April, 2003
HGS Meetings

HGS Emerging Technologies Dinner Meeting

"Global Geophysical Trends"

Abstract:

The Exploration and Production industry faces a tremendous growth challenge with a projected need for an additional 37 MMBOPD over the next two decades. Advances in geophysical technology will play a significant role in delivering these resource requirements. Over the next five years, new developments in computing, digital recording, massive channel counts, 3-D imaging, time-lapse (4-D), anisotropy, seismic attributes, multi-component recording, and visualization will provide geoscientists with new tools in the arsenal for finding and developing new fields.

Biographical Sketch:

Mike Bahorich invented two technologies that are used extensively by oil industry geophysicists. He received the SEG 1998 Virgil Kauffman Gold Medal for his Coherence CubeTM patent, a method that reveals stratigraphic features and numerically highlights 3-D seismic fault surfaces. A service company, Coherence Technology, was founded on this work. Years earlier, he patented interval/volume attribute mapping, now available on most geoscience workstation software platforms. He is an officer of Apache Corporation where he is Executive Vice President, Exploration and Production Technology. He has spent his career at Apache and Amoco as an explorer, geophysical interpreter, development geophysicist, seismic processor, stratigrapher, researcher, software developer, research supervisor, exploration manager and chief geophysicist. He edited a geophysical textbook and has published in a variety of areas including seismic attributes, multivariate statistical analysis, statics, seismic acquisition, seismic processing, seismic interpretation, workstation software, and stratigraphy. He received a BS degree in Geology from the U. of Mo., Columbia, and an MS in Geophysics from VPI. Mike is SEG President for the 2002-2003 term. He serves on advisory boards at VPI and Stanford University.

HGS Dinner Meeting

Petroleum Geology of the Central North Slope, Alaska: Opportunities for Independents

Abstract:

Four of the top ten producing oil fields in the United States are located on Alaska’s North Slope, where total production currently accounts for at least 15% of domestic production in the United States. The bulk of that oil comes from the super giant Prudhoe Bay field and the giant Kuparuk River field (Figure 1). Large integrated oil companies have dominated the North Slope since the wave of exploration began in the early 1960s that ultimately lead to the Prudhoe Bay discovery in 1967. As the North Slope province matures, the largest integrated major oil companies increasingly focus their exploration resources on opportunities overseas. Recent advances in 3-D seismic and drilling technology have led to a ten-fold increase in exploration success in the region. These facts coupled with Alaska’s predictable area-wide leasing program provide real opportunities for independents.

The petroleum geology of Arctic Alaska is controlled by a complex post-middle Devonian geologic history that includes three tectono-stratigraphic megasequences deposited in response to three distinct plate tectonic settings involving the Arctic Alaska terrane (Figure 2) (Hubbard and others, 1987). From Late Devonian to Late Triassic time Arctic Alaska was part of a south-facing (present-day coordinates) passive continental margin that was connected to a northern source terrane. The sedimentary record of this tectonic regime is assigned to the Ellesmerian sequence, a 6,000-foot-thick (1,800 meters) succession of ramp and basinal carbonates, including porous dolomitic tidal and peritidal facies, quartzose sandstones derived from northern sources, and organic-rich shales. Ellesmerian strata are time-transgressive toward the north, where they progressively onlapped the northern source terrane.

Basin polarity gradually changed over a 100-Ma period from Early Jurassic to Late Neocomian time. During this period Arctic Alaska experienced active crustal extension that culminated in Valanginian-Hauterivian time in uplift of a rift shoulder, the Barrow arch, opening of the oceanic Canada Basin, and formation of the present day coastline of Arctic Alaska. The sedimentary record of this period is assigned to the Beaufortian sequence „ (Figure 2). Beaufortian strata thicken away from the crest of the Barrow arch, toward the north and south. South of the arch, Beaufortian strata are up to 3,200 feet thick (1,000 meters); north of the arch the thickness exceeds 9,500 feet (2,900 meters) in extensional fault-bounded basins. Like Ellesmerian strata, Beaufortian sandstones are quartzose, reflecting derivation from northern and local sources. The Jurassic part of the mega-sequence is interpreted to record a failed rift episode characterized by down-to-the-south faulting and formation of half grabens, and deposition of an extensive south-thickening (basinward) clastic wedge with distinct clinoform geometries visible on regional seismic data. The Neocomian part of the megasequence records an episode of renewed extension that led to separation of Arctic Alaska from its northern source terrane and opening of the Canada Basin. Uplift during this second period of extension created the rift shoulder-Barrow arch. Widespread erosion along the crest and proximal flanks of the rift shoulder resulted in truncation of older Beaufortian and Ellesmerian strata below a regional Hauterivian-Valanginian breakup unconformity (LCu).

In Late Jurassic time, coeval with Beaufortian rift-related tectonism to the north, Arctic Alaska collided with an island arc south of the present-day Brooks Range. This arc-continent collision resulted in obduction of oceanic crust and the collapse of the outboard margin of the Arctic Alaska plate and the associated imbrication of its Devonian to Triassic sedimentary cover. The sedimentary record of Mesozoic- Cenozoic compressional tectonism is recorded in the Brookian sequence, an Upper Jurassic to Eocene succession characterized by lithic sandstones derived from the ancestral Brooks Range (Figure 2). Brookian strata filled a large east-west-trending peripheral foreland basin with nearly 25,000 feet (7,700 meters) of siliciclastic detritus; the thickness of Brookian strata decreases toward the north, up the south flank of the Barrow arch. Regional seismic data show pronounced clinoform geometries that record the eastward migration of Brookian depocenters. Clinoform reflectors represent mud-prone strata that downlap distal condensed marine shales of the Hue Shale/Gamma-Ray zone. Base-of-slope and slope-apron sandstone successions are important components of clinoform deposits (Figure 3). Topset facies include marine shelf, sand-rich delta-front, and delta-plain facies (Figure 4).

Each megasequence includes petroleum source rocks, but the Ellesmerian and Beaufortian sequences were endowed with the richest, most prolific source rocks on the North Slope (Figure 2). Triassic limey shales of the Shublik Formation (Ellesmerian), distal facies in the Jurassic Kingak Shale (Beaufortian), and transgressive shales of the Hauterivian Pebble shale unit (Beaufortian) have sourced most oil and gas accumulations in the region (Bird, 1994). These rocks are widespread in outcrop and the subsurface. Known productive source rocks in the Brookian sequence include the Lower to Upper Cretaceous Hue Shale/Gamma-Ray zone, and mudstones and shales within the Torok and Seabee Formations.

Burial history analysis using wells drilled in the central North Slope show rapid subsidence of the foreland basin starting in Barremian time (Cole and others, 1997), resulting from the northward emplacement of a significant thrust load on the southern margin of the Arctic Alaska terrane. High accommodation in the basin combined with rapid uplift in the orogen led to deposition of a thick post-Barremian succession of Brookian siliciclastic rocks, which, in turn, resulted in maximum burial of Ellesmerian, Beaufortian, and older Brookian source rocks by Campanian time 75 Ma (Bird, 1994).

The Brookian sediment load and formation of Brookian age structures controlled secondary migration and accumulation of hydrocarbons in present-day reservoirs. Structures in the range-front region of the Brooks Range consist dominantly of north-vergent thrust faults that record hundreds of kilometers of transport. Emplacement of thrust sheets over Brookian foredeep deposits and distal Beaufortian strata in the southern foothills province resulted in complex outcrop-scale folds and thrust faults. Most compressional structures in the Brooks Range and southern foothills belt formed in Late Jurassic-Neocomian time. Structures in the northern foothills belt consist of short-wavelength, thrust-cored anticlines and longer wavelength synclines. These structures typify the Albian-Cenomanian Nanushuk Formation and developed above detachments in the Torok Formation. A similar structural style characterizes Upper Cretaceous strata, where present in the northeastern part of the foothills belt. Beneath the coastal plain north of the foothills belt, Lower and Upper Cretaceous strata are largely undeformed, or are very gently folded without associated thrust faults. Hydrocarbons initially migrated from source rocks at depth in the Ellesmerian and Beaufortian sequences to stratigraphic and combined stratigraphic-structural traps up-section and up-dip on the Barrow arch. Hydrocarbons generated by Brookian source rocks migrated up-dip toward the southwest to reservoirs in base-of-slope and topset positions. Current mapping in the central foothills belt indicates these structures formed in Late Cretaceous and Tertiary time, which suggests a period of remigration to combined structural and stratigraphic traps along the flanks and crest of the Barrow arch. Subaerial exposure of Ellesmerian and selected Beaufortian sandstones beneath the LCu unconformity was critical to porosity enhancement and reservoir development. Post-rift subsidence of the Barrow arch resulted in deposition of the transgressive Pebble shale unit in Hauterivian-Barremian time, creating the topseal for most Ellesmerian and some Beaufortian reservoirs.

Plays are grouped by stratigraphic position and structural style (Figure 2). The most prospective Ellesmerian reservoir targets are located near the Beaufort seacoast and the crest of the Barrow arch, where they lay at depths generally less than 11,000 feet subsea (above the 2% Ro isograd). Ellesmerian reservoir targets include nonmarine and shallow-marine clastics, and dolomitized shallow- and marginal-marine carbonates in combination stratigraphic-structural traps associated with the LCu. Similarly, attractive Beaufortian targets are located on the south flank and crest of the arch, are present at moderate depths (above the 2% Ro isograd), are largely undeformed, and include shallow- and marginal-marine quartzose clastics. Jurassic Beaufortian targets will probably be in stratigraphic traps encased in the Kingak Shale; Neocomian Beaufortian targets will be either in stratigraphic or in combination stratigraphic-structural traps. Brookian targets include basin-floor and slope-apron turbidite systems throughout the Colville basin and in fluvial-deltaic sandstones deposited in topset positions in the „ northern foothills belt (incised valley/lowstand deltas and in highstand structural plays). Significant potential exists for deep-water Brookian targets in stratigraphic traps in the northern foothills and coastal plain (above or near 2% Ro isograd). Topset reservoir targets in the northern foothills are likely to be in combination stratigraphic-structural traps (also above or near the 2% Ro isograd). Numerous other plays involving some of the same stratigraphic intervals as those outlined here are present farther to the south, in the southern foothills belt and along the Brooks Range mountain front. These plays most likely involve gas as the primary hydrocarbon phase.

References

Bird, K.J., 1994, Ellesmerian (!) Petroleum system, North Slope of Alaska, U.S.A., in Magoon, L.B., and Dow, W.G., eds., The Petroleum System-From Source to Trap: AAPG Memoir 60, p. 339-358.

Cole, F., Bird, K.J., Toro, J., Roure, F., O’Sullivan, P.B., Pawlewicz, M., and Howell, D.G., 1997, An integrated model for the tectonic development of the frontal Brooks Range and Colville basin 250 km west of the Trans-Alaska Crustal Transect: Journal of Geophysical Research, v. 102, n. B9, p. 20,685-20,708.

Hubbard, R.J., Edrich, S.P., and Rattey, R.P., 1987, Geologic evolution and hydrocarbon habitat of the ‘Arctic Alaska Microplate,’ in Tailleur, I., and Weimer, P., eds., Alaskan North Slope Geology: Pacific Section SEPM, p. 797-830.

Biographical Sketch:

David LePain is a senior geologist in the Energy Section of the Alaska Division of the Geological and Geophysical Surveys (DGGS). His PhD dissertation addressed the regional sedimentology and tectonics of the Carboniferous Endicott Group in the range-front region of the Arctic National Wildlife Refuge. Dave’s current focus is the sequence stratigraphy and reservoir potential of the Lower Cretaceous Nanushuk Formation and selected Upper Cretaceous units in the foothills belt south of the National Petroleum Reserve-Alaska. He manages DGGS’ NPRA-Foothills program.

HGS Environmental / Engineering Dinner Meeting

"Brakish Groundwater Development, for Potable Supply: Part 1"

Abstract:

The San Patricio Municipal Water District (SPMWD) provides water to municipal and industrial customers in San Patricio and Aransas Counties. SPMWD needs to produce additional potable water to meet anticipated growth in demand. Availability of additional surface water resources in the area may be insufficient, based on current consumption compared to supply and the ever-present threat of drought. Consequently, SPMWD is interested in determining the quantity and quality of brackish groundwater that could be produced in proximity to the SPMWD treatment plant and distribution system. Reverse Osmosis (RO) technology has been selected as the treatment technology. Project feasibility depends on water quality, quantity, and on identifying a plausible and cost-effective permitting strategy to dispose brine waste.

The stratigraphic setting of San Patricio County was evaluated on a regional scale to determine the distribution and thickness of water-bearing units. The Goliad Sand and the Jasper Aquifer were identified as potential candidates. These two formations were then evaluated in more detail in the vicinity of SPMWD’s plant and distribution system. Oil well electric logs and existing geological reports were reviewed. The data indicated the presence of adequate brackish water with a TDS of 10,000 mg/l less than ten miles from key SPMWD facilities.

Regulatory analysis and interviews with Texas Commission on Environmental Quality (then the TNRCC) indicated that obtaining a permit for the disposal of RO brine to Corpus Christi Bay was feasible. Disposal by injection well was reviewed but rejected.

Economic analysis indicated that the brackish groundwater could be produced and treated for approximately $1.90/1,000 gallons. This was viewed by SPMWD as competitive with the price the District now pays for treated water. The price included permitting and constructing a waste disposal pipeline to Corpus Christi Bay from the RO facility.

Projected population growth in the Corpus Christi area will result in an ever increasing need for additional raw-water supplies. Development of high-quality groundwater and available surface water has now, or will shortly, reach the limit of supply. Development of brackish groundwater could provide SPMWD with a new source of water.

Biographical Sketch:

Steve Petersen senior geologist for Malcolm Pirnie of Houston, TX. He has seventeen years of experience in providing a wide range of services, including soil and groundwater assessment and remediation, water resource assessments, permitting, landfill closures, geomorphological assessments related to facility siting, and large-scale due diligence for complex property transactions. He has been working with the San Patricio Municipal Water District for several years to develop brackish groundwater for potable supply. He is presently working with the Harris County Flood Control District to develop a master plan that will redirect channel sediments away from landfills and into useful compost. While with ARCO Pipeline Company, Mr. Petersen established the site assessment and remediation program that were utilized to close numerous sites affected by the release of petroleum hydrocarbons. Petersen has a BA in Theology and an MS in Geology. He is a Wyoming Certified Professional Geologist and will soon receive his Texas certification. He is a member of the National Groundwater Association.

Gulf Coast Section of SEPM & South Texas Geological Society

Symposium, Field Trip

Structure and Stratigraphy of South Texas and Northeast Mexico: Applications to Exploration

SEMINAR:
OMNI SAN ANTONIO HOTEL
SAN ANTONIO, TEXAS
APRIL 11, 2003

FIELD TRIP:
LOWER. CRETACEOUS CARBONATES
WEST OF SAN ANTONIO
APRIL 12, 2003

Information:

The GCSSEPM and the STGS will co-sponsor a one-day seminar on structural and stratigraphic applications to petroleum exploration of Mesozoic through Paleogene targets in South Texas and Northeast Mexico. Recent discoveries call for a new focus on these trans-border trends. An exciting program of oral, poster, and core presentations will include topics on regional structure of the GOM Basin with focus on the South Texas/Northeast Mexico area; GOM Basin source rocks; Cretaceous stratigraphy and biostratigraphy; Lower Cretaceous carbonate reservoirs; gas potential of various Northeast Mexico plays; raft tectonics in South Texas; timing of growth on Tertiary fault systems; Wilcox, Vicksburg, and Frio sandstone trend studies; and Lower Cretaceous carbonate and Lobo sandstone core displays.

Scheduled presenters will be an impressive group of structural and stratigraphic experts on the region, including Albert Bally, Robert Goldhammer, Claudio Bartolini, Clif Jordan & James Lee Wilson, Thomas Ewing, Victor Ruiz, Genaro Ziga, Charles Kerans, Robert Loucks, Robert Scott, William Morgan, Rashel Rosen, Lynn Anderson & Carl Fiduk, William Galloway, Richard Debus, Albert Shultz, and Frank Brown.

The seminar registration fee is $125 through March 19, 2003 and $150 after March 19, 2003. The fee includes lunch, refreshments, wrap-up “happy hour”, notepad portfolio, and CD publication containing seminar papers and abstracts.

The field trip will visit three easily accessible Lower Cretaceous exposures just west of San Antonio. One stop will be at the Pipe Creek caprinid buildups and beach facies outcrops of Glen Rose age first studied by Bob Perkins in 1974. The Pipe Creek locality is one of the most instructive areas in the Cretaceous of the Gulf of Mexico for observing a range of depositional facies and reservoir rock types associated with caprinid reef systems of Aptian-Albian age. The Texas BEG has recently used state of the art technology, including LIDAR scans to increase our understanding of this spectacular outcrop. Cores from the immediate vicinity will be available. The other stops will be in the Edwards Formation (Albian). The Edwards aquifer is one of the most prolific aquifers in the world and will be discussed with an emphasis on the permeability structure of the faults, fractures, and karst-dissolution features seen at these stops. Transportation will be by vans, which will leave the Omni Hotel on April 12 promptly at 8 AM and return by 5 PM.

The field trip fee is $50 and will include lunch and guide materials. The trip will be limited to 50 registrants, who must also be registered for the seminar.

Seminar Program Co-Chairmen: James Lee Wilson, Bonnie Weise

Seminar Coordinating Committee: Bonnie Weise, Michelle Debus, John Waugh, Gene Ames III, Norm Rosen, Nancy Engelhardt-Moore

Field Trip Organizer: Tom Fett

Field Trip Leaders: Charles Kerans, Jerry Lucia, Robert Loucks, Jerry Bellian

Information and registration forms are also available on the GCSSEPM web site at www.gcssepm.org .

For program information, contact Bonnie Weise at bweise@venusexploration.com.

For registration information, contact Norm Rosen at gcssepm@houston.rr.com.

For field trip information, contact Tom Fett at medinalake@msn.com.

HGS International Dinner Meeting

"The Stratigraphy and Reservoir Architecture of the Oligocene to Miocene Malembo Formation of the Lower Congo basin, Offshore Angola"

Abstract:

A stratigraphic framework based on the detailed integration of well data and regional seismic stratigraphy, seismic facies analysis and biostratigraphy is presented for the Oligocene to Miocene Malembo Formation of the Lower Congo Basin. The Malembo Formation was deposited in a deep-water slope environment characterized by hemipelagic shales, with generally E-W trending confined to distributary deep-water systems. The extensive 3D seismic data (~20000 km2) and ~50 well penetrations are coupled with high-resolution biostratigraphy to provide a comprehensive dataset covering a significant portion of the Lower Congo Basin.

The Malembo Formation contains several low frequency megasequences (3-10 M.y.) characterized by sand-prone lowstand deposits and shale-prone abandonment deposits that can be mapped regionally within the basin and control the major reservoir and seal play elements. The megasequences are in turn composed of composite sequences (0.5-3 My) and high frequency sequences (0.1-0.5 My) that control lithofacies type, reservoir distribution and reservoir architecture within the deep-water systems. The Oligocene to Miocene reservoirs contain both turbidite and debris flow deposits that display an overall fining-upwards succession from gravel-dominated in the Oligocene, mixed gravel and sand in the Early to Middle Miocene and fine to medium-grained sand in the Late Miocene.

The Malembo Formation is presented with eight new members based on European Basins stratigraphic nomenclature where each member contains one to four composite sequences. The framework promotes internal consistency and provides a basis for a more detailed regional understanding of the Oligocene to Miocene succession. The proposed stratigraphic framework provides an understanding of semi-regional seals and reservoirs that is an important aspect of exploration, development and production geology.

Biographical Sketch:

John Ardill currently works for ExxonMobil Technology in Houston as the team lead of the Deep-Water Reservoir Interpretation and Prediction Best Practices Project. Over the past 7 years with ExxonMobil, John has worked in Exploration, Development, Production and Research with the last 5 years being focused on deep-water reservoir characterization in West Africa. John joined ExxonMobil in 1996 after completing a Ph.D. at the University of Liverpool in England under the guidance of Dr Stephen Flint and a Bachelor of Science at the University of Edinburgh in Scotland under the guidance of Dr John Underhill.

HGS North American Exploration Dinner Meeting

"Subsalt Trap Archetype Classification: A Diagnostic Tool for Predicting and Prioritizing Gulf of Mexico Subsalt Traps"

Abstract:

Many Gulf of Mexico subsalt traps remain poorly imaged on even the best depth-migrated seismic datasets, necessitating the use of geologic models to help guide prospect evaluations. We introduce a subsalt trap classification scheme to address a long-standing industry need for a comprehensive and practical method of characterizing subsalt traps according to their structural merits. Designed for exploration applications, the classification helps interpreters recognize and, in the case of ambiguous seismic data, infer the presence of key trap attributes that improve or diminish subsalt prospectivity. This trap assessment tool is based on the following tenets:

The four trap families are qualitatively ranked for overall trap risk and play value, a ranking that is affirmed by Gulf of Mexico subsalt drilling results. Contractional, extensional, and passive subsalt anticlines occur almost exclusively above deep autochthonous salt, and traps of the top-ranked autochthon rooted play family have yielded the largest subsalt discoveries to date. Although subsalt traps underlain by back-ramping allochthonous salt roots lack anticlinal closures, they often exhibit inverted, flat-crested sigmoid folds and may present the best play opportunities updip of the autochthon rooted subsalt trends. The family of subsalt traps underlain by fore-ramping allochthonous roots is relegated to a third-place ranking because of the generic risk of upwardly flexed trap crests, although specific variations (e.g., piggyback sills with subsalt inversions) may remain highly prospective. Lastly, sub-suture traps often retain their pre-suture stratal synclines, forming bi-lateral ribbon truncation closures. These high-risk traps remain problematic for the industry.

Biographical Sketch:

Bill Hart is a geologist in BP’s Deepwater Gulf of Mexico Exploration Business Unit, where he currently works extrasalt and subsalt plays in the Perdido fold belt. Upon joining Amoco in 1980, he became an ardent student of salt-sediment dynamics, a natural result of his early assignments exploring and appraising numerous Louisiana salt domes. Since the late 80s, he has leveraged this experience toward emerging Gulf of Mexico subsalt play trends, generating prospect inventories from coastal Louisiana to the deepwater protraction areas. Bill holds a MS in geology from the University of Massachusetts, as well as a BS in geology from San Francisco State University. He is an active member of HGS, NOGS, and GCSSEPM, and currently serves as Program Advisory Committee Co-Chair of the 2004 GCSSEPM conference on salt-sediment interactions.

Martin L. Albertin is a geophysicist with BP, in its Deepwater Gulf of Mexico Exploration Business Unit. Martin joined Amoco in 1988, and has worked on depth imaging, subsalt exploration, and pressure prediction projects worldwide. Martin has a BS in geology from Indiana University of Pennsylvania (1985) and an MA in geology from the University of Texas at Austin (1989).

HGS Lunch Meeting

"AVO Impedance: A New Attribute for Lithology and Fluid Discrimination"

Abstract:

( This article was presented at Petex 2002 by the first author in December 2002.)

Introduction

Porosity and fluid discrimination from seismic using elastic inversion techniques is currently an area of considerable interest for oil and gas exploration. Since the formulation of elastic impedance (Connolly 1999) many workers have been evaluating the possibilities of combining the benefits of inversion (i.e., calibration) with the exploitation of AVO phenomena that potentially provide enhanced discrimination of fluid and lithology.

The work of Goodway et al. (1997) highlighted the benefits of rock property related attributes (l and m) in terms of both physical interpretation and discriminating power. Recently, Whitcombe and Fletcher (2001) formulated the attribute GI (effectively a projection of elastic impedance), and showed that projections on AIGI crossplots can be used to differentiate fluid or lithology. This paper presents another elastic attribute, termed AVOImpedance, that can be considered alongside attributes such as LMR and AIGI.

AVO Impedance is a data-adaptive attribute based on a weighted combination of acoustic impedance (AI) and elastic impedance (EI). Using a well dataset from the Central North Sea, the AVO Impedance attribute is shown to be similar (in terms of its predicting power) to other attributes based on projections of AI and GI and MR (mr) and L/M (l/m). The simplicity of the AVOI attribute and the direct relevance to the outputs of near- and far-stack inversions are compelling.

Dataset

A dataset from a well in the Central North Sea is used as a means of comparing the different attributes. A 300-m section of the well is used with variable thickness brine-bearing sands of Jurassic age. Rock physics analysis and fluid substitution to oil bearing was undertaken as well as depth to time conversion (2-ms sampling). Various facies were then described from the time- sampled data.

AVO Impedance Construction

If acoustic impedance is crossplotted against elastic impedance (at an angle of 25°) (Figure 1), it is evident that the trends of the various facies are similar (i.e., diagonally from bottom left to top right) but that there is an arrangement of shales at the top, then brine sands, and finally oil sands progressing down the plot). AVOImpedance effectively normalizes the data to a trend on this plot (usually the brine sand trend is chosen as the normalizing trend).

The equation that performs this normalization is quite simply (AI*a+b) - EI where a is the slope of the trend and b is the regression intercept. Essentially this operation is a projection of the data points along a trend, a technique borrowed from weighted stacking of AVO attributes.

AVO Impedance Interpretation Template

It has been found that a crossplot of AVO Impedance vs AI provides a very useful template for the interpretation of porosity and fluid fill. A porosity and fluid fill framework is established using rock physics analysis of well data.

In the example shown in Figure 2 the AVO Impedance attribute is normalized to the brine sand data of the rock model. On the crossplot. the shales (denoted by Kimm Clay and Ettrick shales points) plot to the left, with the brine sands in the center of the plot and oil sands to the right. It illustrates that of the two attributes plotted (AI and AVOI) AVO Impedance is the principal discriminator of fluid. Porosities plot successively down the crossplot showing the dependency of acoustic impedance on porosity. The plot also highlights the difficulties in differentiating fluid and lithology at low porosities (<15%) using elastic attributes.

Of course, if there is variation in the fundamental nature of the rock fabric of the sands then the framework becomes more complex. However, in many cases the sands in a localized area can be defined adequately by a simple porosity-dependent rock physics model (e.g., Dvorkin et al. 2002).

Comparison with LMR and AIGI

AIGI and LMR crossplots for the same data are shown in Figures 3 and 4, respectively. The framework trends for fluid and porosity are also shown as is the projection trend that gives the optimum discrimination of fluid (arrow with dashed line).

The AIGI and MR vs L/M crossplots show that individually the attributes have limited discriminating power. However, as Whitcombe and Fletcher (2001) note, the discriminating power is in the projection of the data. Projections designed to discriminate fluid have been applied to both crossplots and projection attributes generated. To compare the attributes, histograms were created to which Gaussian fits were made for each of the facies.

The results (shown in Figure 5) show that AVOImpedance, the “‘ortho-fluid’” projection of AI and GI, and the projection of MR and L/M have comparable similar discriminating power. In fact, fuzzy logic cross-validation techniques (i.e., facies prediction on the learning dataset) yields a 90% hit rate in the prediction of facies using each of the attributes.

Discussion

The AVO Impedance attribute as described here would appears to be as good a discriminator as any other projection of elastic attributes. In a sense this is not surprising as they are all derivatives of the same elastic parameters. However, AVO Impedance is elegant in its simplicity of construction and has a direct relevance to the outputs of near- and far- angle stack inversions. When crossplotted against acoustic impedance and linked to a rock model framework, it provides a useful template for the interpretation of elastic inversions.

The limits of practical application of the elastic attributes discussed here are an area yet to be fully explored (and documented in the literature). Clearly, projections of AVO-related attributes are sensitive to noise, and much depends on the pre-stack data quality as to the success of application. It follows that noise-free comparisons of different attributes may be misleading. White (2000) illustrated that although there may be a theoretical justification of the LMR attributes in comparison to the AVO intercept and gradient, the LMR attributes are more sensitive to noise. In the presence of noise LMR-related attributes gave the same misclassification rates as the AVO attributes. Limiting the adverse effects of noise in inversions is one of the challenges of applying this technology.

An evaluation of AVOI-, AIGI- and LMR- related attributes generated from real seismic data is currently being undertaken.

References

Connolly, P., 1999. Elastic impedance. The Leading Edge, April, 438--452

Dvorkin, J., Gutierrez, M.A and Nur, A., 2002. On the universality of diagenetic trends. The Leading Edge, January, 40--43.

Goodway, W., Chen, T. and Downton, J., 1997. Improved AVO fluid detection and lithology discrimination using Lame petrophysical parameters; lr, mr and l/m fluid stacks from P and S inversions. Internat. Mtg., Soc. Expl. Geophys., Expanded Abstracts.

Whitcombe, D.N and Fletcher, J.G, 2001. The AIGI crossplot as an aid to AVO analysis and calibration. Internat. Mtg., Soc. Expl. Geophys., Expanded Abstracts.

White, R.E., 2000. Fluid detection from AVO inversion: the effects of noise and choice of parameters. 62nd EAGE meeting Glasgow, 1 June 2000.