December, 2002
HGS Meetings

HGS North American Exploration Dinner Meeting

"Grayson Field, Jurassic Smackover Reservoir, Columbia County, AR: A Case Study Using Leading Edge Reservoir Characterization Seismic Processing of 3D Seismic Data."

Figure: Log data plotted vs seismic amplitude. Click here

Abstract:

The discovery well at Grayson Field was drilled on a four-way dip closure defined by three 2D seismic lines. Investors were hoping to find a maximum of 100 feet of pay. After the discovery of 158 feet of pay at 8000 feet measured depth in the Jurassic Smackover limestone in January 1993, the participants decided that a 3D seismic program was needed. The objective of the 3D seismic program was to define the structural and stratigraphic limits of the new field.

Specific processing and interpretive tools will be illustrated with many different seismic displays. Evidence will be presented that 1) relative amplitude of the Smackover reflector does not define the reservoir’s stratigraphic parameters, 2) attributes of the Acoustic Impedance data (Inversion) shows good statistical correlation to key reservoir parameters, 3) A.V.O. shows a hydrocarbon indicator over the reservoir, and 4) reservoir characterization data (petrophysical volumes generated with Hampson-Russell Emerge software) generated with the 3D seismic data delineates the production.

The Grayson field Smackover reservoir was originally divided into two zones. The upper 35 feet of the reservoir is dolomitic lime with high porosity (20-25%) and moderate to low spotty permeability of 10-100 md. The main pay zone is approximately 40 feet below the top of the Smackover. It has primary oolitic porosity of 17-20% with permeabilities into the darcies. The separation between the pay zones ranges from one to ten feet. Through the use of this fully integrated sub-surface well information and 3D seismic data set, the thinner upper pay interval can be discerned from the thicker main pay. Horizontal well programs have been designed using the 3D seismic data to exploit the best porosity and permeability in the upper pay interval. Vertical wells adequately drain the main, lower pay interval.

In July of 1995 gas injection was begun in the field. In February 1998 a water flood program replaced the gas injection. In-fill drilling was needed to optimize the production. The 3D seismic data was needed for this work, but the resolution of the reservoir was not really clear enough on the original processing. Reprocessing of the data set with “state-of-the-art” parameters such as detailed editing of each shot record, pre-stack time migration, and post stack inversion (acoustic impedance), A.V.O., and Petrophysical cubes was needed. The full integration of the entire suite of logs from every well in the area into the post-stack processing of the 3D data yielded multiple data volumes. The bandwidth of the reprocessed data is 15-90 hertz, with a dominant frequency of 43 hertz. With the broad bandwidth and integration of the well log information, the new data volumes show the stratigraphic components of the reservoir very clearly.

Tuning thickness of the wavelet at the Smackover level is 9 milliseconds (approximately 54 feet). Identification of the upper and lower pay intervals is very difficult because the upper zone is thinner than tuning. The two pay zones appear to merge into one thick, high amplitude seismic event.

The sonic and density logs from the wells were used to calibrate and generate an acoustic impedance data volume. This multi-linear regression technique yields a data volume that better defines the two layers within the reservoir. The acoustic impedance (velocity) of the upper 100 feet of the Smackover was evaluated with different attributes to see if there was a correlation to the overall reservoir. Cross-plots of certain seismic attributes exhibit a good statistical fit with the reservoir’s porosity and pore-volume maps generated from well information.

The Grayson field Smackover reservoir is a low velocity zone encased within high velocity rocks. This is a classic Type III AVO case. A positive AVO P*G (primary times gradient) response is seen at the producing wells, while no AVO P*G response is observed in the non-producing areas.

The difficulty of identifying the thin upper pay interval was overcome by making deep induction, and gas effect “seismic” volumes that could be used in conjunction with the relative amplitude, AVO, and acoustic impedance volumes. The seismic data quality was very good and a sufficient population of well bores, with the target attributes, was available. Hampson-Russell Emerge software was used for the reservoir characterization data generation. This is an artificial neural network algorithm that successfully computed the deep induction, density porosity, and neutron porosity volumes.

Cross-plotting the density porosity and neutron porosity data volumes generated a gas effect “seismic” volume. The results of this data volume were outstanding. The thick pay interval and Grayson as well as a thin stratigraphic pay at Barlow Branch Field stood out extremely well.

The hydrocarbon saturation and water saturation can be calculated using Archie’s equation with the “seismic” deep induction and density volumes. The data shows the upper and main pay intervals as well as a possible separate deeper zone. The deeper zone has produced in two wells, and it was originally thought to be connected to the main pay zone. However the new processing shows this zone to be separated from the main pay zone by at least 15 feet throughout the field. Further evaluation of this interval is ongoing.

The acoustic impedance data shows low velocity (porosity) extending outside of the known producing limits of the field while the oil and water saturation volumes show the definitive limits of the pay interval. The oil and water saturation volumes also more clearly define the separation of the three different pay zones within the reservoir.

Conclusion:

3D seismic data was a significant asset in the development of Grayson field. The 3D seismic data allowed Petro-Chem Operating Company to drill the best structural locations within the field. Reprocessing the 3D seismic data brought out the stratigraphic nuances of the field. The relative amplitude strength of the top Smackover reflector does not define any reservoir parameters.

The acoustic impedance data volume shows a good statistical correlation to the gross reservoir parameters of the upper 100 feet of the Smackover. Multi-attribute inversion using an artificial neural network algorithm (Emerge) successfully computed the deep induction, density porosity, and neutron porosity volumes. “Seismic” volumes of gas effect, water saturation, and hydrocarbon saturation clearly delineate the reservoir.

New wells drilled using these 3D seismic volumes greatly increased the production rate and ultimate recoverable reserves in the field. Recent drilling proves that the 3D seismic effort and expense was well worth the money.

Biographical Sketch:

Kevin B. Hill is a geophysical consultant with more than 25 years of broad Gulf Coast and international experience in exploration and production geophysics and geology. He is president of Hill Geophysical Consulting in Shreveport, Louisiana.

Mr. Hill specializes in integrating state-of-the-art geophysical technologies with geology, and has designed and interpreted numerous 2-D and 3-D seismic surveys in the Jurassic, Cretaceous, and Tertiary plays of the Gulf Coast basins in Texas, Louisiana, Arkansas, Mississippi and Alabama. His international work includes interpretation of over 2,000 km. of seismic in a Latin American offshore Tertiary basin, Australia, Canada, Bahrain and a large 3-D transition shoot in Trinidad.

Mr. Hill was involved in the original design of the Kingdom PC based 3D seismic workstation software. He teaches courses on using Seismic Micro-Technology, Inc. Kingdom software at schools around the world. His schools include data loading, interpretation, mapping, post-stack processing, stratigraphic analysis, synthetics, modeling, 3-D visualization, and presentation techniques.

Hill received a BS-Professional Degree in Geology in 1977 from Louisiana State University, Baton Rouge, LA., where he was president of Sigma Gamma Epsilon, and received the H.V. Howe award for outstanding Geology graduate. Prior to becoming a consultant in 1987, he worked as Senior Exploration Geophysicist for Sonat Exploration in Shreveport, LA; Regional Exploration Geophysicist for Forest Oil Corporation in Lafayette, LA and Jackson MS; and as a Senior Geophysicist for Cities Service Company in Tulsa, OK and Jackson, MS. Hill has authored and presented numerous technical papers at Gulf Coast professional society meetings. In 2000 he received the Third Place Excellence of Presentation Award at the 50th GCAGS convention. At the 51st GCAGS convention, in 2001, he received the First Place Excellence of Presentation award and the A.I. Levorsen Award.

Mr. Hill is a member of the American Association of Petroleum Geologists, Shreveport Geological Society, Society of Exploration Geophysicists, and is a Commandeur in the Confrerie des Chevaliers du Tastevin.

William R. Meaney is the exploration geologist with Anderson Oil & Gas, Inc. in Shreveport, Louisiana. He has worked with Anderson for over 11 years and has almost 30 years of oil and gas experience.

Bill received a BA in Geology in 1970 from Vanderbilt University, Nashville, Tennessee. He then attended graduate school at Louisiana State University in Baton Rouge, Louisiana, earning a MS in Geology in 1973.

Upon completing his course work, Bill went to work for Marathon Oil Company in Shreveport in December of 1972. He was initially assigned to work the Smackover of North Louisiana and South Arkansas. Shortly thereafter his responsibilities were shifted to the Black Warrior Basin.

Like most other Gulf Coast geologists, Bill spent the requisite time in Houston from 1975 to 1978 where he worked for Hunt Energy Corporation. There he had the opportunity to be involved in the discovery and development of Clear Branch Field in Jackson Parish, Louisiana before returning to Shreveport to go to work for Fortune Gas and Oil, Inc.

Bill’s love for the Smackover was whetted with the 1980 discovery of Corney Bayou Field in Union Parish, Louisiana, however, the ensuing years proved the elusiveness of this storied target.

After Fortune, Bill worked first for O. B. Mobley, Jr., and then as a consultant for Hurley Petroleum in Shreveport. In May, 1991 he went to work for Anderson. The first deal he reviewed and recommended to Anderson ultimately led to the discovery of Grayson Field, of which Anderson is the largest working interest owner.

Bill is a member of the American Association of Petroleum Geologists, AAPG Division of Professional Affairs, Shreveport Geological Society, and Houston Geological Society. He is a past president of the Shreveport Geological Society and has been active in the Gulf Coast Association of Geological Societies, most recently serving as GCAGS Vice Chairman and Awards Chairman of the 2001 GCAGS annual convention. Bill currently serves on AAPG’s Core and Sample Preservation Committee and Membership Committee.

GCSSEPM Foundation Bob F. Perkins Research Conference

"Sequence Stratigraphic Models for Exploration and Production"

HGS Environmental / Engineering Dinner Meeting

"Accessing Austin's Environmental and Geologic Information Resources"

Abstract:

As the Texas State Capitol and home to The University of Texas with a significant geological influence, Austin has a wealth of information that is valuable to environmental and petroleum geologists. The accessibility of collections of aerial photos, city directories, geologic maps, historical topographic maps, oil and gas well records, regulatory facility files, Sanborn maps, soil surveys, and water well logs will be reviewed. Thomas Brown of the Texas Natural Resources Information Systems (TNRIS) will join me to discuss the focus and future of the agency. TNRIS has partnerships with organizations such as the USGS that enhance the development of its programs. Included in the discussion will be the TNRIS’s role as the leading pilot on the National Map project and the applications of technology to its collections. Digital versions of aerial photographs and maps are being prepared for Internet distribution. Please join us for an overview of environmental information past, present, and future.

Biographical Sketch:

E. Scott Anderson is president of Atlas Environmental Research Inc. in Austin, Texas. The firm specializes in researching and obtaining environmental/oil & gas information from the Texas Natural Resource Conservation Commission (TNRCC) and the Texas Water Development Board (TWDB) as well as various other state and federal regulatory agencies. Mr. Anderson received a BS in geology from the University of Texas in 1992.

Thomas W. Brown is the manager of the research and distribution center of the Texas Natural Resource Information Systems (TNRIS) in Austin, Texas. He was awarded a BS in geography from Southwest Texas State University in 1996.

HGS International Dinner Meeting

"Integrated Subsurface Characterization of the Bonga Field, Offshore Nigeria"

Poster Session: Click here

Abstract:

The development of the Bonga field is presented as an example of integrated subsurface modeling of complex, deepwater channel reservoirs, highlighting geophysical techniques. Three main static reservoir parameters were modeled in detail: (1) net sand distribution, (2) sub-seismic channel architecture, and (3) reservoir connectivity. Proprietary probabilistic, model-based seismic inversion has provided excellent predictions of net sand thickness in development wells in the main reservoir, adding confidence to our in-place oil volume assessment. Because of limits to seismic resolution, all potentially relevant sand and mud beds cannot be visualized from (inverted) seismic data alone. Sub-seismic channel architectures have been deterministically placed in the static models based on analogue and well data and guided by seismic attributes. Connectivity is especially important because pressure support and sweep from water injection wells is crucial to productivity from these near-hydropressured reservoirs. Reservoir connectivity is defined as a function of horizontal and vertical permeability, and transmissibility barriers. Analysis of seismic equal-amplitude surfaces provides a way seismic can potentially help indicate areas of relatively better and worse connectivity. Each reservoir is simulated multiple times using scenarios based on all combinations of the above parameters. Highly amalgamated channels are less impacted by connectivity variation than less well amalgamated channels. Reservoir simulation models have been transferred to synthetic seismic models and demonstrate the potential value of time-lapse (4D) seismic. Other “in-field opportunity” reservoirs have been identified in addition to the main reservoirs, and may provide added production potential in the future.

Biographical Sketch:

Mark Chapin received a B.S. degree in geology from Wheaton College, and M.S. and Ph.D. in geology from Colorado School of Mines. He has worked the past 12 years for Shell in Deepwater areas of the Gulf of Mexico, U.K., and Nigeria, and has been involved in exploration, development, research and operations. Contact email: mchapin@shellus.com .

Posters:

Poster 1.
"Bonga Field, Deepwater Nigeria: Comparison of Near-Surface, Well-Calibrated Submarine Channels with Reservoir Channel Sands "

Mark Chapin, (Deepwater Services, Shell International Exploration and Production), Craig Sipp (Bellaire Technology Center, Shell International Exploration), and Charles Winker (Bellaire Technology Center, Shell International Exploration).

Comparison of near-surface channels with channel reservoirs at Bonga, offshore Nigeria (OML118, 1000 m water depth), demonstrates some important lessons in using shallow analogs for reservoir prediction. Studies of shallow hazards and pipeline routing, integrating 3D and high-resolution 2D seismic with well logs, illustrate seafloor and near-surface features including a large mud-draped canyon, mud volcanoes, and numerous pockmarks, which indicate fluid expulsion. Both the shallow overburden (Plio-Pleistocene) and the main reservoir intervals (Miocene) are characterized by deepwater channel geometries visible in seismic profiles, on map views, and within 3D volume views. Most near-surface channel features inhabit broad, relatively straight scours 1-3 km wide and 30-300 m deep, filled by composite packages of smaller, often sinuous channels 100-500 m wide and 5-50 m deep. Although many of these near-surface channels display a chaotic to low-continuity, high-amplitude seismic facies character often associated with sandy fill, well logs through the near-surface section indicate these are mainly filled with mud. Channel geometries at reservoir level show different characteristics. The smaller-scale map-view geometries are consistent in size with the near-surface channels but the larger host scours are not as prevalent or obvious, and some thin, sheet-like sands are also present. A transition from lower slope to upper slope at the end of the Miocene probably accounts for this variation. A fundamental understanding of geologic setting and rock/fluid variation is critical before extrapolating seismic facies information from shallow analogues to deeper reservoirs.

Poster #2

"Structural Style and Petroleum Potential of Offshore Sierra Leone and Liberia, West Africa"

Kara C. Bennett, Consultant and Don Rusk, Rusk and Bertagne

The offshore region of Sierra Leone and Liberia has been under-explored until recently,when a new 2-D Seismic data set was acquired. This poster session presents the results of a reconnaissance interpretation of the new data, in conjunction with a review of the geologic history, and relevant reservoir and geochemical information. >p> TGS-NOPEC Geophysical Company acquired approximately 15,000 line-km of 2-D seismic data in the offshore area of Sierra Leone and Liberia in 2000 and 2001. The data set consists of 170 lines extending from the continental shelf to water depths of 2500 m to 4000 m. The southwest-northeast dip lines have an average spacing of 5 km and lengths of 50 km to 140 km. Three distinct basins are present. From north to south they are; the Sierra Leone Basin, the Liberia Basin and the Harper Basin. The basins developed during two phases, a syn-rift phase and a passive margin phase. A component of wrench tectonics significantly overprints the framework of both phases.

The Sierra Leone and Liberia basins are separated by the Monrovia Fault Zone, which terminates obliquely at the Liberian coast. The Monrovia Fault Zone is a segment of the Sierra Leone Transform System. The Liberia and Harper basins are separated by the Liberia High, a major element related to the St. Paul Transform System.

The main rift phase began in Aptian time, accompanied by continental deposition. In middle Albian time shallow marine incursions reached the area. Sea floor spreading began in late Albian, associated with widespread marine sedimentation which continued essentially until late Neogene time. The region was tilted basinward, resulting in erosion (the Mid-Cretaceous unconformity) on the shelf and slope while uninterrupted marine deposition took place in the basin. Nine exploratory wells were drilled and abandoned on the shelf, considerably shoreward of the potential of the basin complexes. In terms of exploration maturity, the area should be classified as “frontier”. However, there is an abundance of key data from the above wells, which contribute to the establishment of several petroleum systems.

Numerous Aptian to early Cenomanian sequences contain rich oil-prone to mixed oil and gas-prone source rock, which are mature throughout most of the subject area. Also, the late Cretaceous interval, which expands to more than 2000m in the basin, undoubtedly includes effective Cenomanian to Turonian source beds. Cenomanian and Turonian shales are established type II source rocks throughout offshore West Africa.

Trap types are numerous and relatively widespread, in particular those associated with Cretaceous syn-rift and transform related faulting and unconformities. In addition, traps on the slope and in the basin are ideally located for access to oil migration. Trap types include: titled fault blocks, drape anticlines, strike-slip related faulted anticlines and “flower” structures, stratigraphic pinchouts against the Mid-Cretaceous unconformity and against the continental shelf, truncation traps and deepwater fans