January, 2001
HGS Meetings

HGS Dinner Meeting

"Tectonic Control on the Creation of Supergiant Fields in the Central and South Caspian Area"

Abstract:

Introduction

Over 2000 oil and gas fields have been discovered in the area between the Black Sea and Turkmenia (figure 1) in the former Soviet Union. Of particular note are the supergiant fields of the Caspian area; such as, Kashagan and Tenghiz in the North Caspian and Shah Deniz and Chirag fields in the South Caspian (figure 2) . This note describes the late Permian to present day structural evolution and tectonic setting of these fields and the influence the tectonic events have had on the hydrocarbon story. This regional story was completed in 1993 at BP as support for the application for acreage in the Caspian basin.

Basin and Structural Setting

The Caspian Sea can be considered three discrete basins (figure 2) with completely different origins. The North Caspian area is underlain by a Paleozoic passive margin. The Central Caspian is a foreland basin associated with shortening of the Caucasus Mountains and the southern area developed as a pull-apart basin during the Mesozoic. The basins all formed within crust that originated from the supercontinent Laurasia, which accumulated during the Paleozoic (Sengor et al., 1993). The southern boundary of the South Caspian basin is interpreted to represent the suture that separates Laurasia from the fragments of the Gondwana supercontinent (Iran) that accumulated during the Mesozoic and Cenozoic (figure 1) . This paper concentrates on the post-Paleozoic evolution of the Caspian.

North Caspian Basin

The North Caspian basin is a Devonian extensional basin (pull-apart?) that is interpreted to have developed on the then southern margin of the Laurasian supercontinent. The Caspian sea overlies the southern rift shoulder of this basin. Post rift thermal subsidence during the late Devonian and Carboniferous resulted in the seeding and growth of giant pinnacle reefs (reservoir). Isolation of the basin in a deepening foreland setting lead to termination of reef growth, flooding and deposition of mudstones and evaporites (seal) during the Permian. Closure of Paleotethys to the south in the late Triassic resulted in the development of a further foreland setting.

Central Caspian Basin

The Central Caspian is a relatively shallow foreland basin that began to develop in the Late Eocene. During the Early Jurassic, a rift developed within the present day Caucasus mountains on the western side of the Central Caspian; the area of the present day Central Caspian developed on the rift footwall. During the early Cretaceous and Tertiary (late Eocene to present), the rift inverted as a response to collisions and subduction on the southern margin of the plate. The Caucasus mountains were formed and a foreland basin was generated. The principle reservoir rocks are fractured Late Cretaceous micrites, sourced by the overlying foreland flooding event (figure 3) and trapped within inversion structures.

The South Caspian Basin

The South Caspian is an exceptionally deep, oceanic-floored basin, which is surrounded by thrust zones and mountain belts. The basin is located in what used to be Laurasia, situated on the northern margin of the Paleotethys ocean. Oceanic closure (Alavi, 1992) occurred in the mid-Triassic. By the mid Jurassic, a major left lateral shear zone had developed across the area, controlled largely by the opening of the Central Atlantic. Several extensional and strike-slip basins developed at this time: it is proposed that one of these was the South Caspian. From the late Jurassic onward, the area went into compression. A succession of plate and ensimatic arc collisions associated with the closure of the Neotethys and other minor oceans resulted in a series of pulsed compressive events through to the present day. The only exception is a brief phase of extension in the middle Eocene.

To the northwest, the South Caspian basin is interpreted to extend into the Azerbaijan Caucasus, where field work has enabled us to develop a story for the structural evolution of these basins, which fits with the regional tectonic framework. Thick Liassic basinal deposits, continuous from the Eastern Caucasus rifts, suggest a major phase of rifting, while the fringe of Late Jurassic carbonates (Grachevskiy et al., 1980) around both basins implies basin formation prior to the Late Jurassic. Thrusting and major unconformities give evidence for the subsequent compression. The first major compressive event is in the mid Cretaceous, related to ensimatic arc collision in Armenia. It is likely that this occurred when oceanic crust began to subduct north under the Apsheron ridge in the South Caspian. Neotethys closure in Iran during the Oligo-Miocene resulted in another major compressive phase. Crustal shortening and subduction developed the South Caspian as a deep push down basin, forming an ideal site for source rock deposition (figure 3) .

As compression continued up to the present, sedimentation in the South Caspian can be closely linked to the pulses of regional shortening. Uplift and loading deepened the foreland basins, resulting in flooding and sometimes the formation of a continuous sea-way from the South Caspian to the Mediterranean. During the phases of quiescence, sea level fell and the South Caspian became isolated. The primary example of this is during the Messinian, when rivers drained into the Caspian depositing the principle reservoir interval in places up to 12 km thick (figure 4) . This was subsequently folded by continued compression, creating the giant structures of today.

Conclusions

The tectonic history of the Caspian played a major role, not only in creating traps, but also in creating depositional environments during which excellent quality reservoir and source rocks could be deposited. These events resulted in the development of the giant fields in the North and South Caspian basins as seen today.

Figures:

  1. Main tectonic elements in the Caspian area.

  2. Present day position of the Mesozoic - Cenozoic sutures in the area between Bulgaria and Tadijkstan.

  3. Main source rock paleogeography: Early Maykop formation.

  4. Main reservoir paleogeography: the Pereriv of the Azerbaijan Productive Series.

References

Alavi, M., 1992, Thrust tectonics of the Binalood Region, NE Iran. Tectonics, vol. 11, no.2, p360-370

Grachevskiy M.M., Kucheruk, Y.V., Skortsov I.A. and Zyubko, A.K. 1980, The reefal margin of the south Caspian basin and its petroleum prospects (southwestern Turkmenia), Inter. Nat. Geol. Rev., vol. 24, no.7, p807-813.

Sengor, A.M.C., Natal'in, B.A. and Burtman, V.S. 1993, Evolution of the Altaid Tectonic collage and Paleozoic crustal growth in Eurasia, Nature, vol. 364, 6435, p51-84.

Biographical Sketch:

HGS Environmental / Engineering Dinner Meeting

"Light Rail in Houston – Environmental Impact Considerations in Transportation Construction Projects"

Abstract:

The presentation will include an overview of the progress to date of the Downtown to Astrodome Light Rail project. Metro's organizational structure to tackle the project will be introduced. The discussion will include the methodology and preliminary findings of the hazardous risk assessment, environmental investigation, and proposed remediation activities. The type of environmental considerations and potential for subsurface contamination of soils and water, archeological considerations, wetlands, and geotechnical aspects of the project will be reviewed.

Biographical Sketch:

Dave Marsh has a B.S. in geology from the University of Wisconsin – Madison. He has been involved as a geologist on transportation construction projects for over 30 years. He joined Metro in 1990 and oversees environmental and construction material projects

Lynda Mifsud has degrees in accounting, economics, and fine arts. She has been involved in risk analysis for oil companies for 20 years. She has worked as an Environmental Planner dealing with archeological and NEPA issues. She joined Metro in 1993 and oversees compliance with NEPA, EIS, and federal, state, and local environmental regulatory issues.

HGS International Dinner Meeting

"New Trends of Petroleum Exploration in Central and Eastern Europe"

Poster Session

Vendor Corner

Abstract:

The area reviewed in this presentation includes the territory of Hungary, Slovakia, Poland, Ukraine, Romania, Serbia and Croatia. All of these countries had been either "satellites" of the former Soviet Union or were part of it before the dramatic political changes in the early 1990's.

Geologically speaking, the area under consideration includes the Pannonian back-arc basin, the surrounding Carpathian-Dinaric mountain arc and the European foreland. The European foreland is divided into two major subunits by the Trans-European Suture Zone, which is a 2000 km long feature transversing Europe obliquely from the Black Sea up to the North Sea. These subunits are called the West-European Platform and the East-European Craton.

The Carpathian arc is a remarkable feature as it is the most prolific petroleum-bearing orogenic arc per unit length in the world, taken into consideration the cumulative production and known reserves. There is a consensus that future exploration will be successful only if the structural and stratigraphic conditions of reservoirs/seals, and the extent and maturation history of the source rocks are better understood, together with the application of the most advanced drilling, logging and well completion technology.

The West-European Platform in Poland is made up of a Permian through Mesozoic sedimentary cover uncomformably overlying the Variscan basement. There is a major chance for finding hydrocarbon gases. Prospect analyses suggest undiscovered reserves of 14 to 26 TCF of gas.

The East-European Craton in Ukraine is of remarkable exploration interest because of the presence of the Dnieper-Donets rift system in a length of nearly 2000 km. The rift was active during the Late Devonian, which was followed by the accumulation of an extremely thick post-rift series dominated by Carboniferous strata. Two major phases of uplift and erosion occurred at the end of Permian and Cretaceous times. This is a huge hydrocarbon province with the occurrence of both oil and gas. Undiscovered reserves are estimated as 1.3 to 1.5 BB oil and 20 to 25 TCF gas.

The Pannonian basin of Hungary, Slovakia, Romania, Serbia and Croatia is a mature exploration area with undiscovered resources of about 1.2BB oil and 8 TCF gas. It is generally accepted that most of these reserves could be found in the substrata of the Neogene basin, which is an Alpine thrust-fold belt composed of Late Paleozoic and Mesozoic rocks. Obviously, acquisition of modern 3D seismic surveys, better interpretations and new play concepts are required for significant exploration success in this basin.

Table 1 presents a compilation of proven oil and gas reserves, the annual production rates and imports in these countries.

It is obvious that the domestic hydrocarbon production can not fulfill the consumption and massive import is required in each of these countries. It is an unfortunate heritage from the previous political regime that imports of hydrocarbons still come dominantly from Russia. Therefore it is not too surprising that the current energy strategy in Central and Eastern European countries is to move away from the dependence on Russian oil and gas.

In the case of Ukraine, for example, the amount of imported gas is about 2.5 TCF a year, which makes Ukraine one of the largest gas markets in the world. Another extreme is Slovakia, where the domestic production is so small, that practically all the country's consumption is from import. Seemingly, Romania is in the best position, because national production can cover 60% and 75% of the consumption of oil and gas, respectively.

It is generally accepted that the rate of economical growth in the countries of Central and Eastern Europe largely depends on the success of petroleum exploration and production, either by national companies or foreign new ventures. The general trend of petroleum exploration in Central and Eastern Europe is to diminish the technological gap relative to the western world, which requires time and money. Profitable investment by western companies can only be achieved if they have both. At the same time it is a national responsibility to implement stable legal and fiscal environment, and fully guarantee international business standards in each of the countries. Apart from Poland and Hungary, there is still a lot to do in the region to arrive at a favorable business environment.

 

 

Proven Reserves

Annual Production

Import

(Percent of total annual consumption)

Country

Oil* (MMB)

Gas (BCF)

Oil* (MMB)

Gas (BCF)

Oil

Gas

Hungary

131

3100

13

155

75%

60%

Slovakia

14

150

0.6

8.5

99%

96%

Poland

115

5800

2.2

180

89%

60%

Ukraine

395

41000

29

640

75%

77%

Romania

1442

13000

48

615

40%

25%

Croatia

99

1100

12

57

70%

42%

Serbia

~70

~1200

7.3

32

70%

70%

Table 1. Proven hydrocarbon reserves, annual production rates, and imports relative to the national consumption (in the year of 1997) for countries of Central and Eastern Europe.
*Oil includes natural gas liquids

Biographical Sketch:

Dr. Ferenc (Frank) Horvath is a full Professor and Head of the Geophysical Department at Eotvos University, 1083 Budapest, Ludovika ter 2, Hungary. His main fields of research include tectonics and environmental geology, as well as basin analysis and hydrocarbon exploration. He has published 76 scientific papers, mostly in leading international journals, 3 university text books and is editor of 9 monographs.

Scientific Awards:
1987 Honorary Fellow of the European Union of Geosciences
1991 Member of Academia Europeae
1995 Honorary Fellow of the Geological Society of America
1997 Commendation Award of the American Association of Petroleum Geologists

POSTERS:

  1. "Gulf of Cadiz, Western Spain, as potential site for vast hydrocarbon reserves."
    by Luis Somoza and Allen Lowrie

  2. "Petroleum Plays of Italy"
    by J. Granath, F. Krecow, J. Aldrich, T. Berge, and L. Albanesi

  3. "New frontiers in high-resolution seismic exploration: > examples from Central Europe."
    by Tamas Toth, Robert Vida, Peter Szafian, Frank Horvath, and Peter Dovenyi

  4. "Two new hydrocarbon plays in the Western Black Sea Basin: Shallow-water reefs and deep-water ridges."
    by Marek Kaminski and Mikhail Sharipov

  5. "Palinspastic reconstruction of the Carpathian/Pannonian system."
    by Gabor Tari, Frank Horvath, and Laszlo Csontos

VENDORS:

TGS / NOPEC Spec seismic data offshore Portugal www.tgsnopec.com

HGS NeoGeo Dinner Meeting

"Attributes and Skills for Successful Career Development"

Abstract:

Most entry-level geologists and geophysicists enter the petroleum industry with advanced academic training that has given them many of the tools and basic "clinical skills" they will need to begin work. More specialized training is usually provided by the companies for whom they work, or will be acquired through the course of their cumulative work experience. Unfortunately, an important ingredient for success is often missing: the synthesis skills that are necessary for professionals to excel in their fields are often not taught in either of these settings. Similarly, the critical skills necessary for successful communication of ideas are also often lacking or poorly developed; failure to master these techniques can lead to recurring frustrations. This presentation aims to make the NeoGeos in attendance aware of what some of these wide-ranging skills are and will direct the attendees toward paths of analysis and self-improvement that will continue to develop throughout their careers.

Biographical Sketch:

Dr. Rusty Riese is a Consulting Geologist with BP America, Inc. in Houston, Texas. Educated in New Mexico, he has worked during his 28-year career in both minerals and petroleum as a geologist, geochemist, and manager. His research efforts have been devoted to various aspects of applied geochemistry, coalbed methane reservoir stimulation, and the techniques of predrill risk and reserves analysis. He teaches via adjunct appointments at several universities, including Rice University here in Houston, and has published widely.

HGS Emerging Technologies Dinner Meeting

"Geomorphologic, Stratigraphic, and Seismic Visualization Analysis of Deepwater Deposits"

Abstract:

Detailed seismic-geomorphologic, seismic-stratigraphic, and seismic vizualization analyses of 3-D seismic data offshore Indonesia, Nigeria, and the Gulf of Mexico, reveals the presence of extensive turbidite and debrite deposits. Key depositional elements observed include: turbidity flow leveed channels, channel overbank sediment waves, frontal splays/distributary channel complexes, and debris flow channels, lobes and sheets. These depositional elements will be described and the mode of formation discussed within the context of deep-water sedimentary process and interaction with local bathymetry.

Turbidity flow channel widths range from 2 km to less than 200 m. Sinuosity ranges from moderate to high, and channel meanders are observed to migrate in a down-system direction. High-sinuosity channels are associated with extensive sediment wave development in proximal overbank settings, especially in association with outer channel bends. The long axes of these sediment waves are oriented normal to the inferred direction of turbidity flows. These sediment waves reach heights of 20 m and spacing of 3 km. Overbank thickness decreases systematically down-system. Near to where overbank thickness can no longer be resolved seismically, high-sinuosity isolated channels feed low-sinuosity distributary channel complexes/frontal splays. Low sinuosity distributary channel complexes are expressed as lobate sheets, in excess of 5-10 km wide and potentially 10's of km long. Notably, they appear to be characterized by channelized flow all the way to the edges of these systems.

Debrite deposits are in the form of low-sinuosity channel fill, narrow elongate lobes, and sheets. These deposits are characterized seismically by a contorted, chaotic seismic facies that commonly overlies a striated/grooved pavement. These striations/grooves can be up to 10's of kilometers long, 15 m deep, and 25 m wide. In areas where flows are unconfined, striation patterns suggest that divergent flow is common. Within the constraints of the seismic data coverage, the debrite deposits extend as far basinward as the turbidite deposits. Individual debrite units reach 80 m in thickness.

Examples utilizing different visualization techniques will be presented. Other examples and techniques will also be shown by Veritas Exploration Services in the Vendor's Corner during the social hour.

Biographical Sketch:

Dr. Henry W. Posamentier
Senior Technology Advisor Dr. Posamentier joined Veritas as a Senior Technology Advisor based in Calgary. Prior, he was a Senior Exploration Advisor with ARCO Indonesia Inc., concentrating on ARCO's exploration and Production offshore, Java. He has employed an interdisciplinary approach using borehole and seismic data to unravel basin fill histories. Most recently, he has focused on seismic geomorphology, using 3D seismic volumes to identify and characterize elements of depositional systems. In addition to working with ARCO from 1991-2000, Dr. Posamentier was with Exxon Production Research Company, and Esso Resources Canada, Ltd. and was Assistant Professor of Geology at Rider University for 5 years.

While at Exxon, he was part of the team that pioneered the development of sequence stratigraphy, which remains one of his research interests. In 1971-1972, Dr. Posamentier was a Fulbright Fellow to Austria. He has served as an AAPG Distinguished Lecturer to the United States (1991-1992), an AAPG Distinguished Lecturer to the former Soviet Union (1996-1997), and an AAPG Distinguished Lecturer to the Middle East (1998-1999). Dr. Posamentier holds a Ph.D. in Geology from Syracuse University.

HGS Lunch Meeting

"Developing an Exploration Tool in a Mature Trend: a 3D AVO Case Study in South Texas"

Abstract:

You can obtain this talk abstract with figures in MS Word format. The file is large, however, 1.6 Mg. Right-Click here and choose the "Save-As" option to save this file to your hard drive. Then use MS Word to open up the file and view it.

Summary

Successful exploration for new reservoirs in mature trends often requires trying techniques unproven in the area. The Vicksburg Formation in South Texas has been heavily explored using subsurface geology and structural mapping based on conventional seismic data. Although there is a scarcity of direct hydrocarbon indicators such as bright spots, models generated using dipole sonic data suggested that Class 2 AVO anomalies would be associated with gas reservoirs. A pilot reprocessing study demonstrated that gas reservoirs generate Class 2 AVO anomalies and that incident angles greater than about 26º are required to observe them. A large non-exclusive 3D survey was reprocessed using non-hyperbolic moveout and resulting angle stacks were analyzed. Several untested anomalies were identified, including stratigraphic traps. Wildcat drilling based on this effort has resulted in six commercial discoveries and two dry holes, a success rate significantly higher than was achieved through conventional subsurface geology and structural mapping.

Introduction

The clastic Oligocene Vicksburg Formation in Starr and Hidalgo Counties in South Texas has produced over 100 MMBO and 3 TCFG since production began in the 1920's and is densely drilled. Exploration efforts have typically utilized subsurface geology along with structural and stratigraphic interpretation of seismic data to identify and evaluate prospective exploration targets. There are very few examples of bright or flat spots in the section.

A large non-exclusive 3D seismic survey was acquired in the area in 1994 and has led to increased industry activity. The prime motive for the 3D was to image the complex faulting in the Vicksburg. Typical exploration targets are moderate-potential compartments in productive intervals and higher-potential targets in deeper, untested section.

In 1995, Edge Petroleum licensed a 450 square mile portion of the non-exclusive 3D survey. Several moderate-potential untested Vicksburg structural traps were identified and drilled, resulting in one commercial gas discovery, one non-commercial discovery and three dry holes, a 20% success rate. These disappointing results prompted us to search for an exploration tool that would help us to improve our success rate.

Two of the prospects drilled in our initial exploration campaign are illustrated in Figure 1. Our technical evaluation showed the prospects to have analogous stratigraphy, structure, timing of trap formation and proximity to source. Drilling found the predicted reservoir facies in both cases, but one was a commercial gas accumulation while the other was wet. Perplexed by these results, we selected these two prospects as our laboratory for developing a better risk-assessment technique.

Developing the AVO Tool

To better understand rock properties of the target reservoir intervals in the two wells, we acquired comprehensive log suites including dipole sonic data. As illustrated in Figure 2, there are small contrasts in acoustic impedance between gas and wet sands and encasing shales. However, Poisson's ratio in the gas sand is significantly lower than in both the encasing shales and the wet sand.

Synthetic CDP gathers were modeled using the log data to predict AVO behavior and are shown in Figure 3. For small velocity variations, Shuey's (1985) approximation of the reflection coefficient equation, as modified by Verm and Hilterman (1995, see Appendix), shows that the primary determinants of near- and far-offset reflectivity can be represented as acoustic impedance and Poisson's ratio, respectively. Thus, as observed on modeled gathers, the small acoustic impedance contrast at the top of the gas reservoir results in a weak reflection at near offsets while the strongly-negative Poisson's ratio contrast results in a strong negative reflection at far offsets, a Class 2 AVO anomaly (Rutherford and Williams, 1989). The recognizable onset of the far-offset anomaly is at an offset equivalent to reservoir depth, about 5600 ft, or at an incident angle of around 26º. For ease of reference, incident angles are estimated using a straight-raypath approximation. The tops of the water sands exhibit positive reflections at near offsets that weaken with offset. The modeling study encouraged us to conduct a pilot pre-stack reprocessing project to test the hypothesis that Vicksburg gas fields produce Class 2 AVO anomalies.

The non-exclusive 3D data set was acquired by Western Geophysical with a field bin size of 82.5 x 82.5 feet, far offsets of 14,800 feet, 30- to 60-fold coverage and a Vibroseis source with a sweep of 8-80 Hz. Reprocessing, conducted by Geophysical Development Corporation, included non-hyperbolic moveout based on a transversely-isotropic shale model (Tsvankin and Thomsen, 1994 and Hilterman et al, 1998). Usable data were generated at incident angles in excess of 40 degrees.

CDP gathers through the two test wells are shown in Figure 4 with both normal and non-hyperbolic moveout applied. The difference in AVO character between the gas and wet sands is obvious: the gas reservoir produces a distinct Class 2 AVO anomaly while the wet sands do not. Moreover, the strong, far-offset reflectivity that characterizes the Class 2 anomaly is best developed only at incident angles greater than about 23º. Much of the data at higher incident angles would be muted on a stack processed with conventional normal moveout, evident in Figure 4.

Near (0-168) and far (26-458) angle stacks through the two test wells are shown in Figure 5. The gas reservoir is clearly anomalous on the far-angle stack while the wet reservoir is not. These results further encouraged us to reprocess a 320 square mile portion of the 3D survey.

An analysis of the large, reprocessed volume was conducted by comparing near- and far-angle stacks. The analysis generated two interesting statistics. First, of the approximately 100 Vicksburg gas wells in the study area with cumulative production greater than 1 BCF, about half were associated with Class 2 AVO anomalies. No other anomaly types were observed. Second, of the approximately 70 drilled anomalies that appeared to be geologically valid targets, about two-thirds were commercial gas accumulations. Thus, use of the near- and far-angle stacks to identify prospective Class 2 AVO anomalies in the Vicksburg appeared to be a valid exploration tool and would be expected to yield a success rate of around 65%.

Implementing the AVO Tool

Reconnaissance exploration in the reprocessed data set was conducted by visualizing anomalies in the far-angle stack using Landmark's Earthcube software. To accomplish this, a large volume of the far-angle stack was loaded into a workstation along with productive well data. Opacity settings were adjusted to highlight far-angle anomalies, resulting in a 3D image of the subsurface in which the anomalies visually "popped out" of the data (Figure 6).

Known gas reservoirs were readily catalogued as productive analogues and untested anomalies were quickly identified as exploration targets. These prospective anomalies and associated CDP gathers were further analyzed to check for correct polarity, lateral continuity and consistency of downdip limits as well as conventional exploration evaluation including subsurface geology and structural mapping. Several valid prospects emerged from this work. The first test of our new AVO tool is depicted in Figure 7. Subsurface control suggested that an untested anomaly at about 7000 ft was correlative with a sand interval seen in a downdip well and associated with a gas show. As illustrated on the structure map, the AVO anomaly did not fully conform to structure and was observed to terminate along strike of a dry hole in which the sand was absent. Thus, the prospect had both stratigraphic and structural trapping components. Although the trap style was risky, the strength of the AVO anomaly gave us the confidence to drill. The wildcat found a 100 ft interval with 72 ft of net pay and produced at an initial rate of 3 MMCFD/85BCPD. A second AVO discovery is shown in Figure 8. A Class 2 anomaly was identified on trend with a productive anomaly in an adjacent gas field. Although quality of the conventional stack was poor, relatively continuous events on the far-angle stack allowed us to generate a structure map, revealing an untested fault compartment. The wildcat found two gas zones, explaining the multiple anomalies seen on the far-angle stack. The upper zone was 54 ft thick with 28 ft of net pay and the lower was 214 ft thick with 145 ft of net pay. The well produced at an initial rate of 5.3 MMCFD/ 112 BCPD.

To date, our exploration campaign based on AVO anomalies in the Vicksburg has resulted in six commercial discoveries, including two stratigraphic traps. We also drilled two dry holes, a result of drilling Class 2 anomalies caused by reservoirs with low gas saturation. This 75% success rate is similar to the 65% that was predicted by statistical analysis and represents a dramatic improvement over the 20% we realized with conventional subsurface and structural mapping work.

Conclusions

Our initial exploration efforts in the South Texas Vicksburg were based on the assumption that a new non-exclusive 3D survey would lead us to untested compartments in productive intervals. However, the inherent risks in this method yielded a disappointing success rate. A search for a better risk-assessment approach led to the development of an AVO tool. Lessons we learned in this process include:

Development of an AVO-based exploration tool to identify and risk prospects in a mature producing trend allowed us to harvest remaining potential in a variety of ways:

Acknowledgements

The authors gratefully acknowledge Edge Petroleum Corporation for permission to publish this work and John Hastings for his many contributions. We also wish to thank Geophysical Development Corporation for their excellent work, especially Connie Van Schuyver for data processing and Kevin Chesser for petrophysical analysis. Finally, we thank Western Geophysical for permission to use excerpts from their non-exclusive 3D seismic survey.

References

Hilterman, F., Sherwood, J. W. C., Schellhorn, R., Bankhead, B., and DeVault, B., 1998, Identification of lithology in the Gulf of Mexico: The Leading Edge, Vol.17, p 215-222

Rutherford, S. R., and Williams, R. H., 1989, Amplitude-versus-offset variations in gas sands: Geophysics, Vol. 54, p 680-688

Shuey, R. T., 1985, A simplification of the Zoeppritz equations: Geophysics, Vol. 50, p 609-614

Tsvankin, I., and Thomsen, L., 1994, Nonhyperbolic reflection moveout in anisotropic media: Geophysics, Vol. 59, p 1290-1304

Verm, R., and Hilterman, F., 1995, Lithology color-coded seismic sections: The calibration of AVO crossplotting to rock properties: The Leading Edge, Vol. 14, p 847-853

Appendix

Shuey's (1985) approximation of the reflection coefficient equation, as modified by Verm and Hilterman (1995), is:

RC(q) @ NI cos2(q) + PR sin2(q)

Where NI = Normal incidence reflectivity = (r2V2-r1V1)/(r2V2 +r1V1), PR = Poisson reflectivity = (s2-s1)/(1-savg)2, and r, V and s are respectively the density, P-wave velocity and Poisson's ratio for the lower medium (2) and the upper medium (1), and savg is (s2+s1)/2. This two-term approximation is valid for small velocity variations.

Biographical Sketch:

Mark Gregg began his career in 1981 with The Superior Oil Company, later with Mobil Oil, working Gulf of Mexico lease sales. Following the joining of Superior and Mobil in 1984, his career with the merged company included several years in Indonesia, where he explored in the Timor Sea and supervised jungle seismic operations, and several years in Nigeria, where he helped lead a successful Niger Delta exploration effort. Gregg returned to the US in 1995 to assist Mobil's global new ventures group in a business advisory capacity. In 1996 he joined Edge Petroleum Corporation in Houston, where he explored along the Gulf Coast. He recently established KiwiEnergy, Ltd., an E&P independent based in Houston. His exploration approach includes an emphasis on using geophysical tools to identify exploration opportunities and quantify associated risk. Gregg received a B.Sc. in geophysical engineering in 1980 from the Colorado School of Mines and an MBA from the University of Houston in 1988.

HGS North American Exploration Dinner Meeting

"New Exploration Concepts for the Lower Cretaceous Shelf Margin Carbonates of Texas"

Abstract:

Cretaceous Margin Model

Stratigraphic studies, focusing on the Lower Cretaceous Edwards and Sligo margins in east central Texas, suggest new exploration opportunities. One is based on an extension of the favorable stratigraphy of the Edwards beyond the commonly recognized shelf margin; and another on recognizing that the Sligo margin underwent a major period of exposure resulting in deposition of downslope debris wedges. These examples show how new exploration ideas can be developed in mature areas when new tools and approaches are utilized.

The Edwards - An Underdrilled Opportunity

Analysis of well cuttings and core, coupled with detailed seismic correlation, confirms that the Edwards margin consists of both grainstone and reef facies and shows that both sets of facies repeat themselves several times within the Edwards as the margin prograded. The Edwards margin prograded southeastward >5 km beyond the Sligo margin placing prospective backreef and reef grainstones far seaward of the commonly recognized margin. In essence, there are equivalent facies to those of the Word field complex, a mature Edwards gas field producing at a depth of approximately 3962 m, downdip of the field but the facies lack the underpinning of the Sligo margin for structural drape. The extent of this "opportunity fairway" within Lavaca County alone is over 4.8 km in width and 40 km in length.

3-D seismic and a corresponding geologic cross section show the progradational nature of the Edwards in detail. Three Edwards sequences defined by four key reflectors on the 3-D data occur within one sequence on the 2-D seismic. Reflector 1, which is a high-amplitude event downdip that diminishes in strength updip, occurs at the top of an interval of deeper water argillaceous wackestones (Upper Tamaulipas). Reflector 1 is immediately overlain by a prograding reef/bank complex and distal slope wackestones of the Edwards margin as seen in cores and cuttings. Reflector 2 is a weak event that ties lagoonal packstone/grainstones to a reef and bank complex and eventually forereef and slope deposits. Reflectors 3 and 4 tie backreef wackestone/packstones to reef and backreef grainstones. It seems clear that the "top Edwards" interval between reflectors 3 and 4 represents a progradational package whose ultimate culmination is even seaward of the study area.

The Sligo Forereef – An Untested Opportunity

A 3-D seismic line illustrates a major sequence boundary in the Sligo margin and several events on the seaward side of the margin that display onlap and downlap reflector terminations. These events exhibit the proper architecture to comprise part of a downslope debris wedge in excess of 300 m thick. Although this Sligo forereef and slope play is regional in extent throughout the northern rim of the Gulf of Mexico, the opportunity has yet to be tested.

The existence of a Sligo downslope wedge between the sequence boundary and the overlying Pearsall shale does not guarantee the presence of coarse grained material. It is likely the lowstand created a period of instability, resulting in coarse breccia and grainstone transported further downslope in the form of debris flows and sediment gravity flows. During the subsequent transgression and relative highstand, the Sligo shelf margin initially kept up with sea level rise and continued to contribute grainstone debris downslope. Rapid deposition of the downslope carbonates may have helped to preserve primary porosity by limiting the amount of marine cementation. Data from reservoir analogs confirm that such downslope carbonates can retain reservoir-quality porosity, e.g., Poza Rica field from east-central Mexico. Facies variation and slump faulting on the foreslope creates the potential for trapping and juxtaposition to deep-water carbonates sets up the source and migration pathway. Eventually, the Sligo shelf margin was flooded by a major transgression represented by the Pearsall, which would provide a top seal.

I am grateful to the following coworkers for their collaboration: Dale A. Fritz , Santa Fe Snyder Corporation, Houston, TX; Terry W. Belsher, James M. Medlin (retired), John L. Stubbs, and Robert P. Wright, Chevron U.S.A. Production Company, Houston, TX.

Biographical Sketch:

Paul M. (Mitch) Harris , of Chevron Petroleum Technology Company in Houston, Texas, performs carbonate technical support projects, consulting and training for the various operating units of Chevron. His work during the last 23 years has centered on facies-related, stratigraphic, and diagenetic problems that pertain to carbonate reservoirs and exploration plays in most carbonate basins worldwide. Mitch received his B. S. and M. S. degrees from West Virginia University and Ph.D. from the University of Miami, Florida. He has published numerous papers, edited several books, and is active in AAPG and SEPM.