GTI-03/0035

Fracture Quantification in Naturally

Fractured Gas Reservoirs: Research Update 

A collaborative effort between industry and government shows progress towards the goal 

of identifying productive natural fractures in gas reservoirs using seismic methods.

Applying Sequence Stratigraphy 

and Seismic Stratal Slice Technology 

in the Gulf of Mexico 

Improved geological understanding of mature gas reservoirs in offshore 

Gulf of Mexico points towards unrecovered resource.

Cement Pulsation Reduces 

Remedial Cementing Costs

A simple new technique to improve primary cement jobs has resulted in a 36 percent 

decrease in average remedial cementing costs for a group of Canadian gas wells.

GTI Hydrate Characterization Research

New Gas Technology Institute facility provides tools for understanding 

the dynamic behavior of gas hydrate.

Morphysorb® Applied to De-Bottlenecking

of Gas Treating System

New solvent exceeds performance targets during test at Canadian sour gas treating facility.

Improved Modeling Increases 

Salt Cavern Storage Working Gas

An improved model for gas storage caverns has revealed the potential for safely 

increasing storage capacity by accurately characterizing the plastic behavior of salt. 

TECHNOLOGY DEVELOPMENTS IN NATURAL GAS EXPLORATION, PRODUCTION AND PROCESSING

Well 

Completions

Exploration

Resource

Characterization

Gas

Processing

Gas 

Storage

Exploration and

Development

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

New Items of Interest

03 Editors’ Comments

37 New Products, Services 

& Opportunities

38 New Publications

38 Events Calendar

Winter 2003 • Volume 9 • Number 1

4

10

22

25

28

33
2 GasTIPS • Winter 2003

GasTIPS®

Managing Editor

Karl R. Lang

Hart Publications

Editors

Brad Tomer

Strategic Center for Natural Gas

DOE-NETL

Joe Hilyard

Gas Technology Institute

Subscriber Services

Joyce Kelly

Hart/IRI Fuels Info. Svcs.

Publisher

Hart Publications

CONTENTS

Editors’ Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Fracture Mapping. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Maximizing Production in Mature Reservoirs . . . . . . . . . . 10

Improving Remedial Cementing . . . . . . . . . . . . . . . . . . . . . . 22

Hydrate Characterization. . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Sour Gas Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Modeling Improves Cavern Storage Capacity . . . . . . . . . . 33

New Products, Services & Opportunities . . . . . . . . . . . . . 37

New Publications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

DISCLAIMER:

LEGAL NOTICE: This publication was prepared as

an account of work sponsored by either Gas

Technology Institute (GTI) or the U.S. Department

of Energy, (DOE). Neither GTI nor DOE, nor any person acting on behalf of either of these:

1. makes any warranty or representation,

express or implied with respect to the accuracy,

completeness or usefulness of the information

contained in this report nor that the use of any

information, apparatus, method, or process disclosed in this report may not infringe privately

owned rights; or

2. assumes any liability with respect

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

of, any information, apparatus, method or process

disclosed in this report.

Reference to trade names or specific commercial products, commodities, or services in this

report does not represent or constitute an

endorsement, recommendation, or favoring by GTI

or DOE of the specific commercial product, commodity or service.

GasTIPS® (ISSN 1078-3954), published four times a year by Hart Publications, a division of

Chemical Week Associates, reports on research supported by Gas Technology Institute, the

U.S. Department of Energy, and others in the area of natural gas exploration, formation evaluation, drilling and completion, stimulation, production and gas processing.

Subscriptions to GasTIPS are free of charge to qualified individuals in the domestic natural

gas industry and others within the western hemisphere. Other international subscriptions

are available for $149. Domestic subscriptions for parties outside the natural gas industry are

available for $99. Back issues are $25. Send address changes and requests for back issues to

Subscriber Services at Hart Publications, 1201 Seven Locks Road Suite 300, Potomac, MD

20854, FAX: 301/424-7260. Comments and suggestions should be directed to Karl R. Lang,

GasTIPS Editor, at the same address.

GTISM and GasTIPS® are trademarked by Gas Technology Institute, Inc.

© 2002 Hart Publications, Inc.

Unless otherwise noted, information in this publication may be freely used or quoted, 

provided that acknowledgement is given to GasTIPS, and its sources.

Publication Offices

Hart Publications

1201 Seven Locks Road, Suite 300

Potomac, MD 20854

301/340-1520 • FAX: 301/424-7260

POSTMASTER: Please send address changes to GasTIPS, c/o Hart Publications, Inc., 

PO Box 59720, Potomac, MD 20897-5221.
Winter 2003 • GasTIPS 3

Perhaps the most noticeable

change is the new

typeface for the

body text. The previous choice

was from the Bodoni family of

typefaces, of a lineage designed

by a famous Italian printer,

Giambattista Bodoni, in the

1700s. The new typeface, Stempel

Schneidler, was designed in 1936 by

a German teacher and has a lighter,

more modern look. However, Herr

Schneidler based his design on typefaces used by Venetian printers from

the Renaissance, so the Italian influence

is still there. These changes, while relatively minor, reflect our continued commitment to maintaining the publication’s

utility to readers.

Behind this new look GasTIPS’s focus

remains where it has been, on new and

developing natural gas exploration, production and processing technologies. From a

content standpoint this issue is very

diverse, with six contributed articles falling

under five separate topic headings. To deal

with updates regarding research that is

focused on finding more efficient ways to

locate gas reserves. In one case, by using a

better understanding of stratigraphy to

locate unrecovered gas within geologically

complex, mature, Gulf Coast fields. In the

second case, by developing seismic tools to

identify permeable fracture zones within

naturally fractured

gas-bearing formations. Both of

these articles describe ongoing research that

has been under way for a number of years.

The remaining articles cover a wide

range of topics. Two of these highlight

newly commercialized research products

from Gas Technology Institute. One, a

service for improving casing cement

integrity via pressure pulses, the other, a

new solvent system for removing contaminants from sour gas streams. Both of these

articles provide case studies of the application of these new technologies by industry partners.

An article on natural gas storage

modeling provides evidence that a

significant amount of additional storage capacity may be made available

in salt cavern storage facilities by

simply altering pressure specifications during the injection/ production cycle.

And in a sixth article, we

describe the expanding capabilities of GTI laboratories for

characterizing and understanding gas hydrates. These

unique combinations of

hydrocarbon and water

molecules are coming

under increased scrutiny,

both as a plugging agent in

deepwater pipelines and as a potentially vast resource trapped in submarine

sediments.

We hope you’ll find this issue of

GasTIPS informative. Please contact the

individuals listed at the end of each

article to obtain more information on

specific topics. If you have any questions or comments, please contact

the Managing Editor, Karl Lang, at

klang@chemweek.com/. ✧

Same Book, 

New Look

Publications, like many of us, can benefit from refinements to their “look” every now and then. 

The look of this issue of GasTIPS, now beginning its eighth year, reflects changes in style and 

structure that we believe improve the journal’s readability. The format has been “tightened up”

to make it more reader-friendly and improve the visual appeal of single

article reprints, for which we often get requests. 

Commentary
EXPLORATION & DEVELOPMENT

As part of the US

Department of Energy’s

Natural Gas Program,

Lawrence Berkeley National Laboratory

(LBNL) is leading a multi-institutional

project to develop methods for mapping

the fractures that control flow in naturally fractured gas reservoirs. While current

technology can often locate fracture

trends, it remains unable to provide the

accuracy necessary to site wells based

upon fracture permeability. The work

has progressed from lab studies to controlled field studies and now to a full

scale application in the San Juan Basin in

New Mexico. This article summarizes

ongoing efforts to apply high resolution

fracture identification methods (logging,

single well seismic and VSP) and integrate the results with previously

acquired 3-D surface P-wave imaging.

The goal is to determine the optimum

technique for not only locating fractures

but quantifying their properties in a

manner such that the fractures controlling flow can be identified. 

Background

Current methods rely on gross definition of

fracture properties using attributes such as

P-wave anisotropy, AVO or AVA. While

useful for gross fracture detection, these

approaches have not been able to define

the specific fracture sets that control permeability. Past work (Majer et al, 1997) has

shown that such fractures sets, even single

fractures, can control flow from a large

reservoir volume.

The current research is based on the

hypothesis that to obtain the required resolution it will be necessary to gather data at

higher frequencies and with greater spatial

sampling than conventional surface seismic

methods can provide. This implies that

the data must be recorded using

sources and/or receivers placed in the subsurface. Although the use of subsurface

sources and receivers on a semi-permanent

or permanent basis may be years in the

future, this project hopes to extend surface

information with current borehole methods (VSP, crosswell and single well seismic)

in order to quantify fracture characteristics.

However, since surface seismic is often all

that is available, a primary goal of this work

remains the development of a methodology to extract as much information as possible from surface data (Daley et al, 2002).

Research efforts to date have focused on

field experiments in well-characterized field

sites at both intermediate and full field

scale. These include a Conoco test site in

Oklahoma, an MIT test site in Michigan,

and a NIPSCO gas storage field in Indiana

(Majer et al, 1997). Researchers are now

working at industry sites of opportunity

while linking this work with the service

industry so that the technology can be

deployed rapidly when ready.

4 GasTIPS • Winter 2003

by Ernest L. Majer, Fracture Quantification LBNL

in Naturally Fractured 

Gas Reservoirs: Research Update 

A collaborative effort between industry and government shows progress towards the goal of identifying

productive natural fractures in gas reservoirs using seismic methods.

Figure 1: Study Area (Red Box) in Relation to the Fault Structure as Determined by 2-D and 3-D Seismic
The field site that is the subject of this

article is a ConocoPhillips property in the

San Juan Basin of New Mexico. Because it

is in an area of ongoing commercial interest

and has a wealth of geologic and geophysical information, it is anticipated that

commercial wells will ultimately be drilled

based on the results of this work, ideally

validating the methodology.

Project Organization

The overall project work plan is divided

into four broad tasks: Modeling, Field

Measurements, Processing and Interpretation, and Reservoir Simulation. Overall

organization of the project is managed by

LBNL, and the other participants include

ConocoPhillips, Schlumberger, Lynn Inc.,

Stanford University, and Virginia Tech. 

LBNL has responsibility for modeling,

with support from both Stanford and

Virginia Tech. As for actual field measurements, LBNL is responsible for VSP

work and some of the single well data

collection. Schlumberger is responsible

for the high frequency single well

work. ConocoPhillips is responsible

for 3-D surface reflection measurements and co-share the responsibility

with LBNL for the semi-permanent/

permanent array measurements

ConocoPhillips is responsible

for data processing of surface 3-D

seismic data and Lynn Inc. is providing data processing support for

fracture specific processing. LBNL

and Schlumberger will process

their data sets and Schlumberger

will also provide experimental processing of multicomponent VSP

data for fracture imaging. Virginia

Tech will aid in interpretation, as

will LBNL and Stanford. Virginia

Tech will also perform interpretation of fracture spacing based upon

stochastic analysis.

Schlumberger Reservoir Technologies is

providing reservoir modeling and simulation based upon the results of the seismic

imaging. Schlumberger will also work with

ConocoPhillips production engineers to

refine and improve production models as a

result of the fracture imaging.

Theory and Methods

Because fractures represent a significant

mechanical anomaly, seismic methods can

potentially be used to identify not only the

presence of fractures, but such attributes as

orientation, density, aperture, and filling.

Additionally, the partially saturated rock in

gas reservoirs (usually heterogeneous), is

difficult to image. However, this complication also presents an opportunity in that

the highest resolution images can be constructed using the information contained in

the shear and converted waves, along with

Winter 2003 • GasTIPS 5

EXPLORATION & DEVELOPMENT

Figure 2: Two Well Sites Selected (Newberry and Moore Wells)

Figure 3: Layout of 9-C VSP for Newberry and Moore

Wells
EXPLORATION & DEVELOPMENT

compressional waves. Imaging naturally

fractured gas reservoirs should involve a

wide range of scales and distances. The frequencies and wavelengths required will

vary by orders of magnitude, depending

upon the problem at hand.

For example, to characterize within 10

meters a target at a depth of 3000 meters, an

image resolution of centimeters is unnecessary. On the other hand, if delineation of

flow processes is required around the wells,

meter-scale or better resolution is needed.

For most applications a three-dimensional

picture of the elastic properties in the earth

on a scale less than a meter near the surface

to no more than a few tens of meters at

depths of several kilometers would suffice.

The greatest obstacle, however, is to determine the significance of an image, once it

is obtained. The challenge is to define the

seismic properties that control reservoir flow

and permeability, rather than simply the

geologic features. Given the proper conditions (i.e., enough measurement points and

computing power, sufficient frequency content, etc.), it is possible, in theory, to attain

this resolution. However, many practical

obstacles inhibit achieving this goal.

Image resolution with current techniques is limited by the amplitude and frequency content of the seismic waves, and

by the level and complexity of the ambient

and signal-generated noise fields. With surface sources, a heterogeneous surface

weathered layer (often tens of meters thick)

means that the high frequency content and

coherence of the signal that is input

through the ground is severely limited. VSP

solves this problem in part, by placing

receivers beneath the highly attenuating

and variable surface layer (so that the signal

is not required to pass through the surface

layer twice), and also by recording the

wave field with a vertical array in the borehole so that “up going” and “down going”

waves can be identified and separated. An

approach that does address the fundamental imaging limitations is one which incorporates properties of the secondary (S) and

the converted waves (P to S, S to P) that are

generated in the earth. Potentially by incorporating amplitude and converted waves

into the analysis, surface based methods

could be very useful. This approach is particularly well suited for applications where

the primary (P), secondary (S) and converted waves can be examined directly. In

recent years the use of S-waves has

become more common, particularly in

defining anisotropy and fracture content

of rock. Fracture detection using P- and

S-wave surface reflection coupled with VSP

methods is demonstrating that the full

6 GasTIPS • Winter 2003

Figure 4: Field Data Corresponding to Modeled Distances Showing Possible Fracture Events (Arrows)

The objective of the field tests 

was to augment the existing data sets 

at both the borehole scale (logging and 

single well seismic) and surface seismic scale (VSP). 
potential of seismic methods requires

3-component data.

In addition to the continuum properties

approach on shear wave splitting, recent

laboratory and theoretical work explains

shear wave anisotropy in terms of mechanical properties of the fracture discontinuity

itself, i.e., a surface of a finite stiffness affecting velocity as well as attenuation of a seismic wave of any wavelength. In the stiffness

theory, the lateral extent of a target fracture

is still important to seismic resolution

but with sufficiently low fracture stiffness

the thickness of the fracture can be much

less than the seismic wavelength and still

have a detectable frequency-dependent

effect on the seismic wave. A large amount

of information exists in the properties of the

secondary waves, which offers promise for

substantial improvement in the resolution of

seismic methods.

Modeling Progress During 2002

The project effort during 2002 was focused

on three areas: modeling seismic wave

propagation in fractured media, acquisition of an extensive set of VSP data, well

logs, and single well data, and initial processing of the field data.

The thrust of the modeling effort has

been to model the actual field data that was

processed in both 2-D and 3-D. A 20

square mile volume was selected by the

research team based on an analysis of the

geologic and seismic data available and

ConocoPhillips’ drilling program. Once the

20 square mile volume was selected the

next step was to determine model parameters. In order to do so, maps and actual

field inspections were used to determine

fracture spacing, width, orientation and

overall geometry with respect to the bedding. Initial processing of the 3-D data by

ConocoPhillips had focused on deeper targets than those of this investigation.

Therefore, new conceptual

models were derived into

which fractures could be

introduced to determine the

effect on seismic reflection

data. The model’s fractures

were spaced at 20 meters and

“large” faults wereplaced at

610-meter spacing, on a

40 layer geologic model including the Menefee and the

Dakota formations. The modeling was done with a finite difference model solving for the

full elastic wave field using

anisotropic stretched grids to

model fracture properties.

Existing 3-D data from the

20-square mile target area

(Figure 1) was reprocessed

with state-of-the-art and

experimental processing methodologies. The objective has been to apply

processing that would enhance interpretation for fracture and fault identification. ConocoPhillips and Lynn Inc. have

been involved in this effort with the objective being to derive a processed data set

that Lynn Inc. interpreted for fault and fracture structure. Lynn Inc. utilized the singlefold and the partially-stacked azimuth gather data, selected from locations of interest

as identified by ConocoPhillips. The

azimuthal variations in seismic signatures

(travel time, amplitude, frequency, coherence, etc.) were derived with the one-fold

versus stacked-data response and compared, and the magnitude of the azimuthal

anisotropy estimated.

These magnitudes were compared to

well production data (where known) and a

recommendation was made as to how to

separate the azimuths for the creation of

3-D limited-azimuth imaged volumes. These

3-D volumes allow the evaluation of the

coherently-reflected wave field’s response

to the presence of natural fractures at target

level. Anomalous zones, which indicate a

high fracture density, were then inspected

in the one-fold (unstacked) domain in order

to document their incoherently scattered

wavefield response. The result was an

analysis of predicted well performance

across the 20 square mile study area. Two

well sites were selected by ConocoPhillips

operations, one in the SW (Newberry) and

one in the NE (Moore) portions of the

study area (Figure 2). The location of the

two new wells is shown in relation to the

velocity difference derived from analysis of

the surface 3-D seismic. The warm colors

in the figure indicate zones where production in is likely to be better. 

Field Data Acquisition

The objective of the field tests was to

augment the existing data sets at both the

borehole scale (logging and single well

seismic) and surface seismic scale (VSP).

Winter 2003 • GasTIPS 7

EXPLORATION & DEVELOPMENT

Figure 5: FMI Log Showing Natural Fracture
EXPLORATION & DEVELOPMENT

Field testing involved performing multicomponent/multi-azimuth VSP and single

well seismic in a well where surface 3-D

seismic had been performed. This provided

for a range of data resolution at the same

site. Schlumberger’s role was to carry out

conventional logging along with cross

dipole sonic, FMI and single well sonic tool

runs in these wells. VSP was then performed in both wells using multi-offset

multi-azimuth 9-C collection. The VSP

design was based upon the modeling and

theoretical work performed to date (Daley et

al 2002). Locations were selected to gather

reflected and scattered energy from the

near vertical features (fractures). 

The data were collected according to initial modeling of a range of anticipated fracture geometries. Single well seismic was

performed in the same well to obtain higher resolution images. Both P-wave (Piezoelectric bender) and S-wave sources

(Conoco AC orbital vibrator) sources are

being used in this work. Shown in Figure 3

is the design of the VSP shot points around

the Newberry and Moore wells (each symbol is the location of a shot point). Vertical,

S1 and S2 components using a multi-component vibrator were collected at each shot

point. The VSP recorded vertical, S1 and S2

components at 20 foot intervals over a deep

and shallow interval (total of 1500 feet) in

each well. After the VSP was done LBNL performed the single well work in each well

using the orbital vibrator and three component sensors, and the piezoelectric and

hydrophones. The data spans from the well

log scale to the surface seismic scale (8000 hz

to 10 hz) in a continuous fashion.

Interpretation and Processing

The objective of the interpretation and processing effort has been (and will be) to

derive images that are indicative of fracture

characteristics. Each method (surface seismic, VSP, crosswell, single well) has a different image produced at a different scale. The

initial hypothesis that higher resolution is

necessary to define the “important” (permeable) fractures will be tested based upon the

different images produced. A second

hypothesis, that there is information in surface seismic attributes not yet identified that

is indicative of permeable fractures, will also

be tested.

The following data have been compiled

for each well:

• Multi offset (approx 70 source points

per well ) 3-D , 9-C VSP at 20 foot

spacing (10 to 100 hz)

• Single well with three component

receivers at 10 foot spacing using

orbital source (50 to 400 hz) 

• Single well with hydrophones at

5 foot spacing using piezoelectric

source (200 to 4000 hz) 

• FMI and dipole sonic, (4000 to

8000 hz.) 

• Single well sonic (in Moore well only).

Together with the reprocessed seismic

data, this information will form the basis of

a unique multi-scale data set to process for

fracture properties. Each well will be put on

production after the seismic studies are

completed to check the predictions.

Shown in Figure 4 is an example of the

data with some possible fracture events.

The data processing and examination are

very preliminary at this point and much

more work needs to be done.

Figures 5 and 6 are examples of the well

log and single well data. Anisotropy at the

well as well as discrete fractures are evident

in the data at both the log scale and single

well scale. This is very encouraging for using

seismic for understanding fracture flow.

Next Steps During 2003

Overall the project has made good progress

towards the goal of developing and testing

seismic methods for fracture quantification.

The team of LBNL, ConocoPhillips,

Schlumberger, Stanford, and Virginia Tech

has made good progress. The drilling of the

well by ConocoPhillips (over $1.5 MM

investment alone) and the acquisition of the

field data sets mark a significant milestone

in this work and in general a significant scientific contribution to the discipline of fracture imaging. The team now has the data set

needed to progress towards our goal. The

final phase of the project will involve additional work in modeling, data processing,

and reservoir simulation.

With respect to modeling, the groups at

Virginia Tech and Stanford will concentrate

on the characterization of heterogeneity

and seismic processing with regard to

enhancing fracture signals in the VSP and

single well data. The seismic heterogeneity

estimator has been expanded into a fully

3D seismic volume attribute. Seismic

heterogeneity may be caused by data

acquisition and processing, by complex

stratigraphy and lithology, and maybe by

subsurface structure such as faults, joints,

and fractures. Acquisition and processing

footprints should be removable with

methods currently being developed for

other applications. Through analysis of

the field data, the team will examine the

cause of seismic heterogeneity at the San

Juan test site.

It has been observed that seismic

8 GasTIPS • Winter 2003

Overall the project has made good progress 

towards the goal of developing and testing 

seismic methods for fracture quantification. 
heterogeneity varies spatially. Typical

methods of reservoir modeling cannot

handle spatially heterogeneous statistics. Hence, Virginia Tech will develop

an algorithm to simulate small-scale

heterogeneity with spatially heterogeneous statistics. In a later stage, the

algorithm will even be extended to

condition the realizations to seismic

data and well logs.

The second remaining focus is on

data processing. Numerical simulations

by LBNL showed that the seismic signature of fractures is similar to diffraction

hyperbola. Seismic data processing traditionally suppresses such features because

they are considered “noise.” Using a very

simple model, the team derived and

examined processing flows that enhance

diffraction-like signals but suppress

reflection signals and noise. Currently,

Virginia Tech is testing these processing

algorithms using the synthetic 2D dataset

computed by LBNL. Later, the methods

will be extended to 3D, tested with

synthetic data, and applied to field data

to examine if fractures can be detected

from the surface.

Finally, Schlumberger will investigate the

relationship between discrete fractures

detected on the finest scale and their manifestation in effective medium theories at

intermediate scale. To do this they will compile formation micro-imager (FMI) data and

cross dipole acoustic logs

together with supporting

information (monopole compression, shear and Stoneley,

gamma ray, 4-arm borehole

caliper). This data will be

processed to provide compressional and shear slownesses, anisotropic parameters, borehole ovality (an

indication of intrinsic stress

directions), breakouts, and

natural and drilling induced

fractures in the zones of

interest. The data will be

analysed to test the hypothesis that a quantitative relationship exists between the density and orientation of fractures

as seen on the FMI log

and the effective anisotropy

observed on the acoustic logs.

These results along with the

results of the other fracture

imaging work will be used to

develop a reservoir model to

predict well performance. The

prediction will then be compared with actual performance. ✧

For more information on the status of this research

contact Ernie L. Majer at LBNL by email at

elmajer@lbl.gov or at 510-486-6709.

References

Majer, E.L., Peterson, J.E., Daley, T., Kaelen, B.,

Myer, J. L.,Queen, J., D’Onfro, P., and Rizer, W.,

1997, Fracture Detection Using Crosswell and Single

Well Surveys, Geophysics, Vol. 62, No. 2, pp. 495-

504, LBL-38259.

Daley, T.M., T. Nihei, L.R. Myer, E.L. Majer, J.H.

Queen, M. Fortuna, J. Murphy, R.T. Coates, 2002,

Numerical modeling of scattering from discrete fracture

zones in a San Juan Basin gas reservoir, Abs. annual

SEG meeting.

Winter 2003 • GasTIPS 9

EXPLORATION & DEVELOPMENT

Figure 6: Example of Single Well Data Showing Possible Natural Fractures
EXPLORATION TECHNOLOGY

The Bureau of Economic

Geology (BEG) at the

University of Texas at Austin, has

been working to improve gas-recovery efficiency in complex onshore reservoirs since

1988 through Secondary Gas Recovery

(SGR) research sponsored by the U.S.

Department of Energy, with secondary

sponsorship by the Gas Research Institute

(now Gas Technology Institute). A quantitative assessment of the benefits of SGR

research and technology transfer over the

period 1988 through 1998, indicates that

incremental gas production in seven fields

studied under the SGR program is projected

to total 231 Bcf. 

SGR projects in onshore Gulf Coast

sandstones, sandstones of the Fort Worth

Basin, and karsted carbonate reservoirs of

the Permian Basin have successfully

defined secondary, or incremental, gas

recovery on the basis of targeting stratigraphic and diagenetic reservoir heterogeneity. Past projects have been collaborative, with industry partners ranging from

majors, such as Shell and Mobil, to midsize

companies, such as Oryx and Union Pacific

Resources, to small independents.

In 1998, the BEG decided to pursue similar research that would demonstrate SGR

principles and practices in an established

natural gas field in the Federal offshore of

the Gulf of Mexico. The goal of the pro10 GasTIPS • Winter 2003

Applying Sequence Stratigraphy

and Seismic Stratal Slice 

Technology in the 

Gulf of Mexico 

Improved geological understanding of mature gas reservoirs in offshore Gulf of Mexico points towards 

unrecovered resource.

by Lesli J. Wood, T. Hentz, 

H. Zeng, M. DeAngelo, 

S. Dutton

Bureau of Economic Geology –

The University of Texas

Figure 1: Location of OSGR Study Area
gram was to research new techniques in

defining heterogeneity and compartmentalization in mature gas reservoirs through the

use of multidisciplinary reservoir characterization and innovative technology applications for enhancing production from

untapped, bypassed, incompletely drained,

or intrawell reservoirs.

Significant recoverable gas resources

remain undiscovered, undocumented

and unproduced in the Miocene strata

of the northern Gulf of Mexico. More

than 41 percent of the known gas in the

GOM Miocene strata remains to be

produced. One of the most significant

plays remaining in the Miocene of the

northern GOM is the numerous lowstand prograding wedges that characterized the Miocene-age depositional

shelf-edge locations throughout the

Gulf subsurface.

The OSGR research has shown that a

variety of sub-regional reservoir sandstones pinch-out within thick, stacked

lowstand prograding wedges. Their setting within slope and basinal shales creates ideal conditions for potential

hydrocarbon migration and entrapment.

These wedges are composed of distal,

medial and proximal portions each identifiable in logging cross-sections and

mappable within stratal slice (proportional sliced) images. Within the BEG

study area, the lowstand prograding

wedge sandstones of the Robulus “L”

zone contain the most gas reserves of

any identified zones of opportunity: 41

percent of the total oil and gas in place

(421 Bcf) and 40 percent of unrisked

reserves (251 Bcf). The combination of

unique stratal slice imaging of the seismic performed within a sequence framework of key chronostratigraphic surfaces enable geoscientists to define these

resource targets and reduce both their

risk and cycle time in exploiting these

reserve addition opportunities.

Application of Specific Tools

Improves Accuracy

Sequence stratigraphy has revolutionized

the manner in which geoscientists, geophysicists and geoengineers examine, map

and produce reservoirs (Van Wagoner, et al.,

1990; Mitchum et al., 1993). The concept of

reservoirs compartmentalized by sequenceWinter 2003 • GasTIPS 11

EXPLORATION TECHNOLOGY

Figure 2: Ranges of Paleobathymetric Zones

Recorded within the Study Interval.

Figure 3: Relative Positions of Distal, Medial and Proximal Third-Order Sequences and Systems Tracts.

Significant recoverable gas resources remain undiscovered, undocumented and unproduced in the

Miocene strata of the northern Gulf of Mexico. 
EXPLORATION TECHNOLOGY

bounding unconformable and conformable

surfaces has enabled geoscientists to better

understand reservoir behavior by explaining and targeting previously unnoted baffles and barriers to fluid flow. Likewise, 3D

seismic technology in the past decade has

revolutionized the science of seismic interpretation by significantly improving our

ability to image and resolve many of these

same key surfaces and

flow-inhibiting horizons.

Recent advances in attribute

or pseudo-attribute extraction

and analysis have significantly increased the interpreters ability to transform

petrophysical information

from their seismic data.

Analysis of lateral continuity

and variations in frequency spectrum, and comparison of both lateral and

vertical impedence relationships have increased our ability to define and recognize

stratigraphic and structural

features. With so many and

varied options available for

viewing the 3D data volume

it is often easy to get lost as

to what attributes mean

and how to translate them

into meaningful prospects.

By applying a select number of specific tools in a

systematic approach within

a framework of key

sequence stratigraphic surfaces, interpreters can improve the efficiency and accuracy of their reservoir

characterization process and identify

numerous new opportunities for

resource additions.

Study Area Targets 

Shelf Miocene

Siliciclastic Miocene strata are currently

the most productive of all chronostratigraphic units in the northern Gulf of

Mexico (GOM) outer continental shelf,

accounting for 40% of all hydrocarbons

produced and 40% of all remaining

proved reserves. Most of these Miocene

resources (99% of cumulative production, 61% of remaining proved

reserves) are restricted to the present

continental shelf (Crawford, et al., 2000),

where the majority of active fields are

considered mature. These statistics

indicate that significant potential exists

for interfield and intrafield development

in the shelf area (<650 ft water depth).

Moreover, deep Miocene strata (>15,000 ft

subsea) below established reservoirs in

the shelf area hold the promise of additional resources. Only 5% of all wells

drilled on the GOM shelf have penetrated strata below 15,000 ft, in which there

is an estimated 10.5 Tcf of deep gas

recoverable resources (Minerals Management Service, 2001). Bypassed and underproduced oil and gas are waiting to be

tapped and developed in mature fields,

and new plays and numerous stratigraphic traps exist that can contain significant undiscovered resources both

shallow and at depth. The challenge is

to recognize the traps and design an

integrated approach to capitalizing on

the resources.

The most recent OSGR study area

included two major producing fields,

Tiger Shoal and Starfak fields in the

Vermilion Block 50 and South Marsh

Island Areas, northern GOM (Fig. 1).

Although originally designed to look at

data from a single field, the project

evolved to encompass two fields in

detail, as well as to consider surrounding fields of Mound Point, Lighthouse Point, and Amber. This evolution

reflected the need to consider more

regional applicability of research results:

12 GasTIPS • Winter 2003

Figure 4: Dip Cross Section of Distal Third-Order Sequence 10

(Lower Miocene), Starfak Field.

More than 41 percent of the known gas 

in the Gulf of Mexico Miocene strata 

remain to be produced. 
to move from the postage-stamp

application of research results from a

single field to the broader distribution of

observations throughout the GOM

Miocene. The study area contains

predominantly progradational deposits

consisting of upward-coarsening deltaic

deposits, as well as distributary- and

fluvial-channel deposits. The study area

as noted in previous publications (Seni,

et al., 1997) is included in four large gasdominated plays. The combination of

asset size and potential, regional productivity of the field intervals, and data

availability and quality made this an

excellent area for pursuing the objectives of the OSGR program.

Sequence Stratigraphy

Framework

The sequence stratigraphic framework

interpreted over the study area provided a

genetic context for all phases of the SGR

study of the Miocene succession (Hentz et al.,

2000, 2001, 2002; Zeng et al., 2000a, 2001a–c;

Badescu and Zeng, 2001; DeAngelo and Wood,

2001; Rassi and Hentz, 2001; Zeng, 2001; Rassi,

2002a–c; Zeng and Wood, 2002; Hentz and

Zeng, 2003). Moreover, it established the

groundwork for investigations of reservoirspecific attributes and the identification

of previously undetected hydrocarbon

resource addition opportunities within the

two-field area, this project’s 3-D seismic volume, and adjacent on-shelf areas.

Well-log curves from over 156 logs were

provided by Texaco, the project’s industry

partner, for analysis and integration with

over 352 square miles of 3-D seismic data.

Faunal occurrence, abundance and diversity data were provided from 15 wells

across the study area. Paleobathymetric

indicator fauna, benthic organisms that

lived within certain ranges of water depth

(Picou et al., 1999), enabled reconstruction of

water depths within which reservoirscale (fourth-order) systems tracts were

deposited. In most wells, sample faunalcounts were recorded in the wells every

30 ft from immediately above the study

interval to the bottom of the well. These

lists provide an accounting of fossil

assemblages, abundances of individual

species, and stratigraphic positions of major

faunal “floods.” Indicator fossils within

faunal floods, which typically coincide

with marine condensed sections, can be

used to estimate the paleobathymetric conditions under which the sediments containing the fossils were deposited. The indicator fossils in wells within the study area

record an overall upward-shallowing trend

within the entire study interval (Fig.

2), coinciding with the overall regressive

stratal-stacking pattern. The widest portions of zone bars in the figure represent

stratigraphic intervals of particularly abundant indicator fauna. Many sandstones and

immediately adjacent shaly strata in the

Winter 2003 • GasTIPS 13

EXPLORATION TECHNOLOGY

Figure 5: Dip Cross Section of Distal Third-Order Sequence 9 (Lower and Middle Miocene),

Starfak field.
EXPLORATION TECHNOLOGY

lower two-thirds of the study interval were

deposited under marginal-marine conditions; however, indicator fossils of this

environment are sparsely preserved.

Information provided by the indicator

fossils also offers corroborative evidence

for interpretations of systems tracts.

Paleogeographic Setting

The upper lower Miocene-to-Pliocene strata of the ancestral Mississippi River

depocenter form a dominantly regressive

succession 10,000 ft thick. This remarkable

interval of thick siliciclastics accumulated

during a period of high sedimentation rates.

Sandstone-bearing depositional systems,

particularly deltaic deposits (both lowstand

and highstand), are therefore very well

developed. Depositional facies of the

Miocene section grade upward from shalerich slope and sandy basin-floor deposits to

sandstone-dominated, inner-shelf facies.

The sequence-stratigraphic framework for

the study area comprises 10 third-order

sequences, at least 58 fourth-order

sequences, and the full array of systems

tracts within both sequence hierarchies

(Hentz and Zeng, 2003).

Conceptually, stratal stacking patterns

within third-order systems tracts vary relative to their position in the shelf-to-basin

depositional profile (Mitchum and Van

Wagoner, 1990; Mitchum and others, 1993).

Furthermore, these variations coincide with

changes in stratal attributes of the component

fourth-order systems tracts. Therefore, the

study interval can be subdivided into distal,

medial, and proximal parts (Fig. 3), each of

which share sequence-stratigraphic characteristics, to systematically document larger scale

stratal and depositional trends within the

~10,000-ft study interval. The study interval

comprises two distal, four medial and four

proximal third-order sequences. (Note: In

the schematic, iv = incised valley, pw = prograding wedge, sf = slope fan, and bff =

basin-floor fan.)

Lowstand Prograding Wedges

Among the most well-represented systems

tracts in the Miocene interval are lowstand

14 GasTIPS • Winter 2003

Figure 6: Dip Cross Section of Medial Third-Order Sequence 7 (Middle Miocene), Starfak field.
prograding wedges, deltaic deposits that

accumulated during episodic lowstands of

relative sea level. Wedges are typically

sandstone-rich, more so than highstand

deltas, reflecting focused sedimentation via

the funneling of fluvial sands to the wedges

through incised-valley feeder systems during lowstand periods. Moreover, wedges are

commonly encased within outer-shelf and

slope shales and are thus prime exploration

targets. In fact, most Miocene hydrocarbon

production from the modern shelf of the

northern Gulf of Mexico originates in thirdorder lowstand systems tracts (LST) containing these prograding lowstand wedges.

Prime hydrocarbon targets exist where

fourth-order prograding wedges stack to

form third-order prograding complexes.

The upper lower and lower middle

Miocene section of offshore south-central

Louisiana records an upsection gradation

from distal to medial to proximal prograding complexes and associated third-order

lowstand facies. 

Distal Prograding Complexes

The distal third-order lowstand systems

tract (LST) comprises a basin-floor-fan

sandstone at the base; an overlying, shaledominated, slope-fan complex; and a series

of stacked fourth-order prograding wedges

at the top (prograding complex of Mitchum

et al., 1993) (Figure 4). Third-order transgressive and highstand shales probably

exist in shales overlying the LST; however,

consistent well-to-well log patterns identifying these deposits are not evident.

Benthic paleofauna record an overall

upward-shallowing succession that ranges

from basin-floor and lower and upper slope

(upper bathyal) deposits in the interval’s

bottom half to inner shelf (marginal marine

to middle neritic) facies in the upper part.

Whole cores from individual prograding

wedges contain a mix of terrestrial, estuarine, and marine palynomorphs. Prograding complexes of stacked fourth-order

prograding wedges occur as a series of

inter-stratified, upward-coarsening, progradational shale-and-sandstone units,

totaling 580 to 770 ft, each unit as much as

200 ft thick. Sandstones are very fine to

medium grained, with very fine sandstone

predominating (Dutton and Hentz, 2002).

Fourth-order prograding-wedge sandstones compose the hydrocarbon reservoirs. Thin (40 ft), typically poorly

developed retrogradational sections (transgressive systems tracts) over-lie the progradational units.

Basin-floor-fan and slope-fan facies

form 60 percent of the third-order LST.

The thick shale intervals (as much as

1,100 ft) represent outer-neritic to upper

bathyal slope-fan deposits. A thick (as

much as 250 ft) aggradational basin-floorfan sandstone that records little or no

incision marks the base of the third-order

LST. The base of another well-developed

Winter 2003 • GasTIPS 15

EXPLORATION TECHNOLOGY

Figure 7: North-South Cross Section of Starfak Field Showing Well-to-Seismic Correlation in

Two-Way Traveltime.
EXPLORATION TECHNOLOGY

basin-floor-fan sandstone 150 to 200 ft

below the third-order sequence boundary

(Texaco No. 3 well in Figure 4) may represent another third-order sequence

boundary near the distal margin of an

older fan deposit.

Medial Prograding Complexes

Several features differentiate the distal

and medial prograding complexes and

associated lowstand facies. In contrast to

the distal lowstand successions, medial

third-order LST’s contain no basin-floorfan sandstones (Figure 5). Moreover, the

medial prograding complexes (upper part

of third-order LST) contain blocky,

blocky-serrate, and, more rarely, upwardfining aggradational sandstone units as

thick as 120 ft. These units have sharp erosional bases that incise correlated marineshale marker beds and represent incisedvalley fills. Also in contrast to the distal

LST’s, the upper part of the medial thirdorder sequence contains a thin, but

definable, third-order transgressive systems tract and a well-developed thirdorder high-stand systems tract (HST). This

HST occurs as a progradational set of

stacked upward-coarsening units in the

upper part of the third-order LST. The

progradational set ranges from 400 to 500 ft

in thickness, with each unit ranging from

60 to 160 ft in thickness. These characteristics of the medial prograding complex and

associated lowstand facies record a more

landward position relative to that of the distal complex. Reservoirs are restricted to the

prograding-wedge sandstones.

Proximal Prograding

Complexes

Well logs penetrating the proximal portions of third-order complexes record

the transition from upper-slope, proximal portions of fourth-order prograding

wedges to the on-shelf portions of

fourth-order HST deposits locally

incised by valley fills that are equivalent

to the wedges (Figure 6). The third-order

TST and basal HST record a basinwide

transgressive flooding event. The lower

fourth-order HST of the third-order

HST may contain additional fourth-order

sequences. Individual wedges range from

50 to 180 ft in thick-ness. Hydrocarbons

are concentrated in prograding wedges,

incised valley fills, and highstand deltaic/

strandplain sandstones of the third-order

LST. In marked contrast to the distal and

medial LST’s, thick slope-fan shales are not

developed in the proximal third-order lowstand successions.

Stratal Slice Imaging of

Lowstand Depositional

Architecture

Stratal slicing (Zeng et al., 1995; Zeng et al.,

1998a,b), or proportional slicing (Posamentier

et al., 1996), improves seismic-surface dis16 GasTIPS • Winter 2003

Figure 8: Amplitude Stratal Slice and Well Log Expression of a Lowstand Incised Valley Fill Incising

Highstand Delta Plain Deposits.
play mainly by making slices linearly

between geologic time-equivalent seismicreference events. Geologically, a timeequivalent reference event represents a geological surface or a depositional unit that

dominates the reflection energy of the

event because it is isolated, thick, or

acoustically abnormal, and can be correlated over a large area. Marine condensed

sections associated with third-order maximum flooding surfaces and thin sandstone

sheets in relatively sand-poor sequences are

probably among the best candidates.

Common geologic time markers, for example lignites or coal, and thin limestone beds,

may also generate good reference events.

Commonly the time-equivalent seismic references are also the most continuous and

coherent events on seismic profiles, which

can be correlated easily, in many cases

even without well control. In doing

stratal slicing, it is assumed that deposition is laterally proportional in thickness

for all depositional units that are thick

enough to be detected by the seismic signal. Moreover, no unconformities (truncations) and other discordant reflections

(onlap, offlap, toplap, etc.) can occur

between the reference events, unless they

are below seismic resolution.

A stratal-slice volume was been generated among 13 middle Miocene-Plioceneage reference seismic events interpreted

from the original 3-D seismic data volume

from the study area in the northern Gulf of

Mexico shelf (Figure 7). This process resulted in the generation of 776 stratal slices in

the roughly 3.0-s data interval. The stratal

slice volume has an x, y coordinate system that is the same as that of the original

3-D seismic volume, but the z-axis in the

stratal slice volume is relative geologic

time. In Figure 7, stratal slices are numerically ordered according to increasing

geologic time (no scale). Industry designated reservoir (lithostratigraphic) units

are identified by numbers in the parentheses. Three lenticular sandstones tied to

patchy seismic events are designated by

letters A, B, and C.

This process is equivalent to stretching

or squeezing the seismic traces in time,

guided by the reference events, to form a

new 3-D seismic volume having traces of

the same data length or “thickness.” All reference events used in the process are flattened. The resulting slices are the

plan-view geomorphology of depositional

systems that are snapshots of 3-D bodies

of genetically related, high-frequency

sequences and systems tracts (Figure 8).

In the figure, note well-developed

delta-plain sandstones below the sequence

Winter 2003 • GasTIPS 17

EXPLORATION TECHNOLOGY

Figure 9. Depositional dip-oriented seismic line showing a lowstand wedge complex.
EXPLORATION TECHNOLOGY

boundary (exposure surface) equivalent

to that below the valley fills (unconformity) in wells 1 and 4.

A depositional-dip-oriented seismic

profile of a proximal prograding complex is

shown in Figure 9. Seismic units 6, 5,

and 4 correspond to

fourth-order sequences

defined in the area of well

control. However, the

seismic stratigraphy of

seismic unit 3 is more

complex; well log correlation with the seismic indicates that unit 3 comprises the basal two

fourth-order sequences

in the area of well control. Seismic units 1

and 2 were deposited

south and southeast

of well control and

represent coastally onlapping fourth-order

prograding wedges. The

third-order sequence

boundary at the base of

the prograding complex

was a major sedimentbypass surface across

which the sediments in

seismic units 1 and 2

w e r e transported.

Amplitude stratal

slices (Zeng et al., 2001)

and cross sections illustrate aspects of the areal

and internal geometry of fourth-order

pro-grading wedges (Figure 10). Well 1

captures the log expression of the shalier

portion of the wedge, whereas wells 2

and 4 exhibit the sandier accumulations within the central portion.

Well 3 probably represents fluvial deposition within an incised valley (sharpbased, blocky-serrate sandstone)

concurrent with wedge progradation,

followed by estuarine and bayhead delta

(retro-gradational middle portion and

upper pro-gradational sandstone,

respectively) deposition. Imaging of the

18 GasTIPS • Winter 2003

Figure 10: Amplitude Stratal Slice and Well Log Expression of Uppermost Fourth-Order Prograding Wedge in Sequence 9

Lowstand prograding wedges exist along 

all the Tertiary paleo-margins of the northern 

Gulf of Mexico. Within the study area, the 

lowstand prograding wedges are relatively new

prospecting opportunities; therefore, core data is

limited through these reservoir intervals. 
distal parts of most wedges is limited by

the southwestern boundary of the 3-D

seismic data volume. Relief on the firstorder growth fault just north of the

wedge probably formed the exposed

shelf edge below which relative sea level

fell during lowstand deltaic deposition.

Seismic imaging of the sandier

upper parts of the prograding complexes in distal and medial sequences

by amplitude stratal slicing shows that

fourth-order wedges are as much as

9 mi in strike width and >3 mi in the

dip dimension. Third-order prograding

complexes are only marginally wider

along depositional strike (as much as

12 mi), indicating focused lowstand

deltaic deposition within the thirdorder (1.1 m.y.) time frame. These

dimensions contrast markedly with the

much greater areal dimensions of

the highstand deltas.

Reservoir Character and

Prospectivity of Lowstand

Prograding Wedges

Lowstand prograding wedges exist along

all the Tertiary paleo-margins of the

northern Gulf of Mexico. Within the study

area, the lowstand prograding wedges are

relatively new prospecting opportunities

therefore core data is limited through

these reservoir intervals. A petrophysical

study was performed on a single core

from two fourth-order progradingwedge sandstones occuring from depths

of 14,292 to 14,910 ft in Starfak field; the

Robulus L-2 and L-5 sandstones. These

sands represent portions of a distal

third-order prograding wedge from the

Middle Miocene. Study results show

that the Robulus L-2 sandstones are

somewhat coarser grained than are the

L-5 sandstones, 3.0φ (0.13 mm) versus

3.5φ (0.09 mm), respectively. The sandWinter 2003 • GasTIPS 19

EXPLORATION TECHNOLOGY

Figure 11. (a) Isochore map of the incised-valley-to-prograding wedge transition in the 

fourth-order sequence

(b) Isochore map of the fourth-order highstand systems tract that directly underlies, 

and was partially incised by, the valley/wedge complex.
EXPLORATION TECHNOLOGY

stones have an average composition of

Q82F12R6 and are mostly subarkoses.

Average porosity in L-2 sandstones is

19.2 percent, and average permeability

is 111 md. Geometric mean permeability is 18 md. Sandstones from the L-5

interval (all samples from the L-5

[lower]) have average porosity of 18.3

percent and average permeability of 100

md (geometric mean = 13 md). Good

reservoir-quality sandstone at the top

of the Robulus L-5 (lower) and L-2

intervals is interpreted to represent proximal-delta-front/ shoreface deposits.

Muddy deposits above Robulus L-5

(lower) are inferred to compose a transgressive systems tract. However, porosity as high as 27 percent and permeability

as high as 766 md were reported. These

high porosity and permeability numbers

in lower Miocene sandstones between

14,000 and 15,000 ft in the study area

suggesting that deeper sandstones probably retain adequate reservoir quality for

economic hydrocarbon production. 

Isochore maps of incised-valley-toprograding-wedge transition in the

middle Miocene, from Starfak field

show little evidence of fault control of

the shelf break (Figure 11a and b). In

contrast deeper prograding wedges

show more structural control on their

character and possible locations. Figure

11 (a and b) show a lowstand prograding wedge formed basinward of the

depositional-shoreline break of the

underlying highstand delta platform.

There is no evidence of fault control of

the shelf break, in contrast to the structural control on deeper wedges (Figures

8 and 9). Instead, this shelf-phase lowstand delta formed basinward of the

depositional-shoreline break of the

underlying highstand delta platform.

Both the lowstand and highstand systems tracts contain productive sandstones; petrophysical and engineering

analysis suggests that sandstones of the

two systems tracts form separate reservoir compartments. Production in the

wedge (shown by the starred wells) is

limited to basinward of the onlap

point. Collectively, within this small

study area, among identified reserve

addition opportunities the Robulus “L”

sandstones contain the most gas

reserves: 41 percent of the total oil and

gas in place (421 Bcf) and 40 percent of

unrisked reserves (251 Bcf).

Lowstand Prograding Wedge

Sands Zones of Opportunity

Significant recoverable gas resources

remain undiscovered, undocumented

and unproduced in the Miocene strata of

the northern Gulf of Mexico. More than

41 percent of the known gas in the GOM

Miocene strata remain to be produced.

This four-year phase of the Secondary

Gas Recovery research program was initiated to develop new play concepts,

new processing designs and imaging

tools and identify new resource addition

opportunities that will enable small and

large companies to arrest the decline in

capital performance and extend the life

gas exploration and development on the

GOM shelf.

One of the most significant plays

remaining in the Miocene of the northern GOM is the numerous lowstand

prograding wedges that characterized

the Miocene-age depositional shelfedge locations throughout the Gulf subsurface. A variety of sub-regional reservoir sandstones pinch-out within thick,

stacked lowstand prograding wedges.

Their setting within slope and basinal

shales creates ideal conditions for

potential hydrocarbon migration and

entrapment. They are composed of distal, medial and proximal portions each

identifiable in logging cross-sections

and mappable within stratal slice (proportional sliced) images. Within our

own study area, the lowstand prograding wedge sandstones of the Robulus

“L” zone contain the most gas reserves

of any identified zones of opportunity:

41 percent of the total oil and gas in

place (421 Bcf) and 40 percent of

unrisked reserves (251 Bcf). The combination of unique stratal slice imaging

of the seismic performed within a

sequence framework of key chronostratigraphic surfaces enable geoscientists to define these resource targets and reduce both their risk and cycle

time in exploiting these reserve addition

opportunities. ✧

For more information on the status of this research

effort contact Dr. Lesli Wood at lesli.wood@

beg.utexas.edu or at 512-471-0328.

20 GasTIPS • Winter 2003

Stratal slicing, or proportional slicing, 

improves seismic-surface display 

mainly by making slices linearly 

between geologic time-equivalent 

seismic-reference events. 
Winter 2003 • GasTIPS 21

EXPLORATION TECHNOLOGY

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Louisiana (abs.),” American Association of Petroleum

Geologists Annual Convention, Official Program, v. 10,

p. A164. Also on CD-ROM.

Rassi, Claudia, 2002a, in press. “Assessment of production predictability of fourth-order systems tracts in the

Miocene offshore Louisiana,” Gulf Coast Association of

Geological Societies Transactions, v. 52.

Rassi, Claudia, 2002b, in press. “Influence of reservoir

character and architecture on hydrocarbon distribution

and production in the Miocene of Starfak and Tiger

Shoal fields, offshore Louisiana,” Ph.D. dissertation,

The University of Texas at Austin, Department of

Geological Sciences. 

Rassi, Claudia, 2002c. “Predicting reservoir performance through sequence stratigraphy—a viable

approach? (abs.),” American Association of

Petroleum Geologists Annual Convention, Official

Program, v. 11, p. A145.

Seni, S. J., T. F. Hentz, W. R. Kaiser, and E. G.

Wermund, Jr., eds., 1997. “Atlas of northern Gulf of

Mexico gas and oil reservoirs: volume 1. Miocene and

older reservoirs,” The University of Texas at Austin,

Bureau of Economic Geology, 199 p.

Van Wagoner, J. C., R. M. Mitchum, K. M. Campion,

and V. D. Rahmanian, 1990. “Siliciclastic sequence

stratigraphy in well logs, cores, and outcrops: concepts

for high-resolution correlation of time and facies,”

American Association of Petroleum Geologists Methods

in Exploration Series, No. 7, 55 p.

Zeng, Hongliu, M. M. Backus, K. T. Barrow, and

Noel Tyler, 1995. “Three-dimensional seismic modeling and seismic facies imaging,” Gulf Coast

Association of Geological Societies Transactions, v.

45, p. 621–628.

Zeng, Hongliu, M. M. Backus, K. T. Barrow, and

Noel Tyler, 1998a. “Stratal slicing, part I: realistic 3-D

seismic model,” Geophysics, v. 63, no. 2, p. 502–513.

Zeng, Hongliu, S. C. Henry, and J. P. Riola, 1998b.

“Stratal slicing, part II: real seismic data,” Geophysics,

v. 63, no. 2, p. 514–522.

Zeng, Hongliu, T. F., Hentz, and L. J. Wood,

2000a. “Three-dimensional seismic facies imaging

by stratal slicing of Miocene-Pleistocene sediments in

the greater Vermilion Block 50-Tiger Shoal field

area, offshore Louisiana (abs.),” American Association of Petroleum Geologists Annual Convention,

Official Program, v. 9, p. A165.

Zeng, Hongliu, 2001. “From seismic stratigraphy to

seismic sedimentology: a sensible transition,” Gulf Coast

Association of Geological Societies Transactions, v. 51,

p. 413–420.

Zeng, Hongliu, T. F. Hentz, and L. J. Wood, 2001a.

“Stratal slicing of Miocene-Pliocene sediments in

Vermilion Block 50-Tiger Shoal area, offshore

Louisiana,” The Leading Edge, v. 20, p. 408–418.

Zeng, Hongliu, T. F. Hentz, and L. J. Wood, 2001b.

“3-D seismic expression of high-frequency sequence

stratigraphy in Vermilion Block 50-Tiger Shoal area,

offshore Louisiana (abs.),” American Association of

Petroleum Geologists Annual Convention, Official

Program, v. 10, p. A224-A225.

Zeng, Hongliu, and L. J. Wood, 2002. “Using quantitative seismic sedimentology to predict reservoir architecture and lithology: a Gulf Coast Miocene-Pliocene

example (abs.),” American Association of Petroleum

Geologists Annual Convention, Official Program, v. 11,

p. A197.
WELL COMPLETIONS

Achronic problem for the oil

and gas industry is failure to

achieve reservoir isolation as

a result of poor primary cement jobs, particularly in gas wells. A new technology

designed to address this problem, cement

pulsation (CP), has proven technically and

economically successful in Canada. CP

technology has demonstrated excellent

results in preventing early gas leaks in over

150 cemented wells. The basic approach of

this technology is to improve reservoir isolation by mitigating fluid migration during

the cement setting process. 

Primary Cementing 

Failures Costly

Approximately 15% of all primary cement

jobs fail, costing the oil and gas industry an

estimated $470 million annually (Newman,

et al., 2001). One-third of these failures are

attributed to fluid influx into the cementfilled annulus that results in channeling and

subsequent communication. Fixing this

problem is challenging for several reasons:

channels are difficult to locate and often too

small to easily fill, and remedial squeeze

treatment are expensive and treating pressures may breakdown the formation. The

best solution to the problem is the prevention of fluid migration in the initial (primary)

cement job.

Studies have shown that in the Gulf of

Mexico there are more than 11,000 strings

of casing in over 8,000 wells that exhibit

sustained casing pressure (SCP) (Bourgoyne,

et al., 1998). SCP is defined as a build up of

pressure on any string

of casing that can not

be attributed to an

applied pressure or

temperature fluctuation. SCP is an indication of communication between a reservoir and the surface.

SCP can be the result

of tubing or casing

leaks, cement damage

after setting or what

is more likely, a poor

primary cement job.

The problem can lead to tubular failures,

and at the extreme, an underground or

surface blowout.

Defining the Problem

With fluid migration, the fluids invading

the cement matrix can be either gas or liquid. Fluid migration in primary cement jobs

can be attributed to four general factors.

First, with a pressure differential across the

curing cement, fluid can leak from the

cement into the formation causing a volume reduction. Second, during the hydration process, the volume of the slurry contracts up to 6%, allowing micro-annuli to

form along the casing and formation surfaces. Third, the unset cement is very

permeable until it develops sufficient

strength to prevent fluid influx. And

fourth, the development of gel strength in

cement slurries causes a lowering of the

hydrostatic pressure in the annulus that

can lead to influx. 

The combination of volume losses due

to fluid loss and hydration, loss of hydrostatic pressure because of gel strength and a

weak, permeable cement matrix provides a

perfect environment for fluid influx to take

place. If this occurs, bonds between the formation and casing can be destroyed. If

there is sufficient pressure and if the invading fluid volume is great, channels can

become quite large and ultimately lead to

fluid communication. 

Attempted Solutions

To increase the chances of a successful

cement job and provide good bonding

between the formation and casing, the

annular space must be completely filled

with cement and drilling fluids must be

completely displaced by the cement slurry.

Cement properties must be controlled to

minimize fluid-loss, free fluid and gel

22 GasTIPS • Winter 2003

by David Stein, 

RITS 

Tom J. Griffin, Jr., 

Griffin Cement Consulting, LLC 

Dale Dusterhoft, 

Trican Oilwell Service Company Ltd.

Cement Pulsation Reduces

Remedial Cementing Costs

A simple new technique to improve primary cement jobs has resulted in a

36 percent decrease in average remedial cementing costs for a group of

Canadian gas wells.

Figure 1: Compressible Volume Response
strengths, in order to help to lower the risk

of a poor cement job. Additional techniques are used to attempt to prevent fluid

migration, but no universal solution exists.

Techniques include carefully controlling

cement properties and the use of casing

hardware to isolate the producing zone.

Many of these solutions are costly and

complicated to implement.

Cement Pulsation

Cement pulsation is the application of lowintensity pressure pulses to the annulus

after a primary cement job to delay gel

strength development in the cement slurry.

Gel strength of the cement causes a lowering of the hydrostatic pressure transmitted

through the annulus (Newman, et al., 2001).

By delaying gel strength development, the

hydrostatic pressure on the formation is

maintained until the cement has built sufficient strength to prevent the influx and

migration of reservoir fluids through the

cement matrix.

The pulsation process starts immediately after pumping stops and the annular BOP is closed. Low-pressure pulses,

typically in the range of 80 to 200 psi, are

applied to the casing annulus at a time

interval of 30 to 60 seconds. Pulsing continues until the compressible volume

levels-off or the thickening time test indicates the cement has reached 70 Bc, usually 4 to 6 hours (Figure 1). The compressible volume is the volume of fluid

required to pressurize the annulus when

the pulse is applied.

The cement pulsation system employs

an air compressor to continuously pressurize an air tank on the unit. To pressurize

the annulus, a controller opens a value

between the air and water tanks (Figure 2).

Air pressure forces water into the casing

annulus and pressurizes it for a specific

time. After pressurization, the control system releases the pressure by closing the

pressurizing valve and opening an exhaust

valve. Water returns from the casing annulus back into the water tank, de-pressuring

the casing annulus. As the cement sets, the

compressible volume decreases, giving a

real-time indication of the setting process.

History of CP

In the early 1990’s, John Haberman at

Texaco E&P proposed the application of

pressure pulses to the casing annulus after

a primary cement job to control fluid

influx and migration. GTI and Texaco E&P

Technology Company collaborated in the

development of a simple procedure to

achieve these goals. In a recent effort to

extend this technology, CTES L.C.

developed the system and collected

downhole annulus pressure data during

the pulsation procedure. Concurrently,

efforts to model a well’s response to

cement pulsation were undertaken by

researchers at Louisiana State University

(Chimmalgi, 2001).

The goal has been to gain a better quantitative understanding of how successful

the procedure is in maintaining the pressure

throughout the column and also to develop

tools for modifying the procedure to suit

specific conditions. After verifying that the

pressure pulse did transmit completely

through the cement column, a field trial

was conducted on a group of Canadian

wells (Dusterhoft, et al., 2002).

Canadian Results Impressive

Cement pulsation was applied during

2000-2002 in areas of Alberta and

Saskatchewan that historically have had

problems with gas migration. Typically,

these wells are vertical with a depth

ranging between 1900 to 5900 feet. On

average, 57% of these wells develop

leaks after the primary cement job.

Canadian regulations mandate that any

Winter 2003 • GasTIPS 23

WELL COMPLETIONS

Figure 2: Cement Pulsation Layout
WELL COMPLETIONS

well with casing pressure problems must

be fixed before abandoning. Repairing

the leaks can cost anywhere from

$30,000 to $50,000. If the problem is

related to poor zone isolation, remediation costs can become significant.

Cement pulsation was applied on over

150 shallow gas wells in Alberta and

Saskatchewan. A comparison of the total

number of wells pulsed, the expected

number of leaking wells without pulsing

(based on historical data) and the actual

number of leaking wells after pulsing is

shown for the top 11 fields, which

account for 88% of the total (Figure 3).

Overall, with the use of CP the percentage

of leaking wells declined from 57% to

only 21% and the cost of performing

remedial cement squeezes

related to leaks was

reduced from 59% to

43% of average total

cementing cost (Figure 4).

This results in an overall

average cementing cost

(primary plus remedial)

reduction of 35%.

Based on these

results, cement pulsation appears to provide

a simple and cost effective solution for controlling fluid migration in

gas wells. However, it is

still mandatory to maintain good cementing

practices to ensure the

overall success of the primary cement job. The

work in Canada is still continuing and

now the service is available in US. ✧

For more information on cement pulsation contact David Stein, RITS Manager, at

936-521-2212; E-mail: david.stein@rits.cc (or

see www.rits.cc).

References

Newman, K., Wojtanowicz, A., Gahan, B., 2001.

“Cement Pulsation Improves Gas Well Cementing,”

World Oil, July 2001, pages 89-94.

Bourgoyne, A. Jr, Scott, S. L., 1998. “A Review of

Sustained Casing Pressure Occurring on the OCS.”

Chimmalgi, V.S., “Design of Top Cement Pulsation

to Prevent Gas Migration During Cementing,” MS

Thesis, Louisiana State University, Baton Rouge,

Louisiana, May 2001

Dusterhoft, D., Wilson, G., Newman, K., 2002.

“Field Study on the Use of Cement Pulsation to

Control Gas Migration,” SPE paper 75689

24 GasTIPS • Winter 2003

Figure 3: Summary of the Top 11 Fields Pulsed in Canada

Figure 4: Improvement in Number of Leaking Wells
Winter 2003 • GasTIPS 25

RESOURCE CHARACTERIZATION

Aconsensus of virtually all

experts in the field agrees that

the annual demand for natural gas in the United States will grow to

more than 30 trillion cubic feet (TCF) by

2020. Considering the persistent annual

shortfalls of reserve replacement, significant

new natural gas reserves must be discovered and brought on line if this demand

is to be met. This situation demands serious attention to unconventional natural gas

resources, production of which has been

hampered historically by both technical

and economic hurdles. Of all unconventional natural gas resources, methane

hydrate represents the largest in-place accumulation, and therefore, holds the promise

of playing a role in meeting U.S. energy

demand in the future. The mean average

of the U.S. in-place hydrate resource is

320,000 TCF. If only one per cent of this

resource producible, the reserve would be

enough to meet the entire U.S. gas

demand for 100 years. Accordingly, attention to methane hydrate as a potential

energy resource for the United States is

imperative. 

Methane hydrate is formed through the

entrapment of hydrocarbon molecules

inside cages of ice crystals. Such crystals

can contain amounts of methane up to 170

times their volume. That is, one cubic foot

of hydrate can contain up to 170 standard

cubic feet of gas. Considering their global

abundance, methane hydrate has the

potential to meet the world’s energy

demand for many decades if not centuries. 

Another interesting characteristic of gas

hydrate is in that,

under moderately high

pressure, the material is

stable at temperatures

several degrees above

the freezing temperature of water. As a

result, the occurrence

of natural gas hydrate

is not limited to cold

regions such as Alaska

and northern Canada.

It is also present at

or near the sea floor in

deeper portions of the

Gulf of Mexico, offshore North Carolina, and

many other locations. However, it must be

emphasized that estimates of in-place

resource should not be mistaken for producible reserve. In fact, it is currently impossible to predict what portion of this resource

can be safely and economically produced. 

The potential of this resource has

moved work on identification and characterization of methane hydrate to the forefront of energy supply research and development. Specifically, the increased attention and financial support of the U.S.

Department of Energy’s National Energy

Technology Laboratory (DOE-NETL) has

played a decisive role in the creation of several joint industry projects involving the

participation of the U.S. Geological Survey

(USGS), universities, and several major gas

production and E&P service companies.

Research on natural gas hydrates is by

no means new. DOE has been funding

work on this concept for many years, and

several USGS laboratories have been

working on various aspects of hydrate

characterization as an energy resource. In

parallel with these efforts, several major

universities have been evaluating the

physical chemistry and petrophysical

properties of methane hydrate. Nearly all

these efforts have been noticeably accelerated during the last few years. 

Hydrate Resource

Characterization 

Research at GTI

At the Gas Technology Institute (GTI),

research programs on hydrate have been

designed with an awareness of all other ongoing research, to ensure that GTI efforts

will augment, not duplicate, the work of

other R&D organizations. 

In general terms, the principal objectives

of work at GTI’s Hydrate Resource Characterization Laboratory (HRCL) have been to

develop data and information needed for

by Iraj Salehi, GTI Hydrate Gas Technology Institute

Characterization Research

New Gas Technology Institute facility provides tools for understanding 

the dynamic behavior of gas hydrate.

Figure 1: Conceptual Design of GTI’s HRCL Pressure Vessel
RESOURCE CHARACTERIZATION

(a) precise seismic identification and

delineation of hydrate-saturated sediments

and (b) determination of the effects of rock

properties on the rate of dissociation of

hydrate in a variety of rocks with different lithologic and flow properties. This

work involves laboratory determination

of seismic (elastic) properties of

hydrate-impregnated sediments of different

compositions, porosities, and permeabilities, under controlled pressure and

temperature conditions that replicate in situ

conditions. Results

from this laboratory

work will provide a

set of reliable data for

seismic modeling and

interpretation as well

as log analyses. A

second category of

laboratory measurements includes ultrasonic monitoring of

hydrate dissociation

rates in specimens

with differing porosity, permeability, and

saturation, as a means for predicting gas

production rate.

The economics of gas production from

methane hydrate accumulations hinge

upon production rate and ultimate

recovery, both of which vary as a function

of dissociation rate and depend on the

behavior of the reservoir unit as a whole.

Currently, neither the flow mechanisms

within hydrate “reservoirs,” nor the

dynamic changes that may result from the

hydrate dissociation process are clearly

understood. In fact, it is likely that severe

sediment deformation and seafloor

instability may result from the dissociation

of hydrate in rocks that form ideal

reservoirs for conventional hydrocarbon

production (e.g., 30% porosity, coarse grain

unconsolidated sands). Such damage could

render production from these formations

unsafe and impractical. It is therefore conceivable that more competent rocks with

low to moderate porosity and permeability—but with high hydrate saturation—

may constitute the reservoir condition

most amenable to production of the

trapped gas. The dissociation rate (as a

function of pressure decrease, or temperature increase) is the key factor controlling

production from such formations. For this

reason, accurate determination of the dissociation mode and rate within a host formation is crucial to the identification of

promising host formations and estimation of expected production from

these formations. 

Laboratory Measurements

Laboratory measurements at HRCL

evaluate the elastic properties of hydratebearing sediments and map the propagation of the dissociation front resulting from

depressurization or temperature change.

Design of the laboratory has been based on

the well-established fact that the presence

of free gas in the pore space of sedimentary

rocks reduces their compressional wave

velocity significantly. Therefore, a reaction

cell containing arrays of shear and compressional sources and receivers (Figure 1)

enables researchers to measure the velocity

of the front through the medium during

synthesis/dissociation cycles. In addition, if

the dissociation takes place along a

progressing front (e.g., through activation

of a heat source at one end of the reaction

cell) it is possible to map the progress of

the front in real time. Thus, careful

experiments can determine the compressional and shear velocity of the specimen

26 GasTIPS • Winter 2003

Figure 2: Schematic Diagram of the HRCL Experiment Station

Figure 3: Instrumented Sample Sleeve Held

Above the Cell Body

Figure 4: Assembled Reaction Cell Placed Inside

Temperature-Controlled Chamber
for use in seismic and log

analyses and determination of

dissociation rate for reservoir

simulations. Finally, by performing these experiments on

samples with different properties, researchers can develop

baseline data needed for all geophysical and reservoir engineering studies. GTI’s HRCL

was designed and assembled to

permit just these kinds of experimental operations. 

Central to the HRCL is an

instrumented reaction cell that

houses an array of six compressional and six shear wave source and

receiver pairs. Pressure and temperature are

computer controlled in ranges from 220 to

350°K (-63.7 to 170° F) and 0 to 35 MPa

(0-5076 psi). The unit also incorporates

pressure and temperature transducers, volume and rate measurement devices, and

automated data acquisition system (Figures

2, 3, and 4). 

Concurrent recording of pressure,

temperature, and time allow characterization of the anticipated dissociationreconsolidation cycles. In the case of loosely packed unconsolidated sands held

together by the hydrate matrix, severe

attenuation or the absence of shear wave

signals clearly indicate the onset of the dissociation process. 

Progress to Date

Design, construction, assembly, and

testing of GTI’s HRCL were completed in

the summer of 2002. Experimental results

to date clearly have been in line with

expectations derived from theoretical

studies. In addition to determining the

elastic properties of hydrate-bearing sand

packs, researchers also have been able to

monitor the progress of dissociation fronts

in a few laboratory-synthesized samples.

One example of recorded data shows the

change in travel-time (velocity) as a sample

undergoes dissociation (Figure 5). In particular, signal deterioration during the phase

change period contributes to quantification of the observations. Comparison

of the dissociation of a pure methane

hydrate sample and the dissociation of a

hydrate sample created in the pore space

of a batch of 60/80 sand provides an indication of the effects of rock properties on

dissociation and production rates

(Figures 6 and 7).

As research continues at the

HRCL, a reasonably complete

database covering an acceptable range of parameters will be

developed. This database will

be of great assistance to the

research and operations community involved in data

analysis and modeling. ✧

For more information on the ongoing

research at GTI’s HRCL, contact

Iraj Salehi, at 847-768-0902,

or via e-mail at iraj.salehi@

gastechnology.org.

Winter 2003 • GasTIPS 27

RESOURCE CHARACTERIZATION

Figure 5: Monitoring of Dissociation Process in Real-Time 

Figure 7: Dissociation of Hydrate in Medium Porosity/

Figure 6: Dissociation of Pure Hydrate Permeability Sand at 10% Hydrate Saturation
GAS PROCESSING

28 GasTIPS • Winter 2003

Anew solvent process for

treating sour gas, developed by Uhde GmbH and

Gas Technology Institute (GTI), has been

demonstrated for the first time on a commercial scale in Duke Energy Gas

Transmission’s (DEGT), Kwoen Gas Plant in

Northeastern British Columbia. The

Morphysorb®process was shown to be a

cost effective and environmentally beneficial method for de-bottlenecking the

DEGT Pine River processing system. 

Instead of recovering sulfur, the plant is

designed to inject over 30 MMscfd of

extracted acid gas (primarily H2S and CO2)

into depleted gas reservoirs, simultaneously minimizing sulfur and carbon dioxide emissions and saving gas producers significant sulfur marketing costs. The process

exceeded all performance targets set by

DEGT, which were substantially above

expectations for alternative solvents.

Background

The Kwoen Gas Plant is a new addition

to the Pine River gathering and processing system operated by DEGT in British

Columbia (Figure 1). The system includes the Pine River gas plant, with

three identical processing trains that

include Shell Sulfinol-D gas treating

units, triethylene glycol dehydration and

MCRC sulfur recovery units. The plant’s

capacity is 560 MMscfd sour gas,

94 MMscfd acid gas and 2000 LT/day

sulfur production with a design plant

feed containing 16.8 % total acid gas,

9.3% H2S and 7.5 % CO2.

The sour gas feed sources to the Pine

River system range from 5% to 40% acid

gas. Producers dehydrate their gas prior to

its entering the system, typically via molecular sieve adsorption. Natural gas liquid

(NGL) content of the gas is extremely low

(about 1.4 bbl/MMscf), and NGL recovery

is not required. The plant feed contains a

significant amount of sulfur, with carbonyl

sulfide (COS) and mercaptan content in

excess of 300 ppm. The Sulfinol-D system is

designed to achieve a sales gas specification

of less than 16 ppm total sulfur. Although

the raw feed volume to the Pine River

plant was less than capacity, the plant was

fully utilized due to a higher-than-design

acid gas quantity in the feed gas (21.0%

versus 16.8%). In addition, new sources

of sour gas in excess of 130 MMscfd

by Glenn Kowalsky, 

Duke Energy Gas Transmission 

Dennis Leppin, Raj Palla 

and Dr. Aqil Jamal, 

Gas Technology Institute 

H. M. Hooper, 

Uhde Corporation of America

Morphysorb®Applied to 

De-Bottlenecking of 

Gas Treating System

New solvent exceeds performance targets during test at Canadian sour gas treating facility.

(Article excerpted from paper presented at the 2003 Laurance Reid Gas Conditioning Conference, February 23-26, 2003)

Figure 1: Conceptual Design of GTI’s HRCL Pressure Vessel
flow capacity were in need of transportation and processing service.

System Expansion Alternatives

In order to process additional sour gas,

DEGT was faced with the decision of

either adding more treating and sulfur

conversion capacity at the Pine River

plant or installing additional processing

capacity elsewhere in the system. Two

alternatives were considered: the addition

of a fourth 130 MMscfd train at the Pine

River plant, or the installation of a

300 MMscfd sour gas upgrader (the Kwoen

Gas Plant). The Kwoen Plant option was

chosen due to significant economic

advantages.

For example, the capital cost for the

Kwoen Plant was $94 MM CND versus

$258 MM CND for a new processing

train at the Pine River Plant. As a ratio

of capital cost over treated sour gas

volume, the Kwoen Plant was installed

at $0.8 MM/MMscfd versus $2.0

MM/MMscfd for a new processing train.

In addition, the Kwoen Plant design is

expected to yield 3.0 MMscfd more sales

gas than a traditional gas treating/

sulfur recovery design.

No fuel is required

to run compressor

engines, large power

generators or large

heat medium systems.

Partially offsetting

these advantages are

slightly higher operating costs due to purchased power requirements.

The plant is

designed to dispose of

over 860 LT of sulfur

as H2S every day through injection of liquefied acid gas into a depleted gas reservoir.

Sulfur disposal by injection will result in a

cost savings for producers since the netback

price for sulfur in the Pine River region is

currently negative and the price is forecast

to stay quite low for the foreseeable future.

At an elemental sulfur netback price of

minus $10/LT, the Pine River producers

can expect to save over $3 MM CND/yr.

In addition, the Kwoen Plant is designed

to produce significantly less emissions than

a new gas processing/sulfur recovery train.

The upgrader design is predicted to have

5,250 LT/yr less SO2 emissions and

105 LT/day less NOx emissions. Re-injection

of extracted CO2 equates to an emissions

reduction of 176,000 LT/day as compared

to a new train. This advantage is quite timely given Canada’s recent ratification of the

Kyoto Accord.

Kwoen Plant Design

The Kwoen Plant, located 18 miles upstream from the Pine River Plant, is sized to

remove and inject 28 MMscfd acid gas into

depleted reservoirs and to permit an additional 130 MMscfd gas to flow into the

Duke gathering system and the Pine

River Plant. In addition to the plant, a

new 9,500 hp centrifugal sour compressor

was also installed upstream of the processing unit to hydraulically de-bottleneck the

sour gas gathering system.

The Kwoen Plant is the first full-scale

application of the new, patented gas treating

solvent Morphysorb®. Co-developed by

Winter 2003 • GasTIPS 29

GAS PROCESSING

Table 1: Predicted Performance of Morphysorb Solution at Kwoen Gas Plant

Stream Sour Feed Gas Upgraded Acid Gas Acid Gas

Flow, MMscfd 300 266 34

Pressure, psia 1085 1074 1015

Temperature, oF 63 55 120

mol%

CO2 8.60 7.21 19.60

H2S 13.54 5.33 78.71

CH4 77.26 86.81 1.47

C2H6 0.21 0.23 0.09

C3H8 0.02 0.02 0.02

COS 0.02 0.02 0.05

CH4S 0.01 0.00 0.04

N2 0.34 0.38 0.00

H20 0.01 0.00 0.04

Figure 2: A simplified flow diagram for Morphysorb® process.
GAS PROCESSING

Gas Technology Institute (GTI) and Uhde

GmbH (KU), Morphysorb is a physical solvent that consists of a mixture of NFormylmorpholine (NFM) and N- Acetylmorpholine. The solvent was extensively

tested in bench-scale and pilot plant facilities through the early and mid-1990s and is

now available for commercial application

(Palla, et al., 1998; Gross et al., 1999).

Morphysorb was selected for the

Kwoen Plant based on KU’s prediction

of lower hydrocarbon losses to acid gas,

larger capacity for acid gas removal, and

lower pumping and recycle horsepower

requirements. 

The benefits of Morphysorb were

expected to be partially offset by higher solvent losses than could be expected with

other physical solvents. However, actual

Morphysorb losses measured by a variety

of techniques were in line with losses

expected with alternate solvents. This situation is being monitored and a more accurate value for the losses will be determined

after a year of operation.

Like other physical solvents used for gas

treating, Morphysorb has a strong selectivity for removing H2S over CO2. Despite

the addition of 740 LT/day of additional

feed sulfur in the volume of sour gas undergoing processing, the selective nature of

Morphysorb actually reduced the sulfur

plant feed to the Pine River plant, from a preexpansion rate of 2000 LT/day to 1900

LT/day. At design flow rates, the Kwoen

Plant will be reducing the H2S/CO2 ratio of

the Pine River Plant feed from 1.3 to 1.1.

Kwoen Plant 

Process Description

The Kwoen Plant is a simple flash regeneration design (Figure 2). A total of 300

MMscfd of sour gas is directed to the plant,

which operates at 1100 psia. The gas is

absorbed by a Morphysorb solution in two

parallel 150 MMscfd packed column

absorbers. The lean Morphysorb flow rate

to each absorber is below the maximum

plant capacity of 1500 USgpm. Rich

Morphysorb leaves the bottom of the

absorbers loaded with extracted H2S and

CO2. The rich Morphysorb is consecutively flashed at 425 psia and 185 psia. The

off gas from these drums is recycled to the

absorber feed via a 1750 hp 2-stage reciprocating compressor. The recycle operation

is necessary in order to minimize methane

losses. However, these losses are so low

with Morphysorb that consideration can

be given to recycling only the first flash if

more acid gas rejection is desired. The final

two flash drums yield the gas feed to the

acid gas compressors as well as producing

30 GasTIPS • Winter 2003

Figure 3: The Kwoen plant was completed in August 2002.
a regenerated (lean) Morphysorb stream.

The acid gas flash drums operate at 65 psia

and 25 psia, respectively. The lean

Morphysorb flows from the final flash

drum back to the absorbers via booster and

high-pressure pumps. The plant also contains a mechanical and carbon filtration

system. The filtration flow rate is 9% of the

total Morphysorb circulation.

The Morphysorb solvent is designed to

remove 33 MMscfd of acid gas from the

sour gas feed (actual conditions in the plant

indicate over 40 MMscfd is possible),

resulting in an upgrade from 22.1% acid

gas to 12.5% (Table 1). The design acid gas

quality is 78.7% H2S, 19.6% CO2 and

1.7% hydrocarbon and trace sulfur. Thirty

percent of the inlet trace sulfur is removed

by the Morphysorb solution.

Flash regeneration and auto refrigeration of the Morphysorb eliminates the

need for a number of traditional gas

treating unit operations (e.g., all of the

equipment attached to an amine plant

regenerator system such as the still,

reboiler, process heat medium system,

overhead condenser, etc.). In addition,

the plant has no requirement for a

residue gas dehydration system.

The lack of process heating requirements and a third party power supply for

the large process and compression load

keep fuel consumption low. The flash

regeneration design of the Kwoen plant

requires no process heat input. Plant heating is only required to keep the plant

process piping, vessels and tanks warm

during the winter when the ambient temperature can reach –40 ̊F. The total design

running power load of the inlet compressor

and plant is 22,000 hp. This load is entirely

supplied by the local power generator and

distributor.

In order to maintain a high level of

reliability, the plant was designed with a

significant amount of sparing for rotating

equipment. The plant has three 50%

capacity acid gas compression units, two

100% recycle compressors and 100%

sparing for the Morphysorb booster and

high-pressure pumps. 

Acid Gas Handling 

and Disposal

The acid gas that flows from the final

flash drum is compressed in the first stage

of three 4000-hp reciprocating four-stage

acid gas compressors. This compressed

stream is combined with 16.6 MMscfd of

65 psia flash gas and compressed to a

final discharge pressure of 1100 psia. The

compressor aftercooler liquefies the acid

gas prior to its entering a nine-mile,

6-inch-diameter pipeline. The liquefied

acid gas arrives at the injection well as a

liquid and flows down the tubing to a

depth of 8200+ feet. The depleted reservoir will be filled with acid gas to a pressure less than 80% of the hydrostatic

head of the tubing, at a sandface pressure

less than fracture pressure. Even at this

reduced volume, the estimated storage

capacity is over 200 Bcf, which should

provide for thirty years at projected rates. 

Plant Performance Testing

Construction of the Kwoen plant was

completed in early August 2002 (Figure

3). Morphysorb solvent was loaded to

the process train and brought up to operating pressure with sweet gas in the system. Initial testing with sour gas in a

single column running well below

capacity began in early September, utilizing 90 MMscfd of gas available at that

time. Operations at this level were continued while various mechanical issues

involving compression equipment and

solids deposition ahead of the injection

well were resolved.

At the end of October 2002, plans for an

acceptance test were made. Originally

anticipated to be full flow in both contactors, the test was constrained to one

contactor with a feed of ~150 MMscfd

due to availability of gas and the presence

of downstream bottlenecks. The test was

designed to demonstrate that the

Morphysorb process is capable of

achieving required performance on several

metrics: recycle gas flow rate, methane

losses to injection well stream, solvent

Winter 2003 • GasTIPS 31

GAS PROCESSING

Table 2: Methane Loss and Mass Balance Performance

Test Period Feed Gas Flow Acid Gas Flow Recycle Gas Flow CH4 Losses in Acid Gas Stream Overall Mass Balance Overall Mass Balance 

(MMScfd) (MMScfd) (MMscfd) (mole%) (Based on GTI Analysis) (Based on Duke’s Analyzers)

1 (30 hrs) * 138.1 21.18 9.9 1.2 107.37 108.76

2 (24 hrs)** 146.8 22.35 11.0 1.0 105.99 106.35

* Period 1 Conditions

Feed Gas: 1076.8 psig, 60.9oF

Acid Gas Composition in Feed Gas: 15.3 mole% H2S, 11.8% CO2

** Period 2 Conditions

Feed Gas: 1084.9 psig, 51.4 oF

Acid Gas Composition in Feed Gas: 14.8 mole% H2S, 12.6% CO2
GAS PROCESSING

loss, specific circulation rate, total acid gas

removal, and operability. GTI had responsibility for collecting and analyzing gas and

liquid samples and developing a performance report, funded in part by the U.S.

Dept. of Energy’s National Energy Technology Laboratory (NETL). DEGT observed

the testing and sample analysis and

reviewed the results. A total test run of

53 hours was achieved. 

A total number of seven gas sampling

points and two liquid sampling points were

used for sample collection during the performance test. GTI established a temporary laboratory at the site to analyze the gas and liquid samples collected during the performance test. In addition, Duke had its own

independent online analyzers for measuring:

CO2 and H2S in feed and product; and

CO2, H2S and CH4 in acid gas streams.

All the gas and liquid samples collected

during the test period (November 12 to

November 15) were analyzed immediately

(Figure 4). The plant performance was consistent throughout this period, with some

plant down-time discontinuities due to

compressor and mechanical problems.

The liquid circulation rate was set at a

fixed value below the maximum value

possible in the plant with current hardware. The testing resulted in two useful

“steady state” periods (which differ in

conditions significantly) for the purpose

of computation of the adjusted performance specification metric values and

analysis of results (Table 2). 

In all cases the metrics satisfied the criteria established by Duke Energy.

Measured solvent losses on product gas

samples collected during the performance

test were well within expected levels. Two

different techniques were used to

accurately measure solvent losses: UV

absorption spectroscopy and GC FID

analysis. Analysis of the samples indicated

a solvent concentration of 3.1 to 4.0 ppmv,

well below the expected maximum

limit of 8 ppmv.

No foaming incidents or upsets

occurred prior to, during, or after the

performance test. (As of this writing

the plant has been in operation in

excess of four months, and approximately 8 Bcf of raw gas have been

processed.) This is interpreted as a positive indication of the solvent’s low

propensity for foaming, a problem

often exacerbated in the early stages of

plant operations by the presence of

foreign contaminants in the system.

Operations personnel reported that the

Morphysorb unit was stable and

required no special attention once it

reached a steady state condition.

Application Potential

Sour gas upgrading with Morphysorb

shows great promise as a process for de-bottlenecking existing gas plants in situations

where feed acid gas content climbs above

the optimum host plant design. Preferentially, the feed gas should be hydrocarbon

dry in order to reduce the impact of losing

heavier hydrocarbons to the gas treating solvent. Additionally, acid gas injection can

help to maintain capital costs and emissions

lower than is possible with other sulfur

recovery technology alternatives, provided

that suitable reservoirs are accessible. ✧

For more information on the application of

Morphysorb to gas treating problems, contact

Dennis Leppin, Associate Director, GTI Gas

Processing Program. Phone 847-768-0521;

E-mail: dennis.leppin@gastechnology.org/.

References

Palla, N., Lee, A.L., Gross, Dr. M, Hooper, H. M.,

Menzel, J. and Leppin, D., 1998. “Advancements

in Treating Subquality Natural Gas Using NFormyl Morpholine,” Proceedings of the 77th GPA

Annual Convention.

Gross, M., et al. , 1999. “A New Solvent Process

for Acid Gas Removal and its Impact on BTEX

Emissions,” Proceedings of the 49th Laurance Reid

Gas Conditioning Conference, February.

32 GasTIPS • Winter 2003

Figure 4: All the gas and liquid samples collected during the test period (November 12 to November 15)

were analyzed immediately.
Winter 2003 • GasTIPS 33

GAS STORAGE

Changes in natural gas market

and regulatory environments have created a significant demand for large capacity storage

facilities with flexible gas storage capability.

Some of the recent demand for natural gas

is being addressed through the planning

and development of solution-mined

storage caverns in Gulf Coast salt domes in

Alabama, Mississippi, Louisiana, and Texas

and bedded salt formations in Arizona,

New York, and Wyoming. The major

advantage of storing natural gas in salt caverns is immediate availability during peak

demand. A disadvantage is the high cost of

facility construction compared to conventional porous rock storage.

To improve the economics of storing

natural gas in salt caverns and increase the

total storage capacity of natural gas in the

United States, the Department of Energy’s

National Energy Technology Laboratory

sponsored research performed by RESPEC

aimed at pushing the technical limits and

improving the performance of compressed

natural gas (CNG) storage in salt caverns.

An important aspect of the project was

addressing the ability to accurately

characterize the behavior of salt under

changing pressure conditions. This necessitated use of an appropriate constitutive

model and numerical techniques to predict

the creep and brittle response of salt under

the loading conditions expected in the salt

during gas storage operation. Using such a

model, researchers were able to determine

that minimum gas pressures could be lowered in the caverns studied, increasing

working gas capacities up to 20 percent

with zero increase in cavern size.

Cavern Storage and 

Salt Behavior

Product movement to and from CNG

storage caverns is accomplished simply

by compression and expansion of the

stored gas. Consequently, the internal

pressure on the walls of a CNG storage

cavern can vary considerably. Because a

minimum level of internal pressure is necessary to ensure cavern stability, a certain

quantity of gas (cushion gas) must always

remain in a cavern.

The economics of CNG storage in salt

caverns are largely dependent on maximizing the ratio between the working gas and

the cushion gas volumes. This ratio

depends directly on the relative values of

the maximum and minimum gas pressures

permitted in the storage cavern. The maximum storage pressure is limited by regulation to a fraction of the weight of the overburden (typically 0.75 to 0.85 of the vertical

stress) to prevent loss of containment by

hydraulic fracturing of the salt and/or

cemented well casing. Determination of

the minimum pressure required to ensure the

structural stability of the cavern is much

more difficult and has often been based on

conservative assumptions because accurate

modeling techniques and material properties for the salt are unavailable.

The important characteristics of salt

response for natural gas storage cavern

development are creep and dilation (microfracturing resulting in increased porosity).

A constraint that often limits the minimum

gas pressure in a CNG storage cavern is the

potential for salt dilation that can lead to

spalling in the cavern roof and/or walls and

subsequent damage to the cavern or hanging casing string(s). Depending on the

stress and strain conditions, salt may or

may not dilate as it deforms.

Figure 1 illustrates two deformed salt

core specimens. Both specimens experienced creep deformation at the same stress

difference (difference between the axial

stress and the confining pressure) but were

subjected to different axial stresses and

confining pressures. The specimen on the

left (high confining pressure) did not dilate

and the specimen on the right (low confining pressure) not only dilated but the

microfracturing progressed to a state that

resulted in failure of the salt as evidenced

by the crumbling of the specimen. The

key to optimizing cavern performance is

by Kerry L. DeVries, Improved Modeling Increases RESPEC

Salt Cavern Storage Working Gas

An improved model for gas storage caverns has revealed the potential for safely increasing storage 

capacity by accurately characterizing the plastic behavior of salt. 

Using such a model...minimum gas pressures could

be lowered...increasing working gas capacities up to 

20 percent with zero increase in cavern size.
GAS STORAGE

to determine the minimum allowable gas

pressure that will limit microfractures

from coalescing and growing uncontrollably as exhibited by the specimen on

the right in Figure 1.

Conventional Design Criterion

Conventional cavern design practice

embraces the use of both conservative

design criteria and numerical simulations

of typical gas service cycles comprising

different minimum operating gas pressures to predict the states of stress in the

salt surrounding the cavern. The predicted states of stress are compared to states

of stress known to cause dilation in laboratory tests and the minimum gas pressure is established as the lowest pressure

that can be experienced without inducing

stresses in the salt that cause dilation.

Criteria based solely on stress have

been used extensively in the last several

years to estimate the minimum allowable

pressure of CNG storage caverns. These criteria are often based on a limited amount of

laboratory testing that provides a crude

approximation for the stress states at which

dilation is expected. The uncertainty in

determination of the stress states that produce dilation has lead to a generalized criterion that has been applied to salt at several

Gulf Coast domes and Permian, Paradox,

Appalachian, and Green River Basin bedded

salt formations.

Salt-Damage Design Criterion

Limited damage or dilation is permissible

without compromising the mechanical

integrity of salt. In addition, salt damage is

known to be recoverable under hydrostatic

and/or high mean stress conditions. In gas

storage caverns, high mean stress conditions are induced in the salt when the gas

storage pressures are high; e.g., during maximum storage pressure conditions. Therefore, any damage induced in the salt surrounding the cavern at low storage pressures is likely to be recovered or healed at

high storage pressures. Conventional stressbased design criteria do not allow for any

salt damage nor do they account for salt

healing. Advanced constitutive models for

salt have been developed that address the

shortcomings of the conventional method.

Advanced constitutive models and design

criteria have not been applied to gas storage

caverns before the current research.

Proof-Of-Concept Research

The idea that the minimum gas pressure in

CNG salt caverns may be reduced using a

continuum damage approach with advanced constitutive models is based on the

hypothesis that a better prediction of the

behavior of salt can be obtained by models

that track the history of damage and healing. By incorporating damage accumulation and healing in the material model for

salt, some of the conservatism reflecting the

uncertainty in a stress-based criterion can

be reduced, and a more accurate criterion

may be established. If a more precise

design criterion is established for cavern

analysis, the uncertainty in the minimum

gas pressure requirement would also be

reduced. A reduction in uncertainty should

produce less conservative minimum gas

pressure estimates, which would result in

increased economic benefits for the CNG

storage industry.

RESPEC, an engineering consulting firm,

and Bay Gas Storage Company, Ltd. (Bay

Gas), a natural gas storage company, performed a demonstration project to prove

this concept. The demonstration project

consisted of site characterization, laboratory testing, constitutive model evaluation,

34 GasTIPS • Winter 2003

Figure 1: Creep Deformation of Salt With and Without Dilation
model refinement, and numerical analyses.

The goal of the project was twofold: establish the minimum testing requirements

necessary to accurately define the parameter values of the continuum damage model

used to describe the behavior of salt; and

assess possible improvements for the

working gas capacity of an existing and

planned cavern over a conventional stressbased criterion.

Technology Transfer 

Into the Project

Considerable improvements in the ability

to predict the deformation and deformation rate around underground openings in salt deposits have been obtained

as a result of research efforts in various

countries related to the permanent disposal of radioactive waste. However, coupling of creep deformation and damage to

describe the response of rock salt has

been treated by only a few constitutive models. One of these models,

referred to as the Multimechanism

Deformation Coupled Fracture (MDCF)

model, was developed for the Waste

Isolation Pilot Plant (WIPP) near Carlsbad,

New Mexico, for the disposal of nuclear

waste products generated by U.S. defense

programs. Development of this model

started over 30 years ago and has been

supported by multimillion dollar research

and laboratory testing programs.

This model was used for the proof-ofconcept project to determine the minimum

allowable gas pressure in two CNG storage

caverns (one existing and one under development) owned and operated by Bay Gas

in the McIntosh Dome, north of Mobile,

Alabama. The existing cavern had been

solution mined to a volume of 2.7-

million-barrels, while the cavern under

development is expected to be about

4.22-million-barrels in volume when

complete. The casing shoes of the wells

for both caverns are at a depth of about

4,000 feet subsurface. The height of the

existing cavern is approximately 1200 feet

and a similar height is planned for the cavern under development.

Applicability of MDCF 

Model to CNG Storage

The operating conditions of a CNG storage cavern are significantly different than

a radioactive waste repository. The internal pressure in a cavern can vary considerably through-out the lifetime of the cavern and is directly related to the amount

of gas in the cavern. Conversely, the

nuclear waste repository conditions are

relatively static, with the possible exception of large temperature changes generated by certain high-level radioactive

waste packages. These differences in operating environments necessitated modifications to the MDCF model to better predict the response of CNG storage caverns. 

Supported by laboratory testing,

researchers at RESPEC made theoretical

changes that improved the predictive capability of the MDCF model. A test matrix of

approximately 35 tests that can be performed by most rock mechanics labs was

found to be sufficient to derive site specific

properties for the modified model. Using

the newly developed model and a quantitative design limit for salt damage, numerical simulations were used to determine the

minimum allowable pressure for the two

Bay Gas caverns.

Numerical Simulations

Two sets of numerical analyses were performed using the geometrical, geological

and material properties gathered for the

project. One set of analysis used a conventional stress-based criterion and the

other used the newly developed MDCF

model damage-based criterion. Because

development of the second Bay Gas cavern was not complete at the time of this

investigation, the final geometry of the

cavern was based on a prediction of solution-mining software. The calculations

closely simulated the actual or expected

history of the caverns including cavern

excavation by solutioning, dewatering,

and 20 years of natural gas service.

The gas service cycle used for this

study was similar to that experienced for

the existing cavern during its first 8 years

of service. This gas service cycle consisted

of a single injection and withdrawal phase

during each year of operation. The maximum gas pressure specified for the caverns was 3290 psi or about 0.82 psi/foot

depth at the casing shoe.

Minimum gas pressures of 1200 and

1000 psi (0.3 and 0.25 psi/foot depth at the

casing shoe) were determined using the

stress-based criterion for the existing and

planned caverns, respectively. A minimum

gas pressure of 800 psi (0.2 psi/foot depth)

was determined for both caverns using the

MDCF model damage-based criterion.

Working Gas Increased

The lower minimum gas pressure predicted

by the MDCF model would increase the

initial working gas capacity of the existing

cavern by about 20 percent. An 8 percent

increase in the initial working gas capacity

is expected for the cavern under development. This increase in deliverable gas

comes without any increase in cavern size.

Thus other than the cost of laboratory testing to develop site-specific properties and

performing a geomechanical study using

the MDCF model, no additional operating

or capital expenses are associated with the

capacity increase.

However, the closure rate of the cavern

is very sensitive to the internal pressure

Winter 2003 • GasTIPS 35

GAS STORAGE
GAS STORAGE

within the cavern. The lower the pressure in the cavern the faster the cavern

volume will be reduced because of time

dependent salt deformation (salt creep).

This means that the benefit of lowering

the minimum gas pressure will eventually be negated. Figure 2 illustrates the predicted 20-year working gas capacity history of the existing Bay Gas cavern

assuming minimum gas pressures determined using both the stress-based and

MDCF model damage-based criteria.

The cavern can be operated with the

lower minimum pressure determined

using the MDCF model for about 20

years before the loss of volume reduces

the working gas capacity of the cavern to

that determined using the conventional

stress-based criterion. During this 20-

year period, an additional 4 Bcf of gas

would pass through the cavern assuming

it is only cycled once each year. Also

shown in Figure 2 is the expected working gas capacity of the cavern based on

the current historical pressure cycle for

this cavern. This figure illustrates how a

change in the conservative operation

currently used by Bay Gas could

improve performance.

Next Steps

Based on the results of this research project, the continuum damage mechanics

approach using the MDCF model

appears to be a viable option for determining the minimum gas pressure for

CNG storage caverns. Determining the

total potential savings attributable to

adopting the MDCF model depends on a

number of unknowns (e.g. actual cavern

service cycles, outcome of geomechanical analyses for a specific site). Still,

this proof-of-concept project demonstrated that less conserative estimates for

the minimum gas pressure can be determined. However, further refinement and

development of the model should be

performed before it is routinely applied

to cavern analyses. Specifically, the

model should be validated over stress

conditions ranging from triaxial extension

to triaxial compression. The MDCF

model’s development was based solely

on the results of laboratory tests performed at triaxial compression states of

stress. Based on salt strength testing

data available in the literature and the

results of a creep test performed during

this project, salt characterization in triaxial

extension is important for evaluating

CNG storage caverns. Most rocks behave

differently in triaxial compression and

extension with the material being weaker

in extension. Research in this area would

further reduce the uncertainty in predicting the behavior of salt surrounding natural gas storage caverns. ✧

For more information on the topic of salt cavern

modeling using the MDCF model, contact Kerry

L. DeVries at 605-394-6400.

36 GasTIPS • Winter 2003

Figure 2: Simulated Working Gas Capacity of a Salt Storage Cavern.

The key to optimizing cavern performance is to

determine the minimum allowable gas pressure that

will limit microfractures from coalescing 

and growing uncontrollably 
CORROSION STUDY

MOVES AHEAD

Gas Technology Institute (GTI), in an

effort to enhance the industry’s ability to

characterize and control microbiologically influenced corrosion, is soliciting

the natural gas industry to provide samples of gas pipeline liquids and solids

that may contain microorganisms associated with pipeline corrosion. Companies submitting samples will receive a

conventional analysis of each sample as

well as a more comprehensive analysis

– completed using newly developed

characterization techniques – at no cost.

The purpose is to identify the organisms

in the microbial communities present in

gas pipelines throughout the U.S., and to

obtain data correlating the presence of

certain bacterial species with internal

corrosion. Eventually, this information will

be used to develop effective counter

measures to help control microbiologically induced corrosion. For sample preparation and shipping instructions contact

John J. Kilbane at GTI (847-768-0723 or

john.kilbane@gastechnology.org). A

description of the project is also available

online at http://www.gastechnology.org/.

GTI can cover the shipping charges. ✧

GTI DEVELOPING PIPELINE

INTEGRITY CATALOG

Gas Technology Institute (GTI) – under

industry sponsorship – is developing a

comprehensive catalog of worldwide

natural gas pipeline integrity products

and services. GTI is offering vendors

the opportunity, at no charge, to provide

product and service information for the

catalog. The goal is to develop an allencompassing guide to the various

tools, hardware, consulting services,

software applications, survey crews,

turnkey “solutions,” and other services

available to help meet pipeline integrity

management requirements. The catalog will address such areas as: overthe-ground indirect survey methods

and equipment, leak detection, unique

pipeline surveying methods, and software resources. Release is scheduled

for early 2003. The project is being supported through a GTI consortium of 27

natural gas distribution companies in a

collaborative effort to enhance the efficiency of the industry’s pipeline integrity management activity. These project

participants are contributing to the catalog as well, providing source companies and information on products they

use. The catalog will initially be available in print and electronic form only to

the members of the consortium. A

modified version may be made available

industry-wide at a later date. To have

your company’s product or services

included in the Pipeline Integrity Management Catalog, contact: Josie

Riggio, Materials Engineer, Gas Technology Institute at 847-768-0537 (josie.

riggio@gastechnology.org). ✧

VORTEX VX DEVICE

REDUCES TURBULENCE, 

BOOSTS PRODUCTION

A Denver-area company, Vortex Flow

LLC, announced that its VX tools are

demonstrating impressive results after

nearly one year of use in the field. The

Vortex VX tool improves production by

reducing flowline backpressure from

flow turbulence. The device separates

gas and liquids into a two-phase flow

pattern with the liquids flowing in a

spiral along the pipe wall and the gas

flowing down the center. This vortex

pattern prevents liquids from dropping

out and hindering flow, even over long

distances and substantial changes in

elevation and direction. Vortex Flow

tools, available in several sizes and

pressure ratings, have been installed in

seven gas producing regions across

the United States. After approximately

100 installations, Vortex Flow reports

that wells with VX tools are exhibiting

significant improvements over their

projected decline rates. Field experience is showing that the unit is eliminating flowline freeze-ups in cold weather as well as enhancing the movement of

liquids in flowlines. Producers are seeing

improved plunger-lift performance at the

wellhead an a reduction in the need for

pigging in lines that frequently become

blocked. The Vortex Flow VX tool is

one of a number of new technologies

that was developed with support

from the Stripper Well Consortium, an

industry/government partnership

sponsored by the Department of

Energy’s Strategic Center for Natural

Gas. For more information visit

www.vortexflowllc.com/. ✧

Winter 2003 • GasTIPS 37

NEW PRODUCTS, SERVICES & OPPORTUNITIES

The purpose is to identify the organisms in the

microbial communities present in 

gas pipelines throughout the U.S., and to 

obtain data correlating the presence of certain 

bacterial species with internal corrosion. 

▲

▲

▲
NEW PUBLICATIONS

EVENTS CALENDAR

38 GasTIPS • Winter 2003

APRIL 6-8

20th SPE Hydrocarbon Economics and

Evaluation Symposium, Dallas, TX.

Held at the Hotel Inter-Continental. Theme

is “Prospering Through Economic Cycles.”

www.spe.org/.

APRIL 7-8

North American Gas Strategies

Conference, Houston, TX.

Ziff Energy Group conference to be

held at the Houstonian Hotel. www.ziffenergy conferences.com/. 

APRIL 8-9

SPE/ICoTA Coiled Tubing Conference

and Exhibition, Houston, TX.

Held at The Woodlands Waterway

Marriott Hotel and Convention Center.

www.spe.org/.

MAY 5-8

2003 Offshore 

Technology Conference, Houston, TX.

Held at Reliant Center at Reliant Park.

www.otc.org/.

MAY 5-9

Biennial International Coalbed

Methane Symposium, Tuscaloosa, AL.

Held at the University of Alabama’s

Bryant Conference Center. Call 205-

348-9718, orwww.pmdp.ccs.ua.edu/.

MAY 11-14

AAPG Annual Meeting, 

Salt Lake City, UT.

American Association of Petroleum

Geologists Annual Meeting to be held

at the Salt Palace Convention Center.

www.aapg.org/.

OCT. 5-8

SPE Annual Technical Conference 

and Exhibition, Denver, CO.

Society of Petroleum Engineers to be

held at Colorado Convention Center.

www.spe.org/.

▲ ▲

▲ ▲

▲ ▲

▲

CBM PRODUCED

WATER COSTS QUANTIFIED

The Department of Energy undertook an

effort to quantify the impact of alternative water management approaches

on the volume of economically recoverable coal seam gas in the PRB. The

results of this effort, carried out by

Advanced Resources International, a

consulting firm in Arlington, VA. They

show that under the most likely set

of economic and infrastructure assumptions, a blanket regulation requiring produced water to be “actively” treated

(e.g., reverse osmosis) before discharge

would result in a shift in status of

between 12 and 15 Tcf of gas from

economic to uneconomic (depending on

the mode of RO residue disposal). 

The complete report (Impacts of

Alternative Water Management Practices on Coalbed Methane Development in the Powder River Basin) is available on-line at the National Energy

Technology Center’s Strategic Center

for Natural Gas website at www.netl.

doe.gov/scng. The report is also available on CD. ✧

ASSESSMENT OF UNDISCOVERED

OIL AND GAS RESOURCES IN

ROCKY MOUNTAIN BASINS

The USGS has completed an assessment

of undiscovered, technically recoverable

oil and natural gas resources in five geologic basins in the Rocky Mountain region:

Uinta-Piceance of Colorado and Utah,

Southwestern Wyoming (Greater Green

River Basin), San Juan Basin of New

Mexico and Colorado, Montana Thrust

Belt, and the Powder River Basin of

Wyoming and Montana. Overall findings in

the assessment indicate a mean of about

183 trillion cubic feet (TCF) of undiscovered gas, of which 92 percent (a mean of

169 TCF) of the undiscovered gas resource

is unconventional. Of the 169 TCF of

unconventional gas, about 25 percent

(42 TCF) is coalbed methane. Of particular

interest is the mean estimate of 14.3 TCF of

coalbed gas in the Powder River Basin

(Wyoming), a substantial increase from

1.1 TCF in a previous assessment. The

increased estimate is based upon new

geologic information from increased

exploration and drilling operations.

Detailed fact sheets of each basin are

available at http://greenwood.cr.usgs.

gov/maps/factsheets.html. ✧

CANADIAN REPORTS PUBLISHED

GTI-Canada Group plans to distribute

four reports related to Canadian unconventional gas resources. Two relate to

coalbed methane: Upper Mannville

Coals and Their Equivalents Western

Canada Sedimentary Basin: CBM Play

Types and Potential (GRI-02/0189), and

Coalbed Methane in Western Canada

(GRI-02/0157). The other two relate to

shale gas: Organic Geochemical Analysis

of the Second White Speckled Shale and

Belle Fourche Formations, Upper Cretaceous Colorado Group, West Central

Alberta: Implications for Shale Gas

Production (GRI-02/0163), and Shale Gas

Potential of the Late Cretaceous Second

White Speckled Formation (2WS)In the

Medicine Hat Area of Sourthern Alberta,

Canada (GRI-02/0218). These publications can be obtained on CD-ROM by

contacting Ann Priestman at the

GTI/IPAMS Information Center at

303-575-9030 or via e-mail at

gricentr@ix.netcom.com/. ✧

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