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Director: Dr. Doug Patchen
Appalachian Oil & Natural Gas Research Consortium, W. Virginia Univ.
Phone (304) 293-2867, ext. 5443, fax: 293-7822
E-Mail:
dpatch@wvunrcc.nrcc.wvu.edu
The resource center is located at the National Research
Center for Coal and Energy. Data includes the Atlas of Major Appalachian Gas
Plays, DOE, and Gas Research Institute research programs.
The March 27, 1996 workshop in Morgantown, W. Va., familiarized operators
with the various electronic databases and methods of obtaining oil and gas data
for the Appalachian Basin.
TECHNOLOGY SUMMARY
The Appalachian Basin crosses many states and regions. Locally, state surveys
and permitting organizations have been organizing databases. Until now, all
the local data have had to be stored and retrieved locally physically pulled
and copied. Slowly the data have been transcribed into electronic formats. The
different sets of data can be mailed (different formats for different media)
or retrieved by calling an electronic bulletin board often a toll call. Again,
this process assumes that the operators know what data they want and where it
is stored.
Now that the world has discovered the Internet, the connections allow
people to enter one computer, communicate, and receive data from other
computers. Knowledge once in a file cabinet now sees the "electronic
light of day" and can be viewed by many people, no matter what computer
they use. A computer-modem connection opens up a wide world of data and
information.
WORKSHOP DESCRIPTION
The workshop consisted of a series of presentations detailing the database
resources that are available and how to access the databases either by request
or by the Internet.
PROBLEM ADDRESSED
The operators in this geographically dispersed basin do not have immediate
access to regional or local data. Often they do not even know that the data
exist. In this workshop, the operators have been made aware of the breadth of
the data available, as well as where to access it, and how to retrieve the
data.
OVERVIEW OF TECHNOLOGY
The technology in this workshop is the transfer of a skill (accessing the
Internet) and the knowledge that there is content or data out there on another
computer that can be retrieved and used.
The workshop was divided into three parts - how to use the Internet, what
electronically formatted data are presently available on and off the Internet,
and what projects are underway that have the potential to help in the future.
Once connected to the Internet, this tool can be used to send and receive
electronic mail, to read discussions, to run programs on remote computers, and
to transfer data and program files. Many of these functions are incorporated
in today's World Wide Web browsers which facilitate the transfer of
information while hiding the nuts and bolts of the activity from the users.
However, one can become lost in the huge sea of information that is
available on the Internet. The workshop provided some recommended sites from
which the user can start looking for data. There are also search engines which
can be used to find data.
Not all of the data useful to the operators are presently available on the
Internet. Some of the data must be requested, but it can now be delivered in
most of the common electronic formats. Various organizations in Kentucky,
Ohio, Pennsylvania, and West Virginia maintain this data, as well as some
cooperative alliances.
The data can include fields such as well locations, completion logs,
geophysical logs, sample descriptions, base maps, production reports, well
permits, geologic tops, or ownership. There is a cost associated with some of
the datasets, and others are still not available.
There are also projects underway which include data and models such as GSAM
and GASIS. The Atlas of Major Appalachian Gas Plays has geologic descriptions
of 3D major natural gas plays which range stratigraphically from Pennsylvanian
to Cambrian reservoirs. Also, the atlas geographically covers the entire
Appalachian basin.
The data elements for each play are organized into Basic Reservoir Data,
Reservoir Parameters, Fluid and Gas Properties, and Volumetric Data. A
companion product developed during this DOE-funded project is a database
containing geologic, engineering and production data on more than 4,000 fields
and reservoirs in the basin.
The Appalachia PTTC maintains a list of the available databases and files
which can be obtained by the operators.
SPEAKERS
Roman Olynyk
WV Network for Educational Telecomputing - Morgantown, WV
John Benton
PTTC - Denver, CO
Brandon Nuttall
Kentucky Geological Survey - Lexington, KY
Larry Wickstrom
Ohio Geological Survey - Columbus, OH
Cheryl Cozart
Department of Conservation and Natural Resources - Pittsburgh, PA
Kathy Flaherty
Department of Conservation and Natural Resources - Pittsburgh, PA
Mary Behling
West Virginia Geological & Economic Survey - Morgantown, WV
Dave Matchen
West Virginia Geological & Economic Survey - Morgantown, WV
Doug Malcolm
Independent Oil & Gas Association of West Virginia - Charleston, WV
Bob Whitsett
Natural Gas & Oil Technology Partnership - Houston, TX
Tom Keech
U.S. Department of Energy/FETC - Morgantown, WV
Peter Springer
Energy and Environmental Analysis - Arlington, VA
Ron McDowell
WV Geological and Economic Survey - Morgantown, WV
Back To Contents
Director: Bob Baumann
LSU Center for Energy Studies
phone: (504) 388-1804, fax: 388-4541
e-mail: bob@maelstrom.enrg.lsu.edu
The resource center is located at the Center for Energy
Studies at Louisiana State University. Data include an environmental handbook
and information from the LSU petroleum engineering department and the LSU
Basin Research Institute.
The Sept. 28, 1995, workshop in Baton Rouge, La., was designed to assist
operators with produced water disposal, its problems, relevant regulations, and
existing and emerging technologies that can assist operators.
TECHNOLOGY SUMMARY
The volume of produced water in the Central Gulf Region is significant. In
1993, for example, six barrels of water were produced for every barrel of oil
in Louisiana.
At the time of the workshop, 62 percent of the 1.2 billion barrels of water
were reinjected.
Regulations for injection wells are becoming more stringent to protect
underground water sources. Technologies exist that can improve the cleaning of
the produced water and improve some of the difficulties experienced with
downhole disposal of produced water.
WORKSHOP DESCRIPTION
The workshop consisted of presentations by regulators, experts in water
treatment, and included field examples of water treatments using new
technologies.
PROBLEM ADDRESSED
The workshop focused on three kinds of information needs. Firstly, why is
produced water considered to be harmful to the environment and which
technologies can clean produced water so it can be reintroduced into the
environment? Secondly, what are the new or pending changes in state and
federal regulations for disposal? And finally, what new technologies are
emerging that will clean the water effectively while remaining cost-effective,
or improving the cost-effectiveness of treatment and disposal?
New regulations for zero surface water discharge went into effect on Jan.
1, 1997, essentially requiring all produced water within the state to be
reinjected downhole. A handful of operations were given extensions by means of
an Emergency Order by the head of the state Department of Environmental
Quality (DEQ) and these are being dealt with on a case-by-case basis. However,
the emergency order was adamant in regards to any further extensions. The
longest possible extension is Jan. 1, 1999, and this case would only be for
the most imposing reasons.
OVERVIEW OF METHODS FOR CLEANING AND DISPOSAL
What is produced water? Produced water is any water that comes up to the
surface and includes connate water, water that has been previously injected,
and water left over from previous well or reservoir treatments. The volumes
can be quite large produced water volume is often far greater than oil or gas
production. The volume of water produced depends upon the type of reservoir
and the source of reservoir energy. The volume changes with time usually
increasing.
The composition of the produced water also depends upon the source of the
water. Sources include the flow from beneath the hydrocarbon zone, flow from
within the hydrocarbon zone, and injected fluids. The water can contain
organic materials (oil, non-hydrocarbon organics, and dissolved organics),
salts and heavy metals, inorganic solids (clays, silicas, and scale),
radionuclides, dissolved gas, chemical treating residual, and biological
matter (bacteria).
Untreated produced water impacts the environment through a variety of
effects. Physically, an oily water can smother surfaces. Chemically, the water
can contaminate ground water and remove oxygen from soils and sediments.
Biologically, the produced water may be toxic to animals or it may exhibit
biomagnification where the contaminants are moved up the food chain and
concentrated at each step.
In the past, produced water has been treated minimally to be used as
waterflood injection water, or a source for demineralization, irrigation, or
for livestock. Water really only had to be clean enough to inject and not
impair the waterflood injectivity.
The current processes that treat produced water remove the chemicals and
solids. Two major lines of attack use the specific gravity difference between
water and contaminants or the inability of solids to transit permeable media.
The first approach is used in settling tanks, skimmers and centrifuges to
separate and isolate the water in continuous processes. In the second,
changeable filters are used to trap contaminants. Operators should follow a
four-step plan to solve their current water treatment problems.
- Perform multiple point on-site sampling to characterize waste water
- Perform lab treatment studies and screening of treatment techniques
- Perform an on-site pilot plant treatment test
- Perform a data evaluation to optimize the treatment equipment
specification, design and manufacture
- Work with regulators to both educate them and learn about new
technologies and research which may affect current or pending regulations
that are based on older technology or insufficient research?
Future (and on-going) technologies include seating nipple bypass techniques
and in situ segregation of produced water and oil, as well as surface cleaning
of the produced water.
SPEAKERS
Dale Givens
La. Dept. of Natural Resources - Baton Rouge, LA
Jim Welsh
Lousiana Dept. of Natural Resources - Baton Rouge, LA
Clay Kimbrell
LSU Dept. of Petroleum Engineering - Baton Rouge, LA
Dan Caudle
Sound Environmental Solutions, Inc. - Denver, CO
Brent Smith
U.S. Department of Energy - Bartlesville, OK
Alonzo (Lonnie) Lawrence
Remediation Technologies, Inc. - Pittsburgh, PA
Uncas Favret
Engineering Specialties, Inc. - Covington, LA
Allen Grubb
OXY USA - Houston, TX
M.D. Swisher
Hunt Petroleum Corp. - Dallas, TX
Back To Contents
Director: Dr. Ernest Mancini
University of Alabama
phone: (205) 348-4319, fax: 348-0818
e-mail: emancini@petro.gsa.tuscaloosa.al.us
Resource center Scientific Collections Facility, University
of Alabama. Includes a satellite resource center in Jackson, Miss., well-log,
core, and publications libraries, and computer telecommunications.
The Aug. 13, 1996 workshop in Jackson, MS, offered a regional examination of
technical procedures being used -- and lessons learned -- in selected active
waterflood projects.
TECHNOLOGY SUMMARY
A new brine disposal process is available that converts the brine stream of an
oil or gas well into potable water for agricultural use, combustion products
and water vapor that can be released into the atmosphere, and dry solids.
The process has the potential to be modified to allow the produced water to
be used for waterflooding and pressure maintenance. The disposal process uses
a reverse osmosis unit, a submerged combustion evaporator, and a pulse
combustion dryer.
WORKSHOP DESCRIPTION
The workshop focused on active waterflood projects in the region and how the
technologies used by operators could be transferred to others. Presentations
were made on new treatments of produced water brines from oil and gas wells by
means of reverse osmosis and submerged combustion evaporation. Specifically
discussed were the Lake Como Field Project and the Citronelle Field Reservoir
Management Demonstration Project.
PROBLEM ADDRESSED
The technology workshop reviewed waterflood and pressure maintenance projects
in Alabama and Mississippi. This area has been producing hydrocarbons since
1926. The region is a mature oil and gas province with more than 2,200
established fields. Many of these fields are in advanced secondary and
tertiary recovery. With the maturity of the waterfloods, data are available to
help operators leverage their operations by learning from the successes of the
older projects. One specific technology and two case studies were discussed.
Pretreatment of the brine feedstream is necessary to prevent fouling of the
reverse osmosis membranes. Precipitate carbonates of Barium, Calcium,
Magnesium and Strontium are generated. For example, a primary feed stream of
6,290 barrels of brine (7,000 parts per million (ppm) total dissolved solids)
per day can be converted into 4,718 barrels with 400 ppm total dissolved
solids, and 158 barrels per day of heavy brine with 268,000 ppm total
dissolved solids. The concentrated brine is then dried to a solid salt.
The technology dealt with the treatment of produced brines (applicable both
to disposal and water quality requirements for waterflooding). The first case
study was the ongoing waterflood at Lake Como Field. The second case study was
the reservoir management demonstration at the Citronelle Field.
CASE STUDIES
The Lake Como Field was discovered in 1972 and unitized in 1975. The
production drive mechanism is fluid expansion and solution gas. Secondary
recovery (waterflood) was initiated in 1976 and expanded in 1986. The
producing horizon is the Jurassic Smackover Formation, and the petroleum trap
is an elongated fault which resulted from salt movement.
A nearly flat rate of water injection has been responsible for a very flat
oil production rate of 20,000 to 30,000 barrels per month through 1989. This
waterflood is in a deep reservoir 7,000 feet, with moderate porosity (11.9
percent) and permeability of 1 millidarcy. Primary and secondary production
has accounted for 41.6 percent of the original oil in place. Fresh water is
the most effective source for water injection and flood.
The Citronelle Field was discovered in 1955. Oil was originally tested from
the lower Cretaceous Donovan sandstone at 11,000 feet. About 800 feet of gross
pay was found in two major, but separate, oil-bearing zones. The productive
zones are separated by 300 feet of saltwater saturated sandstone.
The field has been delineated by over 450 wells and is composed of a series
of stacked sandstone lenses that are irregular in distribution and thickness.
In 1961, 139 tracts were unitized and a waterflood was initiated. After the
waterflood, production increased from 6,000 to 11,000 barrels of oil per day.
The success brought more tracts into the unit and by 1965 the unit was
producing 17,600 barrels of oil per day. Three other units were formed, even
though they produce from the same reservoir. Some parts of the reservoir are
compartmentalized and unaffected by the current waterflood.
The field is a demonstration project that shows what production
achievements are available from an integrated approach. The reservoir
management process is cyclic and consists primarily of the formulation,
implementation, and monitoring of a reservoir management plan designed to
maximize the profitability of a reservoir.
Success in developing an appropriate reservoir management plan requires
knowledge of the reservoir system. A team approach using geoscientists,
engineers, managers and other professionals can solve the on-going problems.
SPEAKERS
Dr. Harry Brandt
University of California - Davis, CA
Mike Dean
Tellus Energy Group - Jackson, MS
R.H. Stechmann
Citronelle Unit - Citronelle, AL
Ed Blair
Citronelle Unit - Citronelle, AL
Dr. Mike Fowler
BDM-Oklahoma, Inc. - Bartlesville, OK
Mark Young
BDM-Oklahoma, Inc. - Bartlesville, OK
Back To Contents
Director: Dr. David Morse
Illinois State Geological Survey
phone: (217) 244-9337, fax: 244-2785
e-mail: morse@geoserv.isgs.uiuc.edu
Resource center Illinois State Geological Survey. Resources
include oil and gas databases on the Illinois Basin, Michigan, Indiana and
Western Kentucky that are being added to the regional website.
The March 16, 1996, workshop was held in Grayville, Ill. It reviewed the
fundamentals of horizontal drilling, discussed situations where horizontal
drilling was economic, and reinforced the major points using successful case
histories.
TECHNOLOGY SUMMARY
Reservoirs are by nature heterogeneous, and reservoir heterogeneity is an
important factor affecting production performance.
That reservoirs exhibit heterogeneity is known, but difficult to quantify.
In some cases, horizontal wells can be used to cross permeability and porosity
barriers or intersect fractures and produce reserves that otherwise would have
been bypassed.
WORKSHOP DESCRIPTION
The one-day workshop included presentations from experts, plus four local
operators having horizontal drilling experience.
PROBLEM ADDRESSED
The workshop focused on key aspects of horizontal drilling, a technology new
to the Illinois Basin. The talks demonstrated that, in some situations, the
technology could be more economic than drilling vertical wells. The workshop
provided local information and demonstrated success stories from within the
basin.
Many reservoirs have been treated as continuous pools of oil that can be
drained by a regular pattern of vertical wells. Research now indicates that,
in many cases, there are separate accumulations or compartments within the
same reservoir. Knowing this, it becomes important to be able to measure and
quantify heterogeneity.
There are several methods that can be used to measure heterogeneity -- from
point-source data to volume-source data. Sources include well logs, cores, and
production data. The former data indicate depositional heterogeneity, while
the latter data indicate operational heterogeneity.
OVERVIEW OF HORIZONTAL DRILLING
Horizontal wells can be used to overcome these heterogeneities to produce a
reservoir economically or efficiently. Horizontal wells have been applied in
heavy oil reservoirs, fractured reservoirs with storage, and in reservoirs
that are inaccessible by vertical wells. The technology also has been applied
to reservoirs with vertical permeability barriers, to connect productive
intervals, and to increase the cross-sectional area to flow without hydraulic
stimulation.
Conditions leading to a successful horizontal well include:
- Adequate pre-spud planning
- Reservoir heterogeneity
- Drillable lithologies that will not collapse
- Field storage in matrix and/or fracture porosity
- Deliverability through adequate matrix or fracture permeability
- Careful cost control
This means that the geology and the engineering must be integrated.
Horizontal wells can be classified according to turn radius:
| Radius |
Build Rate |
| Long |
4 degrees/100 ft |
| Medium |
20 degrees/ 100 ft. |
| Short |
150 degrees/ 100 ft. |
| Ultrashort |
90 degrees / 1 ft. |
In addition, horizontal wells can have more than one horizontal run. Each
well type has special applications, tools, drilling methods, logging methods,
and completion styles. The fundamentals of drilling horizontal wells include:
underbalanced drilling, coiled tubing, bit steering, continuous logging or
measurement-while-drilling, multilateral horizontals, and horizontal
completions.
CASE STUDIES
SPEAKERS
Ross Clark
Search Energy and AAPG Distinguished Lecturer - Calgary, Alberta, Canada
Jim Blumenthal
Consulting Geologist - Olney, IL
Kevin Reimer
Consulting Geologist - Harrisburg, IL
Dr. William B. Harrison
Western Michigan University - Kalamazoo, MI
Rick Wadel
Petro Union Company - Evansville, IL
Back To Contents
Director: Dr. David Morse
Illinois State Geological Survey
phone: (217) 244-9337, fax: 244-2785
e-mail: morse@geoserv.isgs.uiuc.edu
Resource center Illinois State Geological Survey. Resources
include oil and gas databases on the Illinois Basin, Michigan, Indiana and
Western Kentucky that are being added to the regional website.
The Dec. 12, 1996, workshop in Mt. Pleasant, Mich., was held to familiarize
operators with CO2 flooding its applications, mechanisms,
and recent project results
TECHNOLOGY SUMMARY
Injecting CO2 (carbon dioxide) into the reservoir
swells the oil, reduces oil viscosity, and reduces the gas-oil interfacial
tension.
CO2 flooding vaporizes lighter hydrocarbons in oil
and generates miscibility by multiple contact processes if the pressure is
high enough.
Put simply, CO2 flooding can make it possible to
produce more oil.
Carbon dioxide is more soluble in oil than in water, so it can be used
after or during a waterflood to great effect. CO2 can
be used (depending upon the depth and pressure) as both a miscible or an
immiscible flooding agent.
This flooding approach can be continuous pushing a bank of expanded oil
through a reservoir, or "huff and puff" where the CO2 is injected, swells the oil (which is produced), and the gas is
injected to start the cycle again.
WORKSHOP DESCRIPTION
The Midwest Region workshop consisted of presentations on field case studies
of successful CO2 floods in US reservoirs.
PROBLEM ADDRESSED
After primary production, typically more than two-thirds of the mobile
hydrocarbon is left in the pore spaces of the reservoir. Even the application
of secondary recovery via waterflooding brings the recovery to a maximum of
50%. This workshop showed the applicability of using CO2 flooding
to enhance the recovery of mobile hydrocarbons beyond secondary recovery.
OVERVIEW OF TECHNOLOGY
Primary production leaves the majority of the mobile oil in place. Although
waterflood advanced secondary recovery can add to production, CO2 flooding, when applicable, can improve recovery of residual oil from
the reservoir. CO2 miscible floods are effective if the
reservoir contains light (25 degree to 50 degree API) oil, the injected CO2 contacts the oil, and CO2
is available at low
cost.
The process also works best at depths greater than 3,000 feet. CO2 flood works in carbonates or sandstones, in various permeabilities (2
millidarcies to 4500 millidarcies in field projects) assuming good injectivity.
CO2 improves oil recovery by swelling the crude oil,
reducing the oil viscosity, reducing the gas-oil interfacial tension,
vaporizing and extracting the lighter hydrocarbons in crude oil and generating
miscibility by the multiple contact process if the pressure is high enough.
Each effect increases with rising pressure as CO2 dissolves
in crude oil.
Any CO2 flooding requires planning reservoir
characterization, and feasibility studies followed by pilot projects before
committing to full field CO2 floods. There are several
public domain and commercial screening programs available as well as
commercial simulators to aid in this process. The modeling of a field is
essential for making informed decisions that encompass all options, reduce
risk and maximize profitability.
CO2 can be used in different types of floods:
- Continuous CO2 injection
- Water alternating Gas (WAG)
- Hybrid WAG
- Stage floods
- Re-injection of produced gas
- Huff and Puff
Examples were presented that demonstrated the performance of CO2 flooding. The productivity response due to the CO2
injection
was shown, as well as the effect that CO2 costs and
reservoir characteristics have had on overall project costs.
CO2 flooding is not without risks. Corrosion and
plugging have been seen, but can be corrected and planned for. Poor
injectivity remains at present a major problem.
New developments in CO2 flooding include CO2 foams, CO2 floods from horizontal wells, and CO2
floods in fractured reservoirs.
SPEAKERS
Joe Taber
Petroleum Recovery Research Center - Socorro, NM
Reid B. Grigg
Petroleum Recovery Research Center - Socorro, NM
David S. Schecter
Petroleum Recovery Research Center - Socorro, NM
Back To Contents
Director: Dr. Lanny Schoeling
Kansas University Energy Research Center
phone: (913) 864-7398, fax: 864-7399
e-mail: lanny@cpe.engr.ukans.edu
Resource center KU Energy Research Center. Information
includes downloadable DOE/SPE software and data from the Kansas Geological
Survey with digital maps fields, and producing horizons.
The Nov. 29-30, 1995, workshop, in Wichita, Kan., sought to familiarize oil
and gas operators with the latest reservoir management techniques having the
potential to maximize the production and profitability of marginal oil fields.
TECHNOLOGY SUMMARY
The workshop stressed current technologies such as reservoir simulation,
transient testing, mapping and echometer technologies.
By combining engineering and geophysical skills with experience in the
field, a reservoir's production is maximized and problems and costs minimized.
WORKSHOP DESCRIPTION
The two-day workshop included descriptions of the steps necessary to evaluate
a marginal property, decide its future merit, and determine how to better
manage the property.
PROBLEM ADDRESSED
What specific steps are necessary to improve the status of a marginal field?
Workshop speakers noted that marginal fields have poor economic return because
of high operating costs and low production rates. This combination often
occurs because of the lack of a true reservoir management effort.
Increasingly, the closer integration of the operator, the engineer and the
geoscientist with their respective skills and data analyses can make the
difference between a poor field and a profitable field.
OVERVIEW OF RESERVOIR MANAGEMENT APPROACH
There must be a comprehensive, integrated approach to reservoir exploitation.
Available resources should be evaluated, including finances, staff, equipment,
and technology. To be successful, the operator first must acquire the
necessary data, evaluate alternatives, develop a strategy, implement it,
monitor the performance, and be prepared to make changes to optimize the
performance.
An inter-disciplinary team approach is essential to success. Workshop
speakers outlined the steps involved in conducting an integrated reservoir
management effort. Major steps include: (1) conducting and integrating
geological and engineering analyses, (2) gathering new well test data through
field testing, (3) examining operations practices for cost reduction
potential, and (4) implementing the revised reservoir development plan.
Activities included within integrating geological and engineering analyses
include: (1) organizing the data, (2) mapping important parameters, (3)
evaluating fluid injection and production monitoring data, (4) using screening
models to determine the optimum recovery process, and (5) considering
waterflood dynamics.
Gathering new well test data can provide insight on current operations of
wells, fluid movement within the reservoir, and reservoir properties.
Operations practices should be examined for cost-saving opportunities
through pumping unit optimization, electrical optimization, and wellbore
clean-up.
Finally, the process has little value unless the identified field
development options are actually implemented--reperforating and contacting oil
behind-pipe, performing permeability modification treatments as needed, and
implementing the improved recovery process. Often, the improved recovery
process involves more effective waterflooding and infill drilling, preferably
targeted to locations where unswept oil remains.
SPEAKERS
Dr. Lanny G. Schoeling
Director, University of Kansas Tertiary Oil Recovery Project - Lawrence, KS
Rodney Reynolds
University of Kansas, Tertiary Oil Recovery Project - Lawrence, KS
Back To Contents
Director: Dr. Roger Slatt
Colorado School of Mines
phone: (303) 273-3822, fax: 273-3859
e-mail: rslatt@mines.edu
Resource center Colorado School of Mines facilities.
Resources include data and downloadable files from industry organizations and
state agencies; Colorado Oil and Gas Commission's list of abandoned
properties.
TECHNOLOGY SUMMARY
PTTC Internet training workshops were pioneered in the North Midcontinent
Region. Early experience confirmed that hands-on experience was essential, as
were incorporating example exercises with regional significance.
PTTC's Rocky Mountain Region took the initial training concepts, and with
the help of the North Midcontinent regional staff, polished them through their
experience in holding several workshops throughout the Rocky Mountain area.
They consolidated the experience in a copyrighted manual, "The Internet
Guide for Petroleum Professionals."
The Rocky Mountain Region has also conducted the workshop as an AAPG short
course, most recently at the April 1997 AAPG Annual Meeting in Dallas, Texas.
Similar Internet training workshops have been conducted by PTTC's Central Gulf
and West Coast regions. The material, and approach used, have been proven
effective, as confirmed by participant feedback following the workshop.
The workshop has been presented with regionally specific information in the
North Midcontinent, Rocky Mountain, Central Gulf and West Coast PTTC regions
in 1995-1996. The purpose of this popular workshop was to introduce oil and
gas operators to the Internet. A series of regional workshops provided
operators with the knowledge they needed to access the Internet and acquaint
themselves with the increasingly comprehensive oil and gas resources
available.
WORKSHOP DESCRIPTION
This one-day workshop provides background material on the history and
development of the World Wide Web (Internet), explains the equipment and steps
necessary to gain Internet access, and shows operators how to download
information from the Internet.
As the workshop incorporates hands-on exercises, it must be conducted at a
computer laboratory with appropriate equipment and Internet access. The
hands-on exercises, which can be tailored for regional audiences, have proven
essential for participants to develop the personal confidence in their
individual ability to access and use the Internet for business purposes.
PROBLEM ADDRESSED
Technology continues to change at an ever-increasing pace, and operators' time
for finding new information, or the oil and gas data they need, becomes ever
more scarce. Data and information providers are increasingly making
information and data available electronically via the Internet, an ideal
solution as the information can be provided at the point of need--the desktop.
However, experience proves that, especially among smaller producers who do
not have access to corporate computing resources, those considering using the
Internet need guided learning to increase their confidence level. This
workshop provides that guided learning experience.
OVERVIEW OF INTERNET TECHNOLOGY
The workshop starts at ground zero, presuming participants have little
knowledge of the Internet. The material then leads participants through a
structured process culminating in using the Internet as a resource for
petroleum information. Six major topics are covered in the workshop. These
topics are:
Section 1: History and Overview of the Web--what the Internet is?
Section 2: Web Browser how to browse, locate, and screen information
Section 3: How to become part of the Internet?--Required computer
capabilities, modem, Internet Service Providers, etc.
Section 4: How do I find useful sites on the Internet?--search engines, search
techniques
Section 5: How to acquire (download) and use information once found
Section 6: Petroleum resources--links, an annotated list of particularly
useful petroleum industry websites, bookmark concepts
GETTING A COPY OF THE MANUAL
The Rocky Mountain Region has copyrighted their version of "The Internet
Guide for the Petroleum Professional." Printed versions may be ordered
for $25 by contacting the region.
Make check payable to: Colorado School of Mines Send payment to:
Ms. Vickey Sare
c/o Colorado School of Mines
PTTC/Department of Geology and Geological Engineering
Campus Box 22
Golden, Colorado 80401-1887
The electronic version of the manual may be downloaded from the PTTC
website (http://www.worldenergy.com/PTTC). If downloaded from the website
(much as shareware is done), individuals are requested to consider donations
of $15 to the PTTC Rocky Mountain Region (mail payment as indicated above).
Incidentally, the on-line version has been found to be very helpful in
conducting Internet workshops.
SPEAKERS
Dr. Roger Slatt
Colorado School of Mines, Golden, CO
Ms. Vickey Sare
Colorado School of Mines, Golden, CO
Dr. Sandra Mark
Colorado School of Mines, Golden, CO
Back To Contents
Director: Dr. Charles Mankin
Oklahoma Geological Survey
phone: (405) 325-3031, fax: 325-7069
e-mail: cjmankin@ou.edu
Resource center State Geological Survey and University
of Oklahoma includes extensive collection of the Youngblood Geoscience Library
lease records, production histories, cores, and "fax-on-demand."
The reservoirs produced by the sedimentary processes in fluvial dominated
deltaic environments are highly compartmentalized leading to large quantities of
by-passed oil in these fields.
Demonstrating this principle to operators is the first step in developing
procedures for improved recovery from existing fields.
Depending upon the particular conditions, additional recovery may be achieved
through targeted in-fill drilling, directional drilling, recompletion, and/or
profile modification.
A series of six workshops held since 1995 in various Oklahoma cities, have
presented data and analyses on eight petroleum plays in Oklahoma. Two additional
plays (Tonkawa and Bartlesville) will be presented in 1997.
This is part of a program to present the results of studies on 10 petroleum
plays that have the common characteristics of having been developed in rock
units that were deposited in fluvial dominated deltaic (FDD) environments during
the Pennsylvanian period of geologic time. The 10 plays included in this series
provide about 15 percent of the crude oil production in the state of Oklahoma.
WORKSHOP DESCRIPTION
The one-day workshops are presented by the lead geologist for each geological
play with contributions from other staff who developed material on selected
fields in the play. One or more reservoir characterization and simulation
studies are presented by a petroleum engineer using public-domain software for
the simulation.
The typical workshop includes an introduction to the sedimentary processes
that produce the FDD reservoirs followed by a presentation of the regional
setting for the particular play. Participants are provided with a publication
containing a description of the sedimentary processes that produce FDD rock
units, a regional description of the geology of the play, descriptions of
selected reservoirs in the play, and the simulation study of one or more
reservoirs. Included with the text are maps, cross sections, tables of data,
and an extensive bibliography.
PROBLEM ADDRESSED
Fluvial dominated deltaic petroleum reservoirs are major contributors to
Oklahoma's crude oil and natural gas production. However, because of
particular properties of these reservoirs, the average recovery factor is only
15 percent for all reservoirs studied to date in this program.
After primary production, typically more than two-thirds of the mobile
hydrocarbon is left in the pore spaces of the reservoir. Even the application
of secondary recovery via waterflooding brings the recovery to a maximum of 50
percent. This workshop showed the applicability of using CO2 flooding
to enhance the recovery of mobile hydrocarbons beyond secondary recovery.
WORKSHOPS TO DATE
The South Midcontinent Region of PTTC co-sponsors these workshops with the
Oklahoma Geological Survey. The Survey is developing the workshops as part of
its DOE Class 1 Project on Oklahoma FDD reservoirs.
The Tonkawa and Bartlesville play workshops are scheduled for July and
October, 1997, respectively. The reservoir play presentations are the most
popular and successful workshops conducted by the Oklahoma Geological Survey,
with co-sponsoring by PTTC. Operators have insisted that the program be
continued following the completion of the current schedule and include other
geological plays in the region.
PUBLICATIONS
Publications for the play analyses may be ordered from the Oklahoma Geological
Survey
(cost = $6/report plus $1.20 postage).
Contact: OGS Publication Sales (405) 360-2886.
Report numbers are:
| Report Title |
No. of Workshops |
Report No. |
| Morrow Play |
2 |
SP95-1 |
| Booch Play |
1 |
SP95-3 |
| Layton and Osage-Layton Play |
1 |
SP96-1 |
| Prue and Skinner Plays |
2 |
SP96-2 |
| Cleveland and Peru Plays |
1 |
SPXX-X |
| Red Fork Play |
2 |
SP97-1 |
SPEAKERS
Dr. Richard Andrews
Geo Information Systems - Norman, OK
Dr. Jock Campbell
Oklahoma Geological Survey - Norman, OK
Robert Northcutt
Consultant - Oklahoma City, OK
Kurt Rottmann
Consultant - Oklahoma City, OK
Dr. Roy Knapp
School of Petroleum & Geological Engineering - Norman, OK
Back To Contents
Director: Robert Blaylock
Petroleum Recovery Research Center
phone: (505) 835-5938, fax: 835-6031
e-mail: reb@baervan.nmt.edu
Resource center New Mexico Institute of Mining and
Technology. Producers can access Internet data technology through the region's
"GO-TECH" system. Information also maintained at the Roswell Energy
Library.
The March 21, 1996, workshop in Farmington, N.M., was designed to review in
detail current techniques, technologies and real-time analysis of hydraulic
fracturing of reservoirs.
TECHNOLOGY SUMMARY
The act of drilling can damage the near-wellbore rock and impede the flow of
hydrocarbons to the well. Stimulations are designed to bypass the damaged
zone. Stimulations are also used to provide more and better flow pathways from
the reservoir to the wellbore.
Well stimulations once consisted simply of dropping explosives down a well
and hoping for the best. Today, however, rock studies, hydraulic research and
field testing have brought stimulation to the point where planning and
real-time analysis can improve the stimulation and productivity of the well.
WORKSHOP DESCRIPTION
The workshop consisted of presentations by experts in stimulation, research
personnel, and representatives from stimulation companies. These experts also
participated in panel discussions. The attendees were given the results of
PTTC regional problem identification workshops to encourage discussion of any
issues where they had experience and could offer solutions.
PROBLEM ADDRESSED
The San Juan basin with over 16,000 active wells has an investment of $1.6
billion in stimulation treatments. Since this investment is so large,
operators need to learn more about the planning and actual operation of
stimulation procedures.
OVERVIEW OF STIMULATION DESIGN AND MONITORING
Wells are stimulated to improve the flow to the wellbore. Hydraulic fracturing
pushes a wedge of material (fluid and proppant) into the formation forming a
conduit that enhances the flow of hydrocarbons.
Part of any stimulation project is making sure the fracture goes where it
is supposed to go. In the past, fractures were treated as two-dimensional
problems, but research and software now treat hydraulic stimulation as a
three-dimensional problem and solution.
Parameters that can be specified or potentially controlled are: fracture
fluid selection, optimum size of the job, injection rate, fracture length,
proppant placement, vertical containment, flow back timing and rate, and
monitoring/management of the fracture treatment. To be successful, the
reservoir rock must be adequately characterized.
Workshop presentations covered: software for designing stimulations, actual
stimulation cases, techniques of monitoring fracture parameters, and the
economic benefits of successful fracture treatments. The software described
included service company software, as well as software contributed to the PTTC
regional resource centers. Software is used to design the treatment based upon
the rock and fluid properties.
Further, there are techniques to measure the effectiveness (fracture height
and width) of hydraulic fractures. The workshop included the use of
radioactive tracers and multi-spectral gamma ray logging tools. These can be
used to evaluate the proppant near the wellbore, proppant settling, stage
distribution in multiple-stage treatments, and the placement of
multiple-strength proppant.
Real-time monitoring of pressures gives the operator an opportunity to
change or improve the fracture treatment while it is underway. Understanding
stress is critical in evaluating fracture geometry and fracture treatment
optimization. Operators can use low-cost methods to determine stress fields by
using data from offset wells or performing actual stress tests from the
wellbore.
Projects using optimal fracture emplacement have seen fewer operational
problems, reduced costs (an average of 20 percent to a maximum of 50 percent),
and increased productivity of up to 300 percent. The final arbiter of the
success of a stimulation treatment is in the production. Case studies were
reviewed on projects completed by the Gas Research Institute, as well as work
done by an alliance of Halliburton Energy Services and Meridian Oil Co.
Production data indicated that advanced stimulation technology can
dramatically improve individual well and field performance.
SPEAKERS
Dr. David Holcomb
Pro-Technics, Inc. - Houston, TX
Ken Collins
Dowell-Schlumberger - Farmington, NM
Mike Middlebrook
Integrated Petroleum Technologies - Denver, CO
Clay Terry
Halliburton Energy Services - Denver, CO
Brian Ault
Meridian Oil - Farmington, NM
Dr. Ray Johnson
BJ Services Co. - Midland, TX
Back To Contents
Director: Robert Blaylock
Petroleum Recovery Research Center
phone: (505) 835-5938, fax: 835-6031
e-mail: reb@baervan.nmt.edu
Resource center New Mexico Institute of Mining and
Technology. Producers can access Internet data technology through the region's
"GO-TECH" system. Information also maintained at the Roswell Energy
Library.
The Sept. 18-19, 1995, Roswell, N.M., workshop's goal was to familiarize oil
and natural gas operators with 3-D seismic technology the theory, acquisition,
interpretation and availability of 3-D seismic software and hardware.
TECHNOLOGY SUMMARY
The workshop summarized the potential economic benefits to independent oil and
gas companies of using 3-D seismic technology in lieu of 2-D seismic for
prospect delineation. A case history of a prospect in Oklahoma where the
companies used lower-cost 2-D seismic, and subsequently drilled two dry holes
was presented.
The study showed that the prospect was not completely evaluated. In
retrospect, the companies could have run a 3-D seismic survey, drilled one
well more properly located, and spent less money than they spent with the 2-D
seismic approach.
Since the advent of 3-D seismic technology, data show an increase in the
"significant discoveries per 100 new field wildcats." Results of
in-house studies by Exxon and Neomar presented at the workshop projected
wildcat success rates increasing 20.3 percent over previous 2-D seismic
exploration efforts.
WORKSHOP DESCRIPTION
The workshop consisted of presentations by experts in the field and included a
day of hands-on experience with 3-D seismic software and hardware.
PROBLEM ADDRESSED
The workshop addressed two problems that oil and gas companies encounter in
attempting to use 3-D seismic technology: 1) obtaining good 3-D seismic data
and 2) proper interpretation of that data, especially the incorporation of
geological and engineering data with the seismic interpretation. Therefore, by
design, the two main focal points of the workshops were data acquisition and
data interpretation.
OVERVIEW OF TECHNOLOGY
Workshop presentations included data acquisition and interpretation of data.
The first reviewed the basic concepts of wave propagation, reflection, and
imaging. There has been a significant evolution of seismic receivers and
seismic sources.
The theory and development of 3-D seismic principles, 3-D seismic survey
design, depth-to-time conversions, seismic signal attributes, thin-bed
responses, and quantitative geophysics were covered.
In addition, workshop speakers presented case histories of prospects
developed using 3-D seismic technology in a South Texas thin-bedded reservoir,
a karsted reservoir, and using attribute imaging. Speakers reviewed
specialized techniques used to gather good data from areas previously thought
to be inaccessible to seismic equipment.
Further, examples and slides were shown of cases operating immediately
adjacent to homes, environmentally sensitive areas, and areas where vehicles
were prohibited.
The main advantages to 3-D seismic technology are cost effectiveness,
improved imaging of structure, speed of interpretation, and advanced
interpretation techniques, according to workshop speakers. The enhanced
resolution capabilities of 3-D seismic were explained -- and examples showed
how 2-D data could be misleading . The data should be refined using 3-D data.
The session also addressed techniques in viewing 3-D seismic data using the
historical wavelet presentation versus color/polarity options offered in 3-D
seismic interpretation software packages. The presentations showed how data
could be selected to highlight faults, thin beds, time slices, or perspective
viewing of a block of the reservoir.
A case history described how the wellbore track of a well was added to the
data set of a 3-D seismic cross section as the well was being drilled. This
greatly assisted in directing the well into the desired fault block.
Work flow diagrams explained how hardware and software allow the
geophysicist to apply different theories to the same set of data to evaluate a
number of "what-if" scenarios, with each new interpretation being a
composite of all previously tested scenarios.
The attendees were introduced to some of the advanced analyses that are
being applied using 3-D seismic data. One of these methods, 4-D seismic, uses
multiple generations of 3-D data obtained over the same field to supplement
the reservoir simulation efforts in predicting reservoir performance.
Finally, the workshop included results of a 4-D study in offshore Louisiana
where the changing fluid levels within individual reservoirs were being
tracked using 3-D seismic data and interpretation techniques.
SPEAKERS
Merle Grabhorn
BDM-OK Inc. - Bartlesville, OK
Dr. Bob A. Hardage
The University of Texas at Austin, Bureau of Economic Geology - Austin, TX
Dr. Bruce Hart
New Mexico Bureau of Mines and Mineral Resources
New Mexico Institute of Mining and Technology - Socorro, NM
Back To Contents
Director: Dr. Rick Major
Bureau of Economic Geology, University of Texas
phone: (512) 471-1534, fax: 471-0140
e-mail: majorr@begv.beg.utexas.edu
Resource center Bureau of Economic Geology at the
University of Texas, Austin. Information available includes the Atlas of
Northern Gulf of Mexico Gas and Oil Reservoirs.
The workshops introduced producers to important Texas oil and gas geological
plays and to describe the new technologies that can improve recovery from these
reservoirs:
- The Frio Fluvial/Deltaic Sandstone Play, Vicksburg Fault Zone, Texas Gulf
Coast Houston, July 13, 1995
- The Frio Barrier/Strandplain Play on the San Marcos Arch, Texas Gulf Coast
Corpus Christi, July 14, 1995
- The Upper Guadalupian Platform Carbonate and Sandstone Play, Permian Basin
Corpus Christi, July 14, 1995
- The Wilcox Deltaic Sandstone Play, Rio Grande Embayment, Texas Gulf Coast
Corpus Christi, July 14, 1995
TECHNOLOGY SUMMARY
The workshops also demonstrated ways in which geologic, petrophysical, and
engineering data can be incorporated in a reservoir-flow model to identify the
locus of remaining oil and to design effective production programs. This part
of the workshop was based on a case study of Rincon Field.
The Frio Barrier/Strandplain Play on the San Marcos Arch workshop reviewed
the geologic and engineering attributes of the reservoirs in a sequence-stratigraphic
context.
The complex structural environment of these reservoirs was also discussed.
There followed a review of techniques best suited for characterizing the Frio
barrier/strandplain reservoirs.
WORKSHOP DESCRIPTION
This workshops consisted of a half-day of presentations followed by a
discussion. Participants received a set of workshop notes, an annotated
bibliography, two key publications, and abstracts from other key publications.
PROBLEM ADDRESSED
During the last decade 99 percent of Texas reserve additions were the result
of redevelopment of existing fields. From 1979 to 1993, only three percent of
reserve additions in the Texas Gulf Coast province were the result of new
field discoveries and only 12 percent were the result of new reservoirs
discovered in existing fields. The vast majority of reserve additions in this
time period, 85 percent, were from discovery of additional reserves in
reservoirs that were already under production.
Reservoirs of the Frio Fluvial/Deltaic Sandstone Play, Vicksburg Fault
Zone, have produced nearly one billion barrels of oil since this play was
discovered in the 1940s. More than half of the play's fields have been
abandoned. Yet it is estimated that more than one billion barrels of mobile
oil remains unrecovered in reservoirs of this play. If operators understand
the causes of reservoir partitioning and ways of extending reservoir life,
abandonment of additional fields can be avoided and much of this enormous
resource will be recovered.
Reservoirs of the Frio Barrier/Strandplain Play on the San Marcos Arch have
produced 9.4 trillion cubic feet of natural gas and 90 million barrels of oil,
yet approximately 20 percent of the recoverable petroleum resource remains in
these reservoirs. This resource target, and the high level of heterogeneity,
makes this play particularly attractive for advanced redevelopment.
Reservoirs of the Upper Guadalupian Platform Carbonate and Sandstone Play
have yielded 1,576 million barrels of oil of an estimated 6,830 million
barrels of original oil in place. In addition, these reservoirs have yielded
1,154 billion cubic feet of natural gas. Reservoirs of this play are estimated
to still contain 1,834 million barrels of mobile oil and 3,420 million barrels
of residual oil. The play is the target for advanced reservoir
characterization and field redevelopment, as well as tertiary recovery.
Reservoirs of the Wilcox Deltaic Sandstone, Rio Grande Embayment Play are
85 percent depleted. However, it remains the fourth largest play on the Texas
Gulf Coast and production activity in this play remains high. Because the
downdip extent of this play is not clearly defined, there are some exploration
opportunities.
The workshops reviewed the regional geologic controls on production in the
Frio Fluvial/Deltaic Sandstone Play, Vicksburg Fault Zone. Reviewed were
reservoir-characterization methods and technologies particularly applicable to
reservoirs in this play. There was a review of the log suites available in
this play and ways to calibrate those logs for reliable quantification of
porosity and saturation.
The Upper Guadalupian Platform Carbonate and Sandstone Play workshop
reviewed characteristics of the reservoirs. Particular attention was paid to
the difficulties of obtaining reliable core and log data in reservoirs that
contain gypsum. The final product of reservoir characterization is a 3-D
reservoir model, which can be used to design and prioritize reservoir
development operations such as infill drilling, well recompletion,
waterflooding and waterflood modification, and tertiary recovery operations.
The Wilcox Deltaic Sandstone, Rio Grande Embayment Play workshop included a
review of reservoir characterization strategies emphasizing integration of
sedimentologic, stratigraphic, engineering, petrophysical, and geophysical
data.
SPEAKERS
Dr. R. P. Major
PTTC Texas Region
The University of Texas at Austin, Bureau of Economic Geology - Austin, TX
Mark H. Holtz
The University of Texas at Austin, Bureau of Economic Geology - Austin, TX
Lisa E. Remington
The University of Texas at Austin, Bureau of Economic Geology - Austin, TX
A. Scott Anderson
Texas Independent Producers and Royalty Owners Association - Austin, TX
Back To Contents
Director: Dr. Iraj Ershaghi
University of Southern California
(213) 740-8076, fax: 740-7982
e-mail: ershaghi@archie.usc.edu
Resource center USC, petroleum engineering program, has
links to the Lawrence Livermore National Lab database. Now includes an expert
"Trouble Shooters" program for one-on-one technical assistance and
referrals.
The Jan. 15, 1997, Los Angeles workshop focused on modern technologies
required to cost-effectively produce future reserves in California.
TECHNOLOGY SUMMARY
The primary technologies applicable to increasing oil and gas production from
California's geologically complex reservoirs were discussed, with application
of most illustrated through field examples or case histories.
Primary technologies are advanced 3-D modeling and visualization,
reconciled with field production data, using geostatistics to quantify
uncertainty and risk, and reservoir simulation to predict performance under a
variety of options. In essence, this is the definition of integrated reservoir
management.
WORKSHOP DESCRIPTION
The workshop consisted of presentations by experts on California geology, oil
and gas resources, advanced 3-D modeling and reservoir simulation, and
geostatistics. Three case histories illustrated application of the concepts in
real-world situations. There also were break-out sessions on selected topics.
PROBLEM ADDRESSED
The complex geology of California's oil and gas reservoirs requires in-depth
reservoir characterization to develop optimum exploration and development,
completion, infill drilling, and improved oil recovery plans. The environment
is complex, data are extensive, so computer-aided geology and engineering are
essential for cost-effectively producing future reservoirs.
OVERVIEW OF TECHNOLOGY
Data were presented illustrating California's import situation, and the
increasing trend toward being an independent's province. Also, new geological
concepts were used to explain the geology of the California margin.
Speakers outlined the parameters which control oil recovery and well
productivity. The complexity of the data pointed toward using 3-D modeling and
visualization technologies, computer-assisted mapping, geostatistics, and
reservoir simulation to develop better answers, faster. An Elk Hills field
example illustrated application of the concepts to turbidite reservoir
characterization.
Current trends in reservoir simulation using advanced 3-D modeling were
reviewed. Effort is focused on developing techniques to (1) honor all relevant
data, (2) integrate seismic data, and (3) incorporate dynamic production data
in a geostatistical reservoir model. A 20-well North Sea field example
illustrated the concepts.
CASE STUDIES
DOE-Supported (Class 3) Projects included the Wilmington Field project, which
incorporated advanced 3-D modeling and visualization technology to guide
placement of horizontal wells used in a steam-assisted gravity drainage
process. In the Carpinteria Field, advanced, integrated reservoir management
techniques are being used to optimize future development plans in a
geologically complex, multi-horizon, mature offshore California field.
A local 3-D seismic case study showed how new faulting, depositional, and
sand discontinuity models, using the results of a 25 sq km survey had
influenced future development plans.
BREAKOUT SESSIONS
Offshore Potential A review of discovered oil and gas reserve estimates for
the Pacific Outer Continental Shelf (OCS). According to a1995 estimate by the
Minerals Management Service, undiscovered economically recoverable resources
in the Pacific OCS were estimated at 5.3 billion barrels and 8.3 tcf of gas.
Geostatistical Methods- A discussion of synergism in stochastic
conditioning. Also presented were examples of how seismic and geologic data
are incorporated using geostatistical approaches.
Computer-Aided Mapping Described trends in computer-aided geology toward
low-cost geology graphics on a PC, as well as workstation 3-D modeling The
Monterey Formation was used as an example of modern reservoir
characterization.
Data Availability Discussed the Internet oil and gas database system being
developed as part of DOE's ACTI program along with USC and Lawrence Livermore
National Lab. In this startup phase, most effort has been focused in
California. Further, Schlumberger described newer logging tools for reservoir
characterization (array induction tool, FMI imaging log, sonic imaging, and
NMR logging).
SPEAKERS
Dr. Iraj Ershaghi
University of Southern California - Los Angeles, CA
Ron Heck
R.G. Heck & Associates - Santa Barbara, CA
Mark Legg
ACTA Inc. - Lompoc, CA
Don Clarke
City of Long Beach, Dept. of Oil & Gas Properties - Long Beach, CA
Mark Wilson
Bechtel Petroleum Operation, Inc. - Concord, CA
Dr. Clayton Deutsch
Stanford University - Palo Alto, CA
Back To Contents
| PTTC Regional Director |
Phone |
Workshop Location |
| Dr. Lanny Schoeling |
(913) 864-7398 |
Wichita, KS |
| Dr. Roger Slatt |
(303) 273-3822 |
Denver & Billings, MT |
| Dr. Charles Mankin |
(405) 325-3031 |
Oklahoma City, OK |
| Dr. David Morse |
(217) 244-9337 |
Grayville, IL |
Waterfloods have been used in the past to sweep unrecovered mobile oil to
production wells. However, information and the lessons learned have stayed with
each operator and project.
A concerted effort was made to group petroleum reservoirs into unique
classes, apply a technology (waterflood) to a class, and share the results with
other operators who have fields in that same reservoir class.
Waterflooding requires a good understanding of the reservoir and the
technology of moving oil with water. The traveling workshops' group of
presentations included two basic discussions of the reservoir characteristics of
Class 1 reservoirs and five case studies of waterfloods in Class 1 reservoirs.
The Class 1 workshop series was so successful that PTTC will use it as a
prototype for future workshops held in multiple locations.
A January-February 1996 series of one-day workshops examined common threads
among five Class 1 (Fluvial-Dominated Deltaic) reservoir projects in four PTTC
regions. The Class 1 workshops, developed by the US Department of Energy and its
management and operating contractor, BDM-Oklahoma Inc., reviewed how
technologies can be applied in other types of reservoirs.
WORKSHOP DESCRIPTION
Each workshop addressed regional data management, cost-effective geological
and engineering data management, and reservoir characterization including
practical applications of 3-D seismic, identifying workover candidates, infill
drilling analysis, improved oil recovery process screening, and unitizing.
PROBLEM ADDRESSED
After primary production, typically more than two-thirds of the mobile
hydrocarbon is left in the pore spaces of the reservoir. Fluvial Dominated
Deltaic reservoirs represent the largest single target for recovery of
unproduced US oil.
OVERVIEW OF TECHNOLOGY
Fluvial Dominated Deltaic (FDD) reservoirs were interpreted to be sandstones
that were deposited in a deltaic or strictly fluvial environment. The
presentation included the genesis of the reservoirs, their sedimentary
characteristics, how to recognize them in the subsurface, and the quality that
can be expected in different parts of the delta.
The University of Oklahoma Class 1 FDD Project (Morrow Play) First the
University of Oklahoma began identifying and placing into plays all Class 1
reservoirs in Oklahoma. Next there was the collection of all relevant
geological and engineering data and field studies within each play, including
geological mapping and identification of critical reservoir and engineering
data elements.
University of Kansas/NARCO Stewart Morrow Field This project from the
University of Kansas had just started its waterflood. Secondary recovery was
estimated at 16.5 percent of the original oil-in-place (OOIP). The high
secondary recovery rate was due to extensive planning, testing and
cooperation. Major accomplishments included:
1) the development of a comprehensive reservoir database using personal
computers, 2) the completion of a simulation study to match the history of the
primary production, 3) the simulation of waterflooding and polymer flooding,
4) an economic analysis to assist in identifying the most economical
waterflood pattern, 5) completion of laboratory analysis conducted on
reservoir rock, and 6) overcoming problems associated with unitization so a
field-wide improved oil recovery process could be implemented.
University of Kansas /Russell Petroleum Savonburg Field Nelson Lease This
was a mature waterflood project. The field suffered from poor waterflood sweep
efficiency due to lack of reservoir management, channeling of water through
fractures, clogging of injection wells as a result of poor water quality, and
lack of injectivity into oil-bearing porous media.
The problems were addressed by conducting an integrated analysis of
existing data by geological and engineering personnel, permeability
modification treatments to improve injectivity profiles, air flotation
technology, pattern changes and improved wellbore cleanup methods, and infill
drilling of injection wells. This improvement in reservoir management doubled
the daily production rate.
University of Tulsa/Uplands Resources Glenn Pool Field Self Unit
This was an ultra-mature waterflood project documented by the University of
Tulsa. The application of reservoir management techniques has more than
doubled unit production from this 85-year-old field. A database was built
using all available geological and engineering data. Geostatistics were
applied and feasibility studies were carried out. Selective perforation and
workovers had been performed, which led to increased injection rates. The
economic evaluation indicated that the cost of finding oil is in the range of
$4 to $8 per barrel, but with the lessons learned, it could drop to $2 to $3
per barrel.
Diversified Operating Co. Sooner Unit
This was a mature waterflood. The application reservoir management, 3D
seismic, and selective infill drilling increased production 100 percent above
the previous trend. Individual operational compartments were identified and
produced. This project is expected to produce another 10 percent of the
original oil in place.
Each of the PTTC workshops included presentations on:
1. Geological Characteristics-Class 1 Reservoirs, by Dr. Richard Andrews,
University of Oklahoma Geological Information Systems, Norman, OK
2. Oklahoma's Class 1 Fluvial-Dominated Deltaic Project, by Dr. Richard
Andrews, University of Oklahoma
3. University of Kansas/NARCO Stewart "Morrow" Class 1 Project,
by Rodney Reynolds, KU Center for Research Inc., Lawrence, KS
4. University of Kansas/Russell Petroleum Savonburg Class 1 Project, by Dr.
Lanny Schoeling, KU Center for Research Inc., Lawrence, KS
5. University of Tulsa's Glenn Pool Field Class 1 Project, by Dr. Mohan
Kelkar, TU, and Dan Richmond, Uplands Resources, Tulsa, OK
6. Diversified Operating Company's Sooner Field Class 1 Project, by Mark
Sippel, consultant for Diversified Operating Co., Denver, CO
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