February, 2002
HGS Meetings

HGS Emerging Technologies Dinner Meeting

"Oil and Water: Rocks and Models Improve Resource Understanding"

Abstract:

Sedimentary processes result in the deposition of 3-D geologic bodies that are buried and lithified, and then undergo diagenesis and structural deformation over time. These post-depositional changes cause overprints that modify, and often complicate, the pore-space distribution of the original deposit. Although geologists have had tremendous success describing 3-D and 4-D problems using 2-D renderings (maps, cross sections, tables, and graphs), the number of computer hardware and software tools has exploded over the past decade so that we can now address the 4-D nature of the problem. In some cases, original interpretations have held up nicely; in other cases, we are seeing things that we never imagined possible.

Nowhere does the application of 3-D and 4-D modeling tools have more impact than in the description and modeling of oil and water subsurface reservoirs. The modeling and visualization of complex subsurface geology, combined with the ability to model the movement of fluids and gases within and through the volume, have revolutionized our understanding of subsurface behavior. Models now help oil companies extract incremental reserves previously thought to be unrecoverable, and help hydrologists model the volume and quality of water in aquifers to forecast future resource allocations.

I will emphasize the importance of rocks to construct accurate stratigraphic and structural frameworks, and the impact of accurate frameworks on 3-D and 4-D models, using animated examples of 3-D hydrocarbon and aquifer models, mainly from Texas. We will even catch a ride on the back of a camcorder with a headlamp and head into the subsurface of West Texas to visit a classic Texas giant up close and personal!

Biographical Sketch:

Scott W. Tinker is Director of the Bureau of Economic Geology, The University of Texas at Austin, a major international energy and environmental research organization. He is the State Geologist of Texas and a Professor in UT’s Department of Geological Sciences. He is also a member of the Steering Committee of the new John A. and Katherine G. Jackson School of Geosciences.

Before joining the Bureau in 2000, he was an Advanced Senior Geologist at Marathon Oil’s Petroleum Technology Center in Littleton, Colorado, where he designed and managed studies of large oil and gas fields. He earned a PhD in geological sciences from the University of Colorado. He is an expert in energy issues and reservoir characterization of carbonate systems. A recipient of best paper awards in two major journals and former AAPG Distinguished Lecturer, he was recently selected for the 2002 inaugural series of the joint SPE/SEG/AAPG Distinguished Lecturer program. He is a member of many professional and honor societies, and is actively involved in several technical and steering committees. He is also a member of the Board of Visitors at Trinity University, the American Geological Institute Foundation, and following a recent appointment by the Lt. Governor of Texas, the Oil Field Cleanup Advisory Committee.

HGS Dinner Meeting

"Distributary Channels, Fluvial Channels or Incised Valleys?"

Abstract:

Many deltas show several orders of branching resulting in a wide range of sizes and shapes of distributary channels. There is thus no such thing as “a distributary channel” in many deltas. At the largest scale, trunk rivers become distributive at the point where the river becomes unconfined (nodal avulsion). Intermediate-scale delta plain channels tend to be few in number, may be separated by wide interfluves, and may be exceedingly difficult to distinguish from fluvial channels. The smallest scale “terminal distributaries” lie in the delta front. Because discharge decreases downstream, terminal distributary channels tend to be narrow and shallow, rather than wide and deep.

In many mid-continent reservoirs, such as the Pennsylvanian Booch sandstone in Oklahoma, 100 m thick channelized deposits cut into 10 m thick prodelta and delta front deposits, but have been historically interpreted as distributary channels. These interpretations were strongly driven by using the deep distributary channels of the Mississippi delta as a modern analog, which is probably not appropriate because it feeds into deep water, rather than an interior sea. These deeply incised channels might be better interpreted as multi-story incised valleys rather than single-story distributary channels.

Outcrop examples of terminal distributary channels in the Cretaceous Panther Tongue sandstone in Utah show multiple shallow channelized sandstones, intimately associated with more extensive delta front clinoform beds. These better match modern shoal-water deltas such as the Atchafalaya delta in the Gulf Coast.

Biographical Sketch:

Janok P. Bhattacharya is an associate professor at the University of Texas at Dallas. His research interests include deltaic sequence stratigraphy and the local control of structure on stratigraphy. He received his BSc in 1981 from Memorial University of Newfoundland, Canada, and his PhD in 1989 from McMaster University, Hamilton, Ontario, Canada. Following an NSERC post-doc at the Alberta Geological Survey in Edmonton, Janok worked for ARCO and then the Bureau of Economic Geology at Austin

HGS Environmental / Engineering Dinner Meeting

Texas Regulatory Awareness Committee (TRAC) -

HGS International Dinner Meeting

"A Review of the Petroleum Systems of the Gulf of Mexico with Emphasis on the Mexican Sub-basins: Oil Quality Distribution, Recognition of a New Petroleum System, and Remaining Petroleum Potential"

Posters:

  1. "Exploration and Reservoir Heterogeneity Implications of the composition of Natural Gases in the Macuspana Basin, Southern Gulf of Mexico"
    Angel Francisco Callejón(1), Noel Holguín Quiñones(3), Ernesto Caballero Garcia(2), and K.K. Bissada(1)
    1. Petroleum Systems and Geochemistry Unit, Department of Geosciences, University of Houston, Houston, Texas
    2. PEMEX Exploración y Producción, Subdirección Región Sur, Macuspana, Mexico
    3. PEMEX Exploración y Producción, Subdirección de Tecnología y Desarrollo Profesional, Mexico City, Mexico.

  2. "Applications of Surface Geochemical Methods in the Evaluation of Subsurface Petroleum Systems"
    V.T. Jones, III, P. N. Agostino, Reyhan Rinaldi, Jack Tennant, Exploration Technologies, Inc., Houston, Texas, USA

  3. "Satellite radar reveals repetitive strong seepage in unexplored areas of the Gulf of Mexico."
    NPA Group, UK

  4. Anouncement of 1st AAPG Memoir on geology of Mexico:
    "Western Gulf of Mexico Basin, Tectonics, Sedimentary Basins and Petroleum Systems, AAPG Memoir #75",
    ed. Claudio Bartolini, IHS Energy
Vendors:

Abstract:

The Gulf of Mexico is a prolific basin with multiple source rocks that are Jurassic, Cretaceous and Tertiary in age. Oil quality distribution in the subsurface is controlled primarily by the characteristics of the source rocks. For example, carbonate source rocks contain marine, sulfur-rich organic matter and yield oils high in asphaltene compounds and sulfur. In contrast, siliciclastic source rocks contain a mixture of marine and terrestrial organic matter and yield waxy, low sulfur oils with greater gas-oil-ratio. In the Gulf of Mexico, the Mesozoic source rocks are generally carbonate whereas Tertiary source rocks are siliciclastic.

In the northern Gulf of Mexico, petroleum generated from Jurassic and Cretaceous source rock has been recognized in the inner onshore region, whereas Tertiary sourced oils and gases are found in the onshore and continental shelf areas (Figure 1) . Oils generated from Mesozoic sequences are pervasive in the deep Gulf of Mexico (Gross et al., 1995). On the Mexican side of the Gulf of Mexico, subbasins also contain oil and gas of different origins.

Burgos Basin

The Tertiary Burgos Basin produces gas and condensate from reservoirs that consist of sand deposited as bars and wide, thin-bed deposits at the front of Paleocene, Eocene, Oligocene, and Miocene prograding deltaic systems.

Although the Mesozoic sequences, such as the Kimmeridgian - Tithonian La Casita Fm., Aptian La Peña Fm., and Turonian Eagle Ford Fm. are rich in organic matter, they are spent source rocks, and did not contribute to the commercial accumulations in the basin. Active source rocks are the Paleocene-Eocene Midway-Wilcox Fms. and Oligocene Vicksburg Fm. sequences that contain a gas-prone Type III kerogen (Echanove-Echanove, 1986; Gonzalez-Garcia y Holguin-Quiñones, 1992) .

The trapped hydrocarbons have been generated at more than 4 km depth and migrated along the listric and growth fault systems that affected the whole Tertiary section. Exploration in this basin is being revitalized with the search for gas in deeper traps, secondary recovery techniques, infill drilling and looking for new prospective areas on the offshore where there is a great potential for accumulations of hydrocarbons (Yañez-Mondragon, 2002).

Tampico-Misantla Basin

The Tampico-Misantla basin produces high sulfur oil of variable quality (e.g., 15 to 40o API gravity) and associated gas. Production comes from stratigraphic, and mixed structural-stratigraphic traps with naturally fractured carbonate reservoirs in Upper Jurassic San Andres Fm., Cretaceous El Abra , Tamabra and Tamaulipas Superior Fms., and clastic reservoirs in the Eocene Chicontepec Fm.

In the central part of the basin, oil and associated gas were generated from Upper Jurassic source rocks, whereas to the west, light oil, condensate and gas were generated from the Lower Jurassic Huayacocotla Fm. (Morelos-Garcia, 1996; Roman-Ramos y Holguin-Quiñones, 2002). In the Sierra Madre Oriental, an oil seep sample suggests that oil charge must have come from a carbonate source rock deposited in an anoxic, hypersaline, shallow water environment (platform). This new evidence suggests that within the Cretaceous Valles San Luis Potosi Platform, there are source rocks that could have charged the Sierra Madre Oriental and adjacent regions. In the Sierra El Abra, an exhumed reservoir contains oil in the moldic porosity of rudist build-ups of the El Abra Fm. This reservoir shows a complex hydrocarbon charging history (Pottorf et al., 1996).

Petroleum activity in this basin is focused on the rehabilitation of mature oil fields, development of the Chicontepec trend and offshore exploration (Yañez-Mondragon, 2002).

Veracruz Basin

The Veracruz Basin is divided into the Tectonic Buried Platform and Veracruz Tertiary Sedimentary Basin.

Tectonic Buried Platform

The stratigraphic section of the Tectonic Buried Platform comprises Upper Jurassic to Early Eocene sequences that were deformed and thrusted during the Middle Eocene. This region contains high sulfur oil and associated gas in structural traps of Cretaceous age (Orizaba, San Felipe and Guzmantla Fms). Active source rocks have been identified in the Upper Jurassic Tepexilotla Fm., Turonian Maltrata Fm. and Aptian-Albian Orizaba Fm.

Veracruz Tertiary Sedimentary Basin.

The stratigraphic section of the Veracruz Sedimentary Basin includes a thickness of more than 8 km of Tertiary terrigenoclastic sediments, and Cretaceous and Upper Jurassic sequences that have not been penetrated. This region produces mainly gas and minor volumes of condensate and oil from Miocene and Pliocene stratigraphic reservoirs. Although it is inferred that Mesozoic source rocks are present, they are most likely spent and may have contributed only minor gas and some oil. Paleocene-Eocene and Miocene sedimentary sequences contain fair to good source rocks with gas-prone Type III kerogen, and are the most likely source of the hydrocarbons trapped locally (Roman-Ramos y Holguin-Quiñones, 2002).

Exploration in the Veracruz basin is concentrated in the Tertiary Sedimentary Basin, which has a great potential for gas discoveries.

Southeastern Basins and Campeche Bay Region

The southeastern basins include the contiguous Salina del Istmo, Chiapas-Tabasco, and Macuspana basins, and the Campeche Marine Platform. These basins have a common geological history during the Mesozoic, and a different structural and stratigraphic development since the Tertiary. Source rocks have been identified in the Upper Jurassic (Tithonian), Middle Eocene, Oligocene and Middle Miocene sections (Sosa-Patron y Clara-Valdez, 2002)

Salina del Istmo

Several giant oil fields in the Salina del Istmo Basin produce oil of about 35 oAPI and associated gas. The main reservoirs are Miocene and Pliocene sequences in stratigraphic-structural traps developed by salt tectonism. Source of these hydrocarbons has been identified as Upper Jurassic (Guzman-Vega, Mello, 1999)

Chiapas-Tabasco Basin

The Chiapas-Tabasco Basin produces oil and associated gas from combined stratigraphic-structural traps of Upper and Lower Cretaceous age reservoirs. These hydrocarbons were generated from Upper Jurassic source rocks. To the south, some oils correlate with Cretaceous carbonate source rocks that were deposited in a platform environment of hypersaline conditions (Guzman-Vega-Mello, 1999).

Macuspana Basin

The Macuspana Basin is a gas producing basin with minor production of condensate and oil. Gases are a mixture of biogenic and thermogenic, and thermogenic of variable maturity. Thermogenic gases were produced from primary cracking of Tertiary source rocks and probably secondary cracking from Upper Jurassic source rocks (Sosa Patron, et al., 2002)

Campeche Marine Platform

The Campeche Marine Platform is the richest oil region in Mexico, and contains several giant oil fields, including the Cantarell Trend. Three stratigraphic sections have been identified as source rocks in this region: Oxfordian, Tithonian and Miocene sequences (Santamaria, et al., 1998; Sosa-Patron and Clara-Valdez, 2002). The Oxfordian source rock appears to be of limited geographic extent, and is only active in the north, whereas the potential Miocene source is more widespread. However, the Tithonian is clearly the source of most of the hydrocarbons trapped in the region (Romero-Ibarra et al., 2002).

The southern basins have been producing oil and gas since the early 70’s and, this region has still great potential for new discoveries.

Offshore Mexico as well as the deep and ultradeep regions of the Gulf of Mexico are frontier regions of oil exploration. Regional work on the petroleum systems suggests that the Tertiary section will be an important source of hydrocarbons on the western side of the Gulf of Mexico, close to the shoreline (Figure 1). Likewise, evidence of oil from the Challenger Knoll and regional trends suggest that the Mesozoic section (e.g., Upper Jurassic) will be the most important source of hydrocarbons in the deep and ultradeep regions of the Gulf of Mexico.

References

Echanove-Echanove, O. 1986, Geologia petrolera de la Cuenca de Burgos. Consideraciones geologicas-petroleras: Boletin Assoc. Mex. Geol. Petr., v. XXVIII, p. 3-74.
Gonzalez-Garcia, , R., y N. Holguin Quiñones, 1992, Las rocas generadoras de Mexico: Boletin Assoc. Mex. Geol. Petr., v. XLII, p. 16-30.
Gross, O.P., K.C.Hood, L.M. Wenger, and S. C. Harrison, 1995, Seismic Imaging and analysis of source and migration within an integrated hydrocarbon system study: Northern Gulf of Mexico: 1st Latin American Geophysical Conference, Rio de Janeiro, Brazil, Extended abstract.
Guzman-Vega, M. A., and M.R. Mello, 1999, Origin of oil in the Sureste Basin, Mexico: AAPG Bulletin, v. 83, p. 1068-1095.
Morelos-Garcia, J.A., 1996, Organic Geochemistry of southern Tampico-Misantla basin, Mexico: Oil-oil and oil-source rocks correlation: Dissertation, University of Texas at Dallas, 635 p.
Pottorf, R.J., G.G. Gray, M. G. Kozar, W.M. Fitchen, M. Richardson, R. Chuchla, and D.A. Yurewicz, 1996, Hydrocarbon generation anf migration in the Tampico-segment of the Sierra Madre Oriental Fold-Thrust Belt: Evdence from an exhumed oil field in the Sierra de El Abra: in, M.E. Gomez-Luna and A. Martinez -Cortez, eds., Memorias del Congreso Latinoamericano de Geoquimica Organica, Cancun, Mexico, p. 100-101.
Roman-Ramos, J.R., y N. Holguin-Quiñones, 2002, Subsistemas generadores de la region norte de Mexico: Boletin Assoc. Mex. Geol. Petr., v. XLIX, p.68-84.
Romero-Ibarra, M.A., L.Medrano-Morales, y R.Maldonado-Villalon, 2002, Subsistemas generadores del area marina de Campeche, Mexico: Boletin Assoc. Mex. Geol. Petr., v. XLIX, p.105-115.
Santamaria, O.D., R. di Primio,B. Horsfield, and D.H. Welte, 1998, Influence of maturity on sulphur-compounds in Tithonian source rocks and crude oils, Sonda de Campeche, Mexico: Org. Geochem., v. 28, p. 423-439.
Sosa-Patron, A. A., P.R. Philp, y E. Caballero-Garcia, 2002, Caracterizacion genetica de los gases de la Cuenca de Macuspana: Boletin AMGP, v. XLIX, p. 143-144.
Sosa-Patron, A.A., y L. Clara-Valdez, 2002, Subsistemas generadores del sureste de Mexico: Boletin Assoc. Mex. Geol. Petr., v. XLIX, p. 85-104.
Yañez-Mondragon, M., 2002, Mexico’s northern region launches massive development: World Oil, November 2002, p. 69-70.

Biographical Sketch:

J. Alejandro Morelos-Garcia graduated with a B.S. in Geological Engineering from the Instituto Polytecnico Nacional (Mexico), and a Ph.D. in Geosciences from the University of Texas at Dallas. His senior thesis and dissertation covered the petroleum systems of the Veracruz and Tampico-Misantla basins in Mexico. His areas of expertise include geochemistry, basin modeling and petroleum system analysis, with special emphasis on integrating geochemical data into regional geologic models. He has worked with several integrated oil companies, independents, and service companies, including the deepwater Gulf of Mexico assessment team for Spirit 76 (Unocal). His areas of geographic expertise include Central and South America, Central and South Asia, and the Gulf of Mexico. Alex is currently a consultant dedicated to basin evaluation, petroleum systems assessment, and reservoir characterization. Tel: (281) 752-5040 email: morelos-roths@att.net

HGS North American Exploration Dinner Meeting

"Integrated Analysis Of The Upper Jurassic Bossier Deltaic Complex, East Texas"

Abstract:

The sandstones encased within the Bossier shale Member of the Cotton Valley Sandstone in East Texas are subdivided into 3 genetically related stratigraphic cycles. The lower deltaic cycle is a seaward-stepping unit that becomes reworked as a result of delta switching with the upper cycles characterized primarily as aggradational to progradational units. Facies range from delta-fed gravity-flow to delta-front to distributary-channel deposits.

Previous interpretations have ranged from submarine-fan to braided river with individual cycles interpreted to be bounded by regionally extensive marine flooding surfaces. Detailed sedimentologic, petrologic, and biostratigraphic analyses of well-logs, and cores, however, indicate that the stacking pattern of the Bossier deltaic complex is controlled by autocyclic lobe-switching as a result of varying sediment supply (overall increase) associated with the large Cotton Valley fluvial system. In particular, detailed biostratigraphic analysis (i.e. palynology, micropaleontology, etc.) suggests that bounding shale intervals and "flooding surfaces" exhibit a high terrigenous/marginal marine signature. True marine flooding events are associated only with the source-rock shales in the underlying Lower Bossier shale interval. Additionally, the abundance of distributary channels associated with all cycles suggests the entire Bossier sandstone section is a river-dominated system subordinately influenced by marine processes.

Rock physics and seismic modeling of the Bossier sands have demonstrated a seismic response strongly dominated by large acoustic impedance contrasts associated with porous sandstones, low porosity siltstones and over-pressured shales. Depositional and sedimentological characteristics of the Bossier sands strongly resemble characteristics of a modern-day fluvial dominated deltaic system (i.e. Mississippi River) undergoing processes of delta-switching and abandonment.

Biographical Sketch:

John Wagner received both his B.S. and M.S. degrees in geology from Louisiana State University in Baton Rouge and his Ph.D. in geology at The University of Texas at Dallas. From 1989 to 1998, John worked for Mobil Oil beginning as an exploration geologist for Mobil Exploration and Producing U. S. in New Orleans, Louisiana. He then transferred in 1991 to work as an international consultant for depositional systems analysis at Mobil Exploration & Producing Services in Dallas, Texas and in 1995 to Senior Staff Geologist for Mobil’s Exploration & Producing Research Technical Center in Dallas, Texas. From February of 1998 to December of 2000, John worked for Pioneer Natural Resources as Sedimentologist/Stratigrapher for Worldwide Exploitation and Development. He joined Nexen Petroleum in December of 2000 (previously known as Canadian Occidental) as Sedimentologist for Deep-water Exploration and Development. Prior to his 10 years at Mobil, his work ranged from field geologist in Alaska, to manager of a seismic crew, to coastal geologist for the Louisiana Geological Survey Coastal Geology Program. He was a scientist on board the 1985 USGS/IOS GLORIA survey of the deep-water Mississippi Fan, Gulf of Mexico. He is a member of both the AAPG and SEPM and has served on Program Committees for the Gulf Coast Section Society of Economic Paleontologists and Mineralogists (GCSSEPM) Foundation Annual Research Conferences. John’s teaching interest began in 1995 when he began co-leading the Mobil sandstone field seminar and lecturing abroad to international offices. His work travels have taken him from the rivers and streams of Sakhalin Island Russia, to the coast of Vietnam, to the jungles and mountains of Bolivia and Argentina. His research interests are in sandstone sedimentology, depositional systems analysis, and understanding the various allocyclic and autocyclic controls that influence deposition.

Kimberly M. Stevens received her B.A. degree in Geology from Southern Methodist University in 1994. She began working as an associate geologist with Hunt Oil before joining Pioneer Natural Resources in 1997. Kimberly is currently a Geologist in Pioneer's Domestic Exploitation & Development group. She has worked development and acquisition projects in both the Permian and East Texas Basin areas. Kimberly is a member of both AAPG and the Dallas Geological Society. Her research interest is in siliciclastic depositional processes, specifically in understanding the relationship between fluvial-deltaic systems on the shelf and time-equivalent deposition in the deep-marine basin. She will be pursuing her Master's degree starting in Spring of 2002.

HGS Lunch Meeting

"Coalbed Methane Potential in Texas"

Abstract:

The natural gas that is retained by coalbeds in the subsurface is commonly referred to as coalbed methane (CBM). It is also known as coal mine methane (CMM) when it is liberated during mining operations. Gases are generated in-situ during coalification and some are adsorbed on the coal’s internal surface area. CBM production now accounts for approximately 8% of the total natural gas production in the United States and is rapidly growing. CBM is produced commercially in many basins in the United States, with the potential for commercial production in other areas, notably the Gulf Coast Basin of Texas.

Coals have a much larger storage capacity for natural gas than porous sandstones or carbonates, meaning that a large resource of coal can contain extremely large volumes of natural gas. However, in addition to gas content, several key factors influence the commercial producibility of coals, most notably permeability, rank of the coal and its thickness and lateral extent. A detailed geologic assessment of the coal and coalbed methane resource is a critical component of CBM prospect development and evaluation.

In Texas, coals ranging in age from Pennsylvanian to Eocene and in rank from lignite to bituminous have potential for CBM production. Wells have been drilled in South Texas to test Cretaceous Olmos coals, in Central Texas to test Eocene Wilcox coals and in West Texas to test Pennsylvanian coals. It is very early in the evaluation stage and CBM has yet to be proved commercial in Texas; however, the potential for commercial CBM production is high.

As with “conventional” natural gas, a producer/developer may sell CBM to the natural gas market or use it onsite for power generation. In addition to those options, CBM can be produced in conjunction with CO2 sequestration from power generation facilities and can qualify for greenhouse gas credits and severance tax credits. CBM production has project issues that are similar to conventional natural gas production, with the key issue typically being disposal of produced water.

Biographical Sketch:

John C. Griffiths the President of Calvin Resources, Inc., is a Certified Petroleum Geologist with over 26 years experience in resource management, generation, evaluation and financing of exploratory and development projects, and asset evaluation for acquisition or divestiture. Mr. Griffiths graduated from the University of Texas and started his career as an exploration geologist for Texas Oil & Gas Corp. in Houston in 1975.

Raymond C. Pilcher is President of Raven Ridge Resources, Incorporated. Mr. Pilcher received a BS in geology from University of Texas at Austin in 1975. He has worked more than 25 years in petroleum and mining industries. His experience includes domestic and international exploration and development, project planning and management, economic evaluation, and corporate planning and development. During the last decade, he has led or participated in numerous domestic and international projects undertaken to develop coalbed methane and coal mine gas and other energy resources for a variety of private sector clients as well as public entities including U.S. EPA, UNDP, APEC, and The World Bank. He has worked and traveled extensively in Western and Eastern Europe, the former Soviet Union, and Asia. Mr. Pilcher is actively leading Raven Ridge toward developing equity positions in international and domestic coalbed and coal mine methane projects. He is a member of the Board of Directors for two companies in which Raven Ridge is a substantial stockholder, CBM Energy Limited and Gas Separation Technology, LLC.