc-cessfully employed capillary strings inSouth and East Texas to resolve problemsassociated with liquid loading.ChevronTexaco now has more than 100installations. Detailed analysis of the ini-tial 17 installations in South Texasrevealed a 74% success rate. Installationcosts, which can approach $15,000, willpay out in less than three months withrepresentative gas prices and productionincreases (100 mcfd).
Reverse circulation drilling avoidsdamage to low-pressure gas reservoirs
Bottom Line: PressSol Ltd. of Calgaryhas adapted reverse-circulation, center-discharge drilling (RCCD) for oil and gasdrilling. Because RCCD drilling returnscuttings through the ID of the inner por-tion of double-wall drill pipe, it does notexpose the formation to possible damagefrom drilling fluid and, thus, is particular-ly well suited for drilling low-pressurereservoirs. K2 Energy of Calgary hasapplied RCCD to successfully drill andtest gas wells in the low-pressure (forma-tion pressure estimated at 150 psi) BowIsland formation on the Blackfeet IndianReservation in northern Montana. As ofFebruary 1, 2003, the system has beenused to drill 11 Bow Island wells on thereservation and an additional five wells inthe Thrust Belt. Drilling cost is competi-tive with mud or air drilling in that area;$15/ft for surface string to 600 ft and$10/ft for a long string to 2,500 ft. Thesystem can be adapted to any rig with theaddition of a dual-wall drillstring.S
Recognized industry speakers in Jan. 22 Workshop in California. From Left to right—J. Portwood and JimMack, Tiorco Inc.; Ralph Cook, moderator, Enhanced Petroleum Tech, Inc; Iraj Ershaghi, PTTC West Coast;Rich Pancake, Univ. of Kansas Tertiary Oil Recovery Project; Bob Sydansk, Petroleum Recovery ResearchCenter at New Mexico Tech.
Water Reduction Through Polymer Treatments
A joint project of Gulf Publishing(World Oil) and PTTC. See case studiesonline at www.pttc.org/case_studies/case_studies.htm
14Network News
NAPE 2003 RESULTS
Record-breaking 8,700 attendees800 exhibit booths with more than 220reservations for 2004 by show's end
APPEX 2003AAPG Prospect and Property Expo
September 9-11, 2003Houston, TX
www.aapg.org/meetings/appex/index.html
Prospects—Alive and Well in U.S.
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. Please note that some topics, dates, and locations listed are subject to change.
April 20034/3 South Midcontinent: Joint Operating Agreements (Marginal Well Commission) - Enid, OK. Contact: 405-604-04604/10 South Midcontinent: Joint Operating Agreements (Marginal Well Commission) - Oklahoma City, OK.
Contact: 405-604-04604/11 Texas: Structure and Stratigraphy of South Texas and Northeast Mexico, Applications to Exploration (South Texas
Geological Society, Gulf Coast SEMP) - San Antonio, TX. Contact: 512-471-03204/15 Texas: Well Cuttings - Houston, TX. Contact: 512-471-03204/15 Rocky Mountain: Unitization for Secondary Recovery Operations (Independent Petroleum Association of Mountain
States, Gas Technology Institute), preconference workshop - Denver, CO. Contact: 303-273-31074/16-17 Rocky Mountain: Rocky Mountain Energy Technology Conference (Independent Petroleum Association of Mountain
States, Gas Technology Institute) - Denver, CO. Contact: 303-623-09874/17 South Midcontinent: Joint Operating Agreements (Marginal Well Commission) - Tulsa, OK. Contact: 405-604-04604/17 West Coast: Operating Cost Reduction, A Roundtable Discussion - Los Angeles, CA. Contact: 213-740-80764/18 Rocky Mountain: Crash Course in Log Analysis (Independent Petroleum Association of Mountain States, Gas
Technology Institute-following Energy Technology Conference) - Denver, CO. Contact: 303-273-31074/22 Appalachian: Well Safety - Prestonburg, KY. Contact: 304-293-2867 ext 54154/22-23 Appalachian: Applied Reservoir Characterization for the Independent Operator - Washington, PA.
Contact: 304-293-2867 ext 54154/23 Central Gulf/Texas: Hydraulic Fracturing - Shreveport, LA. Contact: 225-578-18044/24 South Midcontinent: Joint Operating Agreements (Marginal Well Commission) - Ada, OK. Contact: 405-604-04604/24 Appalachian: Well Safety - Buckhannon, WV. Contact: 304-293-2867 ext 5415
May 20035/5-9 Eastern Gulf: International Coalbed Methane Symposium (other sponsors) - Tuscaloosa, AL. Contact: Ed Martin,
phone 205-348-7192 or Email [email protected]/7 Eastern Gulf: Paraffin/Asphaltene Control - Jackson, MS. Contact: 205-348-43195/8 South Midcontinent: Trade Fair (Marginal Well Commission) - Oklahoma City, OK. Contact: 405-604-04605/10 Rocky Mountain: Desktop Applications—Excel, Access, Database Fundamentals (AAPG annual meeting) - Salt Lake
City, UT. www.aapg.org5/11 Rocky Mountain: Complex Well Technology for Earth Scientists and Engineers (AAPG annual meeting) - Salt Lake
City, UT. www.aapg.org5/11 Rocky Mountain: Desktop Applications-PowerPoint and Effective Graphics (AAPG annual meeting) - Salt Lake City,
UT. www.aapg.org 5/11 Rocky Mountain: Subsurface Fluid Pressures and Their Relation to Oil and Gas Generation, Migration and
Accumulation (AAPG annual meeting - Salt Lake City, UT. www.aapg.org5/19-23 Southwest (workshop & field trip): Mesa Verde - Albuquerque, NM. Contact: 505-835-56855/22 Central Gulf: South Louisiana Petroleum Exploration Symposium (New Orleans Geological Society) - New Orleans,
LA. Contact: 225-578-18045/22 West Coast: Independents Day @ SPE/AAPG Western Regional Meeting - Long Beach, CA. Contact: 213-740-80765/29 Texas: New Methods for Locating and Recovering Remaining Hydrocarbons in the Permian Basin (UT Bureau of
Economic Geology, Center for Energy and Economic Diversification) - Midland, TX. Contact: 512-471-0320
June 20036/10 Rocky Mountain: Coalbed Methane Symposium (Rocky Mountain Association of Geologists) - Denver, CO. Contact:
303-273-31076/11-14 Rocky Mountain (field course): Coal Stratigraphy (Rocky Mountain Association of Geologists) - Rock Springs, WY.
Contact: 303-273-31076/19-20 South Midcontinent: Interpreting Reservoir Architecture Scale Frequency Phenomena (Oklahoma Geological Survey)
- Oklahoma City, OK. Contact: 405-325-30316/22-27 Rocky Mountain: Futures in Energy (student internship program) - Golden, CO. Contact: 303-273-31076/22-27 West Coast: COMET 2003 (student internship program) - Los Angeles, CA. Contact: 213-740-8076
Position Name Affiliation City/StateChairman James Bruning Bruning Resources, LLC Fort Smith, ARVice Chairman Brook Phifer NiCo Resources Inc. Littleton, COImmed. Past Chairman Clark Southmayd, Jr. Oneok Resources Co. Tulsa, OK
Appalachian Bernie Miller Bretagne Corp. Lexington, KYCentral Gulf Joe Jacobs Gas Masters of America, Inc. Monroe, LAEastern Gulf Brian Sims Independent Madison, MSMidwest Craig Howard Howard Energy Mount Carmel, ILNorth Midcontinent Mark A. Shreve Mull Drilling Co., Inc. Wichita, KSRocky Mountain Robert McDougall Phoenix Production Co. Cody, WYSouth Midcontinent A. M. “Mac” Alloway Tony Oil Company Tulsa, OKSouthwest David Boneau Yates Petroleum Corp. Artesia, NMTexas Gene Ames III Ames Energy Corp. San Antonio, TXWest Coast Mark Kapelke Tidelands Production Co. Long Beach, CAIPAA Steve Layton E&B Natural Resources Spring, TXAAPG Chuck Noll Copano Energy Houston, TXSEG Glenn Breed UpstreamInfo Houston, TXSPE Michael Gatens III MGV Energy Inc. Calgary, AlbertaGTI Kent Perry Gas Technology Institute Chicago, ILIOGCC John King Michigan Public Service Comm. Lansing, MIMajor Companies Greg Reep ChevronTexaco San Francisco, CAService Companies Jay Haskell Schlumberger Oilfield Services Houston, TXRegional Lead Orgs. David Morse Illinois Geological Survey Champaign, ILPTTC Exec. Director Don Duttlinger Petrol. Tech. Transfer Council Houston, TX
PTTC’s National Board of DirectorsGuided by Independents for Independents
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PTTC Network News Staff:
E. Lance Cole Technical Editor
Kristi Lovendahl Editor
PTTC Headquarters Staff:
Don Duttlinger Executive Director
E. Lance Cole Project Manager
Kathryn Chapman Director of BusinessAffairs
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