March, 2000
HGS Meetings

HGS Dinner Meeting

"Play Opportunities for the Eastern Gulf of Mexico"

Abstract:

The eastern part of the central Gulf Outer Continental Shelf (OCS) and the eastern Gulf OCS regions present one of the most attractive exploration opportunities currently and soon to be available in the Gulf of Mexico. Recent industry activity in eastern Mississippi Canyon, Main Pass, Viosca Knoll, and Mobile offshore areas have successfully identified significant hydrocarbon accumulations in the eastern part of the central Gulf OCS. There is also a large amount of industry interest in the eastern Gulf OCS region. The current focal point in the eastern Gulf OCS comprises the areas to be offered in the planned Sale 181 area December 2001. They are located in the westernmost extents of Destin Dome, Desoto Canyon, and Lloyd areas.

Tracts in the eastern Gulf planning area are underexplored relative to the traditional exploration areas of the western and central Gulf. Fewer scheduled lease sales, a more diverse geology and absence of producing infrastructure are among the factors that have led to sporadic development. Only eight previous lease offerings have been made in the eastern Gulf OCS region. The last federal lease sale (Sale 116) occurred in 1988 and only 114 tracts were awarded. The low density of leases in the region is in itself attractive to an industry always in search of new opportunities.

In preparation for upcoming lease sales, analyses of newly acquired 2D and 3D seismic data tied to existing well control provide a look at some interesting play opportunities. Approximately 23,000 miles of new 2D seismic has been acquired for evaluation of these tracts along with 450 blocks of new 3D seismic. These new data, when combined with the relatively sparse drilling record, prescribe both old and new play opportunities for these areas.

Three types of plays in the eastern Mississippi Fan and Florida carbonate shelf may be discerned allochthonous salt-related features, autochthonous salt-related features, and Mesozoic shelf carbonate plays. Allochthonous salt-related plays are largely of Early Pliocene or Middle to Late Miocene age and occur in proximity to and beneath horizontal salt features largely restricted to the upper Mississippi fan. Good examples of discoveries associated with the allochthonous salt are Mississippi Canyon blocks 211, 292 and 778, each structurally positioned beneath a salt sill. Additional undrilled opportunities remain in this play but often require high-effort seismic acquisition and processing to be delineated sufficiently for an exploration test.

Middle to Late Miocene plays are associated with autocthonous features in the middle to outer fan. Examples of discoveries associated with the autochthonous salt are in Mississippi Canyon blocks 84, 305, and 657 and Viosca Knoll 915. This play is characterized by channel levee and fan deposits in lower Pliocene to Middle Miocene slope fans. Often features are developed above or adjacent to salt deformation features and associated faulting, some having been subjected to post-depositional basin inversion caused by to salt movement and withdrawal.

The deep, Cretaceous section also represents a play in this part of the fan, pending confirmation of a reservoir section. Recent activity along the buried Cretaceous shelf margin has turned up a significant play with several sizable gas discoveries reported from grain shoal carbonate reservoirs in Viosca Knoll and Mobile areas. A Cretaceous shelf section produces gas from the Aptian James and possibly the Albian Andrew formations, which may extend into the west Florida shelf areas. Examples of discoveries along this trend are in Viosca Knoll 252, 114, 68 and Mobile 991. Evaluation of multiple seismic attributes has proven useful for identification of porous zones along this trend.

Additional opportunities occur in the down-dip Jurassic age Norphlet beneath the shelf. A discovery at Destin Dome 56, as well as prior discoveries in Mobile Bay, have drawn appreciable ‘ interest to the trend. Precise evaluation and ranking of opportunities in these new plays will be highly dependent on detailed evaluations of the high-quality seismic data and understanding of the stratigraphic and sedimentologic framework within these regions.

Basin equivalents of the Mesozoic section have yet to be tested with reservoir being the main concern. This section sources much of the petroleum for the shallower section in the region and may still contain appreciable trapped reserves. Development of significant structural trapping opportunities resulting from an abundance of salt structures is observed in the deepwater Mesozoic section.

Biographical Sketch:

John Adamick received a B.S. degree in geology from Texas A&M University in 1983 and an M.S. degree in geology from Stephen F. Austin State University in 1987. In 1995, he attended Harvard University and completed the Program for Management Development. John began his career with TGS Geophysical Company in 1986 and has served the company in numerous capacities. He is currently president of the Offshore Division. During his career he has authored and presented papers on several subjects including subsalt exploration, Lower Cretaceous stratigraphy, and amplitude versus offset (AVO) analysis.

H. E. ‘Ed’ Denman is a geophysicist at TGS-NOPEC Geophysical Company ASA in Houston, Texas. He received a B.S. degree in geology from Georgia State University in 1972 and an M.S. degree in geophysics from the Georgia Institute of Technology in 1975.

Ed is presently assigned to marketing at TGS-NOPEC, Houston having worked with various TGS affiliated companies since 1990. At TGS-NOPEC his duties include interpretive evaluations of seismic programs and marketing responsibilities. From 1995 to 1998 he co-founded and served as a principal of Excalibur Interpretation Company. Before that he worked with international and domestic affiliates of Exxon Corporation from 1979 to 1990, where he had assignments in Europe, and North and South America, that incorporated prospect generation and evaluations of deepwater opportunities, acreage and data trades. From 1974 to 1979, Ed conducted engineering geophysical projects for Dames and Moore, Consultants and Fairfield Industries, Inc.

Poster Session

Poster One

Integrated geophysical study of near-surface faults in the Wilcox Group, Texas, with application to lignite mining
by Sara Satti

Poster Two

A new evidence for marine influence in Wilcox Strata: Calvert Bluff Formation, Big Brown Mine, Fairfield, Texas
by Jennifer M. Klein, Texas A&M University, College Station, TX.

The Late Paleocene-Early Eocene (Thanetian-Ypresian) interval was a time of major changes in global climate, world ocean circulation, and significant turnovers of marine and terrestrial biotas over a span of 2 my. Climatic changes, including increasing temperature and rainfall, combined with basin downwarping influenced the deposition of sediments in the upper Wilcox Calvert Bluff Formation, previously interpreted as mostly fluvial in origin. New data from study of Calvert Bluff sediments at the Texas Utilities Big Brown Mine indicates that marine transgression outpaced sediment outbuilding to produce deltaic-estuarine sedimentation, resulting in a change to marine-influenced deposition toward the top of the section. This has implications for refining the ability to predict the morphology and distribution of reservoir-sand bodies in the upper Wilcox, as well as the distribution of lignite and coalbed methane generation.

Environmental / Engineering Dinner Meeting

"TNRCC Advisory Role to the RRC and Oil & Gas Industry on Ground Water Protection and the Criteria for Determining Protected Ground Water"

Abstract:

Since 1955 the Texas Natural Resource Conservation Commission (TNRCC) and its predecessor Agencies have acted, through its Surface Casing Team, as geological advisors to the Railroad Commission (RRC) and the oil and gas industry on ground water protection. RRC rules may require a current "water board" letter from TNRCC's Surface Casing Team on such RRC-regulated operations as: new drills, plugging, re-entries, fluid level and mechanical integrity tests, waste disposal by underground injection, enhanced recovery injection, brine mining, seismic programs, and cathodic protection. Applicable to specific operations, Surface Casing geologists determine the depths of fresh or superior quality ground water ( 1000 ppm TDS), usable-quality ground water ( 3000 ppm TDS), underground sources of drinking water ( 10,000 ppm TDS), primary aquifer isolation depths, and minimum injection depths for waste disposal. The team of four geologists prepares an average 15,000 to 20,000 recommendation letters on ground water protection for the RRC each year.

Biographical Sketch:

Robert Traylor is a geologist for the TNRCC Surface Casing Team. His position is responsible for making ground water protection recommendations for the Cenozoic section of the Gulf Coast counties. In addition, he reviews statewide permit applications for Class II injection and disposal wells for the RRC and provides ground water protection recommendations for each application. Before joining the TNRCC Surfacing Casing Team in 1994, he spent more than twenty years as a geologist in the Texas oil and gas industry.

International Section Dinner Meeting

"Why Brasil? - Some Insights into the Future Petroleum Potential, Offshore Brasil"

Abstract:

Introduction.

Brasil has 27 Billion Barrels proven oil reserves from 26 different sedimentary basins. Foreign operators have recently been invited and have responded vigorously to participate in renewed exploration and production licensing activity across these diverse geological provinces. As host country and foreign operators embark on their joint technical and business journey, we believe this is a timely opportunity to summarize new technical insights into potential future producing offshore basins, as well as some emerging mid- and down stream factors that are likely to influence the full business cycle in Brasil.

Upstream Overview.

Many in industry remember Brasil's risk round of the late 70's and early 80's, where exploratory expenditures of almost $1.15 billion and the drilling of 64 offshore wells led to the discovery of only one commercial field, Merluza (300-500 BCF), by Pecten. Many may ask themselves what guarantee a prudent explorationist has in today's business climate that geohistory will not repeat itself. The right answer, of course, is no guarantee, but let's examine some of the petroleum system elements that might influence their perception of the geotechnical risk. We will start with the Equatorial basins in the north and end with the Santos in the south (Figure 1).

Equatorial Basins.

The Equatorial Basins include the Potiguar, Ceara, Para-Maranhao and Foz do Amazonas ('Foz'). The basins have in common that they are; 1) underlain by rifts of Jurassic to early Cretaceous age, 2) vastly under-explored in the 500-1000m water depth range, and 3) unexplored in the deepwater (> 1000m). Ninety one (91) wells have been drilled on the Foz do Amazonas shelf, resulting in some non-commerical gas discoveries, including Pirepema (500-1000 BCF dry gas). Seismic data from the deepwater, however, reveals an untested province consisting of toe thrust, diapir and Tertiary channel trap geometries. Some of the traps are huge, covering 15-20,000+ acres, and with billion barrel reserve potential. Direct trap analogs exist in some of the recent giant fields of West Africa in Angola and Nigeria. The Albian-Cenomian is thought to be the main source for the deepwater. Dominant deepwater license holders in the Foz do Amazonas are BP-Amoco, Esso and Petrobras, together with Shell, Elf and British-Borneo. The first well in this trend will be drilled by BP-Amoco (Operator) on block BFZ-2 in late 2000 or early 2001. The primary geologic risk is hydrocarbon type since gas is not considered an economic success here.

The petroleum system framework of the Para-Maranhao is similar to the Foz do Amazonas but, with less data, is more poorly constrained. Only nine (9) wells have been drilled in the basin and none of these are in deepwater. The hydrocarbon source is believed to be the same Albian- Cenomian as in the Foz deepwater. Seismic shows the existence of a large toe thrust zone. Currently the acreage is all held by the ANP(Agencia National do Petroleo, Brasil's regulatory body), with one block, BM-PAMA-1 scheduled for auction in the ANP Round 2 in Second quarter 2000. The primary risks are hydrocarbon type and reservoir. Gas again is not considered a commercial success.

Both the Potiguar and Ceara Basins are more mature exploration areas, with the Potiguar the number two producing basin in the country at 95 MBOPD. Two petroleum systems have been established (Pendencia and Alagamar), and a third within the Lower Tertiary is emerging. The Pescada and Arabaiana Fields indicate that large portions of the offshore are dominated by high pressure and high temperature conditions. Future plays in the deepwater are both stratigraphic, particularly paleo-canyons such as Pescada and Ubarana, and structural, including pop-ups along wrench zones, faulted four-ways closures, and noses over subtle basement highs. The primary risks are velocity control for proper depth conversion, and locating traps of sufficient size to be commerical.

Bahia Basins.

Stretching from the Pernambuco to Abrolhos volcanic complexes, the Bahia group of basins contains the oldest producing basin, the onshore Reconcavo, and the least mature basins of the offshore( Figure 2).

The Sergipe and Alagoas Basins are the northernmost. The former contains the largest onshore field in the country (Carmopolis) with 400 MMBOE. The offshore is dominated by proven, but small scale, petroleum systems within the Aptian (Muribeca) and Albian-Turonian. Only a few wells have been drilled in deepwater. Here, the main plays are stratigraphic, including pinchouts and channel sands within paleo-canyons. A classic example of the development of the latter canyon is illustrated in the south along the Vaza Barris fault system. Of particular interest is the presence in this area of the ancestral Sao Francisco River system, second only in size to the Amazon, that appears to have deposited a thick, sand-prone section in ultra-deep water (>3000m). The primary exploration risk in deepwater is the existence of traps of sufficient size to establish commerciality and source maturity.

The next group of basins in Bahia are the Camamu-Almada and Jequitinhonha Basins. A proven Lower Neocomian (Morro do Barro) petroleum system exists in the Camamu, along with numerous oil and gas shows throughout the basin complex and several small discoveries (e.g. BAS 97 and BAS 64). Much of the area is covered by poor quality 2-D seismic. Data quality is effected in part by shallow water Tertiary carbonates on the present day shelf. The deepwater play trend is characterized by a steep slope cutby canyons and slumps. Primary reservoir targets are Upper Cretaceous and Lower Tertiary sandstones deposited by turbidite current processes and transported by several ancestral river systems. The primary geotechnical risks are reservoir character and geometry, and trap/seal integrity.

The southernmost basin of the Bahia group of basins (Bahia Sul region) is the Cumuruxitiba. Although there have been shows in almost all of the wells drilled, no commercial discoveries have been made to date and prospectivity appears to be limited. The primary plays are structural and exist along two compressional belts which have been modified by a late stage of transverse motion. As a result of the multi-phase history of deformation, primary risks include effectiveness of charge fairways, timing of hydrocarbon emplacement, reservoir compartmentalization and seal/trap integrity. The primary source rock is postulated to be Albian-Turonian in age.

Santos/Campos Basin Complex.

The final group of basins are the Santos, Campos and southern Espirito Santo Basins. This is Brasil's most competitive exploratory arena, in particular the Campos. The Campos Basin produces 80% of the total production in Brasil and is home to 5 super-giants - Roncador, Albacora, Marlim, Marlim Sul and Albacora Leste. Principal petroleum system elements include a rift-stage rich oil source rock and Tertiary and Cretaceous turbidite reservoirs. Petrobras remains the dominant exploration entity in the Campos area.

Despite Petrobras' reputation as a world class exploration operator, and the level of overall exploration maturity in the Campos Basin and some of the surrounding areas, we believe that there are additional opportunities in these Southeastern Basins. Future discoveries are expected to be made in Tertiary and Cretaceous deepwater sands of the diapir province as both extensions to the current areas (e.g. Cabo Frio and BC 10), and in salt withdrawal 'mini-basins'. The recent discovery by Petrobras on BS 500 (RJS 529) provides a good example. The discovery is reportedly 500-700 MMBO in Upper Cretaceous turbidite reservoirs. Other more regional reservoir targets will continue to include Campanian-Turonian deepwater siliciclastics and Albian carbonates and siliciclastics. Primary risks in this geological province are timing of charge and hydrocarbon quality.

Midstream/Downstream Overview.

Geotechnical considerations must coexist in a favorable mid- and downstream framework to realize a positive return on investment. Let's look next at some of Brasil's emerging business, market and commercial drivers. The onshore areas bordering the Santos-Espirito Santos corridor represents home to 70% of Brasil's population of 165 million and is its main industrial base. A reasonably good infrastructure exits for oil and gas, and conditions for the market absorbing more of both is excellent. A gas net work fed mostly from Bolivia is in early development stage.

If the Santos-Espirito Santos region represents a developed downstream business with potential for short-term return on invested capital, then the other business extreme 'end member' would have to be the Equatorial region. The Equatorial region is dominated by agriculture and tourism and has an undeveloped infrastructure. To promote industry, the state governments have been offering substantial tax breaks, and a market for gas is developing. Gas is currently being sold for $2.70mmcf, mostly due to its high liquids content. Equatorial Brasil can be considered as a frontier for the entire value chain from the upstream, mid-stream to downstream with mostly long-term potential return on employed capital.

The midstream/downstream business climate in the State of Bahia might be considered as something of a midpoint between Santos-Espirito Santos and Equatorial Brasil. The State of Bahia is Brasil's third largest and one of the most politically important. Although good local and industrial market conditions exist for both oil and gas, current production has been dropping steadily from a high of near 60,000 BOPD with serious implications. For example, the Salvador Camacari petrochemical complex has identified critical needs in gas for supply of electricity to replace fuel oil and improve air quality, and high-gravity waxy crude or condensate to supply poly-olefin feedstock. A sophisticated, areally extensive pipeline network is currently drawing gas from as far away as the Sergipe-Alagoas Basin (1500km to the northeast). A short-term source for gas and petrochemical-grade light oil or condensate may be the central and southern Tucano Basins. In onshore Sergipe proper, the primary concern for marketing is that large areas of marine sanctuary may make running pipelines to shore costly or unfeasible.

As a country, Brasil has by late 1999 achieved an average daily production of 1.15 mmbopd, 80% of which is from the Campos Basin. Another 600-700 Mbopd is imported to satisfy country demand. The much talked about gas market, except for selected spots introduced in the preceeding paragraphs, is just beginning to be developed and will take 5 years to mature. Satisfying both the immediate oil production shortfall and the mid- and long-term gas market potential suggests that Brasil has an array of business opportunities that cross the entire upstream, mid-stream and downstream value chain.

Summary.

Given this array of full business cycle opportunities, there are a number of exploration strategies that could be pursued in Brasil. Combine this with the shear size of the country where the area of it's Atlantic Margin alone is a conjugate to 10 West African nations. Add the diversity of its 26 sedimentary basins, and even the size of Exploration licenses, which average 200 times the size of a Gulf of Mexico OCS block, and one gets a sense of the enormity of the task. Let's look at some of the strategic patterns that are emerging and how a few foreign operators appear to be positioning their companies in Brasil;

  1. The niche basin. By this philosophy, focus is placed on gaining an intimate knowledge of a single basin, play or petroleum system. A competitive edge is gained through this geotechnical focus, and the size of the area of investigation is often manageable. We cite: Santa Fe's recent activity and focus in the Potiguar Basin; BP-Amoco in the Foz do Amazonas (though here the area is very large); Unocal's focus in N. Campos/S. Espirito Santo; and Kerr McGee and Amerada Hess' focus on the Santos.
  2. The niche play type. This strategy crosses basin and petroleum system boundaries, and is based on recognition of a technical area of expertise. For example, Esso has in part a focus on toe thrust plays, and are actively exploring this play type in the Foz and Pelotas Basins (as well as offshore Guyana).
  3. The diverse portfolio. The philosophy of a diverse portfolio is one of 'spreading the risk' throughout several basins, play types and petroleum systems. Usually, the exploration portfolio is mixed between high risk/high return, and low risk/low return where the latter usually entails a rapid initial cash flow. A diverse portfolio often includes discovered reserves initiatives. Examples here include: Texaco with holdings in Santos, Campos and Espirito Santo, Repsol\YPF with holdings in the Campos, Espirito Santo, British-Borneo, with holdings in Campos, Santos and Foz.

Biographical Sketch:

Bob Fryklund is a geologist with over 20 years International E &P experience in both technical and managerial positions, the last 8 working South America. He currently is an independent consultant. He has authored, co-authored and edited numerous papers about Brasil and the South Atlantic. He received his degree from Hamilton College, Clinton, N.Y. in 1980. He is a member of the Houston geological Society, the AAPG, The Association of Brasilian Geologists and Association of Latin American Geochemists.

Poster Session One :

Comparison of Biostratigraphic Zonation Schemes in Brazilian Offshore Basins

Anthony D'Agostino *, Dr. Henry Lieberman *, Dr. Robert Nail *, Dr. Peter Thompson **, Del Edelman ***

An extensive literature search effort at PGS has led to the compilation of information on dozens of biostratigraphic zonations applied to the biostratigraphy of subsurface formations in several major Brazilian offshore basins. The zonations are based primarily on the biostratigraphy of microfossils, particularly calcareous nannoplankton and palynomorphs. Other microfossil groups such as foraminifera, ostracods, radiolaria, and dinoflagellates are also represented. Current results will be presented displaying progress on an ongoing and detailed project that will attempt to synthesize and correlate all the published zonations. Early emphasis has been on correlations of biostratigraphy, lithostratigraphy, and sequence stratigraphy in the Campos and Santos basins as well as other basins along the southeastern coast of Brazil.

* PGS Reservoir Inc., Houston, Texas, ** Computational Biochronology, Plano, Texas, *** Edelman, Percival, and Associates, Red Oak, Texas

Poster Session Two :

IDENTIFYING A PLAY USING PUBLIC DOMAIN INFORMATION: AN EXAMPLE FROM POTIGUAR BASIN, NE BRAZIL

HENRY M. LIEBERMAN, PGS Reservoir (U.S.), INC., 1001 S. Dairy Ashford, Suite 300, Houston, TX 77077, Tel. (281) 848-7649, Fax. (281) 848-7676, email: henry.lieberman@pgs.com

ABSTRACT

For those who are unable to access hard data (well, seismic) over an area of interest the public domain can offer a substantial treasure trove of information. The geology of the offshore basins of Brazil has been particularly well documented, if more heavily in some areas than in others. Data can be encountered covering regional geology, stratigraphy, tectonics, structural geology, biostratigraphy, geochemistry, seismic interpretation, and reservoir characterization, to name but a few.

On the basis of information encountered on the Potiguar Basin of NE Brazil, it was possible to establish a basin overview covering its tectono-stratigraphic framework, the petroleum systems, play types, and past exploration history. This particular basin (offshore as well as onshore) has been producing since 1973, but exploration drilling offshore has been limited to the inner continental shelf, in water depths not exceeding 100 m.

While the concept of extending the exploration effort into deeper waters would seem desirable in itself, it is possible, even without the benefit of hard data (well data from the shelf, and seismic data shot over the deeper water part of the basin), to identify a potential play in deep water Potiguar Basin, based upon information available from public domain sources.

Poster Session Three :

Sequence Stratigraphy of the Pelotas Basin, Offshore SE Brazil: Eustatic Control on Stacking Patterns.

Vitor Abreu, Sequence Stratigrapher, Unocal Corporation

Poster Four:

The Greater Campos Basin -- Observations about the Petroleum Systems

Bob Fryklund, New World E & P and Bill Dickson, Dickson International Geosciences

The poster will summarize the key ingredients of the Source system and the migration and entrapment of the hydrocarbons, from a geochemical standpoint.

Emerging Technologies Dinner Meeting

"Simultaneous acquisition of 3D surface seismic data and 3C, 3D VSP data"

Abstract:

Summary

Simultaneous acquisition of surface 3D and downhole 3C, 3D vertical seismic profile (VSP) data provides a comprehensive data set for imaging the subsurface. The surface and downhole data offer complementary measurements of data attributes such as velocity, near-surface distortion and possible anisotropic parameters, leading to improved imaging and resolution. Examples of the recorded downhole data show the exciting possibilities for AVO calibration and attribute analysis. Simultaneous acquisition is very cost-efficient. We offer a work-in-progress report on this unique and comprehensive data set.

Location

The project area is located in southwestern Louisiana, in the South Louisiana salt basin. Seismic data were acquired over a mature field, a piercement salt structure with multiple pay zones. Production is from Tertiary sands, with faults, shales, and depositional geometry providing the trapping mechanisms for oil and gas reservoirs. Cumulative production exceeds 140 MMBO. Over 1100 wells have been drilled in the field. Spatial resolution of small, less than 10 acre or 200m2, reservoir compartments is critical for further reservoir development.

The salt dome has pierced the overlying sediments, extending almost to the earth’s surface. Extensive faulting consists of regional trend faults and radial faulting related to the local salt structure. Topographically, the survey area is flat. Cultural features include residential neighborhoods, highways, pasture, grain fields, and swamps.

Data Acquisition

There are two unique aspects to the seismic data acquisition parameters used for this project, a radial receiver grid with concentric source lines, and the use of multilevel downhole 3C arrays recorded during the surface seismic acquisition. The seismic sources, 5.5 lb. pentolite charges at 60 ft depth (18m) were simultaneously recorded by the conventional surface spread (vertical geophones only) and two downhole 3C arrays deployed in abandoned boreholes within the field.

The data acquisition grid is shown in Figure 1. Receiver lines are radially directed away from the piercement salt dome. Receiver line interval is variable, ranging from approximately 900 to 1200 feet (275 to 365 m), with alternating long and short line segments spaced at 5° increments. Receiver station spacing is 165 feet (50 m) along a receiver line segment. At each station, a six-element array was deployed using 10-Hz geophones. Source locations are approximately concentric circles, with shot spacing 165 feet along an arc. Cultural obstacles in the north and west portions of the survey area, such as houses, wells, highways, canals, highlines and pipelines, produced irregularities in the intended source grid.

The active recording spread consisted of 19 receiver lines that represent a 90° wedge of the 360° coverage produced by the radial receiver line distribution. Typically, 1400 to 2000 channels were active in the surface spread. For each 90° wedge of active receiver lines, the center rack or arc of source points was detonated and recorded. The entire receiver line was active (no radial roll). Each active spread was advanced two receiver lines, or 10°, and the next rack of source points was recorded.

The innovative recording geometry produced a wide range of offset and azimuth fold coverage of the subsurface. Spatial sampling is more dense, with more source and receiver points per km2, closer to the salt dome, where the geologic dips are steeper and the faulting more complex. Fold coverage plots, modeled using GMG Mesa survey design software, show high fold coverage midway between the salt dome (survey center) and the survey perimeter. This high fold area translates to illumination of the steep dips adjacent to the salt dome, the primary area of interest for this project. Ray paths through the salt body are not recorded, avoiding complex wavefield propagation requiring rigorous depth imaging techniques.

The second unique aspect of this project is the use of downhole 3C arrays. During acquisition of the northern half of the surface 3D survey, two abandoned boreholes were used to deploy 3C arrays in the subsurface. Location of the two wells, and the distribution of source points recorded, is shown in Figure 2. The western instrumented well had 80 levels of 3C phones cemented in place at 50 foot increments (15 m). The eastern instrumented well was 40 levels of 3C phones, temporarily deployed using a coiled tubing/bladder technique offered by Paulsson Geophysical Services, Inc. The eastern well had instruments from of 350 to 2350 feet TVD (107 to 716 m). The western well had instruments from 943 to 4893 feet TVD (287 to 1492 m). Of the 80 levels intended, the bottom 18 levels were damaged during deployment and were not operational for recording. The active depth range in the western well was 943 to 3993 feet TVD (287 to 1217 m). An additional 360 channels were required to record these downhole data during the surface seismic acquisition.

An I/O RSR radio telemetry system was used for data acquisition. The flexibility of this system eliminated any cabling problems associated with the radial receiver line geometry. Recording downhole data also presented no problem because groups of six-channel RSR recording boxes were simply located at the wellhead and did not need to be interfaced with the surface seismic using cables for telemetry. There was minimal impact on the surface seismic data acquisition operations. During data gathering and transcription to source records, the downhole arrays were easily treated as separate lines.

Also shown in Figure 2 are the locations of three source points, A, B, and C. These locations are along a radial profile from the salt dome and are referenced in subsequent figures. Over 2000 source points were recorded into the instrumented boreholes.

Data Processing

Simultaneously recording surface and downhole data is a cost-effective method to obtain 3D VSP data. All data are acquired using the same seismic sources and recording instruments. Benefits include using the 3D VSP data to aid in steep dip and salt flank imaging, and improved spatial positioning as a result of velocity model accuracy.

Our objective is to image the area around the salt structure to optimize resolution. Combining VSP and surface seismic data provides an opportunity to add extra control to determine seismic velocities for the depth migration of the surface seismic data and the possibility that we may have reasonable resolution of anisotropic parameters to further enhance the imaging. Additionally, with the surface seismic having improved spatial coverage, there is more scope for determining velocities. The velocities, which cannot be accurately established from the VSP alone, help improve the VSP imaging and maximize the agreement between the surface and VSP images.

Having access to both the surface and downhole data during processing allows the use of complementary measurements of attributes from both volumes. An example is incorporating the source deconvolution, amplitude and static corrections from the surface volume into the 3D VSP processing flow. An ongoing facet of research with this dataset includes anisotropy parameter estimation, VSP-AVO calibration, Q determination for model-based deconvolution, and calibration for time-lapse applications in the survey area.

Discussion

Figure 3 is a migrated vertical section from the surface 3D volume along the radial profile through the western well, containing source points A, B and C. The western well, G-23, did drill to salt at TD. The approximate subsurface position of the 3C array is indicated in Figure 2.

Downhole data recorded for source locations A, B, and C are shown in Figures 4, 5 , and 6. These data have been rotated to radial, tangential and vertical components. The original horizontal phone orientation was determined using P-wave arrivals from 10, far-offset, source locations at varying azimuths. A spherical divergence correction was applied to the trace data and a single gain applied to all displays. These data illustrate many modes of wave propagation, all potentially useful as we learn how to utilize this valuable information. In Figure 4, downgoing P- and S-wave energy is visible on the radial and vertical components. At one interface, upcoming P- and S-wave energy is also seen. In Figure 5, downgoing P and S, together with upgoing P and S, are associated with probable interfaces, suggesting that local calibration of AVO attributes from the surface volume is possible. Energy recorded on the tangential component could be due to structure or possible anisotropy. Figure 6 is interesting, the arriving wave is almost horizontally propagating with the various wave modes being recorded by the downhole array. Again, characteristics of reflection, transmission, and mode-conversion seem to be associated with specific interfaces in the subsurface.

A 3D, VSP migration of the downhole data recorded in the western well (G-23) has been completed. Figure 7 shows a north-south profile through the well from the surface seismic data volume. Figure 8 shows the same surface seismic profile with the 3D VSP image inserted into the section. This VSP migration used the current velocity model, based on well control, surface seismic stacking velocities, and interpreted horizons from the migrated 3D surface data. This is also the migration velocity model for both the post-stack and pre-stack time migration of the surface 3D data. Refining the velocity model is key to improving the VSP image. Further steps toward velocity refinement include incorporating velocity analysis of the surface data following depth migration and tomographic inversion of the recorded downhole data.

Conclusions

The simultaneous acquisition of surface and downhole 3D data is a very cost-effective method for obtaining 3D VSP data. Complementary attributes measured from either data set are used to improve the other. Attributes include velocity estimation, deconvolution techniques, surface consistent phase and amplitude corrections owing to near-surface distortion, measurements of Q, and the possible determination of anisotropic parameters. Direct measurement of reflection and transmission amplitudes at the wellbore will be used to calibrate AVO estimates from the surface 3D data.

Acknowledgments

The authors thank Output Exploration and the joint venture partners participating in the Vinton Field Project. We thank Aminex PLC, particularly John Hayes, Bruce Broussard, and the Windrush Operating Company field personnel for their valuable assistance. Finally, we thank Input Output, Inc., for its investment and participation in the downhole 3C VSP project.

Figure 1: Data acquisition grid showing radial receiver lines. Source lines lie along approximate concentric circles. This radial geometry is centered over the piercement salt structure.

Figure 2: Map view of source points recorded using the downhole 3-C arrays. The two instrumented well locations are shown along with three selected source locations.

Figure 3: Migrated vertical section along a radial profile directed from the salt dome, intersecting the western (G-23) well and selected source locations A, B and C (shown in Figures 4, 5 and 6).

Figure 4: Data recorded from source point A into the downhole 3-C array in the G-23 well. Source offset is 1179 feet. Data are rotated to radial, tangential and vertical.

Figure 5: Data recorded from source point B into the downhole 3-C array in the G-23 well. Source offset is 2862 feet. Data are rotated to radial, tangential and vertical.

Figure 6: Data recorded from source point C into the downhole 3-C array in the G-23 well. Source offset is 6232 feet. Data are rotated to radial, tangential and vertical.

Figure 7: Migrated section intersecting the G-23 well.

Figure 8: Same vertical section as shown in Figure 7 with the 3-D VSP image inserted into the surface seismic data.

Joint HGS & HAPL Lunch Meeting

"Significance of mega-mergers and their implications for the future of the energy industry"

Topic Outline:

The March HGS luncheon, jointly sponsored by the HGS and the Houston Association of Professional Landmen (HAPL), presents a talk by Luke R. Corbett, Chairman and CEO of Kerr-McGee Corporation.

Mr. Corbett will discuss the future of the energy industry with regard to geopolitics, environmental considerations, deregulation, privatization, and world energy trends, and the recent trend toward mega-mergers.

Luke R. Corbett was named chairman and chief executive officer of Kerr-McGee Corporation in February 1997. After the merger of Kerr-McGee with Oryx Energy Co. in February 1999, he was named chief executive officer of the merged company, and named to his current position in May 1999.

After earning a B.S. in mathematics at the University of Georgia in 1969, Corbett began his career as a geophysicist with Amoco Production Co. in 1970. In 1981, he joined Mitchell Energy Corp. and in 1983 became chief geophysicist for Aminoil, Inc., where he subsequently held the positions of manager of domestic exploration and vice president of domestic exploration.

He joined Kerr-McGee’s Exploration and Production Division in 1985 as vice president of geophysics, became vice president of exploration in 1986, and was named senior vice president of exploration for the Exploration and Production Division in 1987. Corbett was named a senior vice president of Kerr-McGee in 1991, group vice president in 1992, and president and chief operating officer in 1995.

Corbett is a member of the American Association of Petroleum Geologists, Independent Petroleum Association of America, and the Society of Exploration Geophysicists. He is on the board of directors of the American Petroleum Institute and the Domestic Petroleum Council and serves as a trustee for the American Geological Institute Foundation.

Corbett serves on the boards of OGE Energy Corp., Bank of Oklahoma Financial Corp., Oklahoma State Board of Education, Oklahoma State Board of Vocational and Technical Education, Last Frontier Council of the Boy Scouts of America, State Fair of Oklahoma and United Way of Metro Oklahoma City. He is on the executive committee for Oklahoma Business Roundtable and serves as a trustee for the Oklahoma City Public Schools Foundation, Oklahoma Foundation for Excellence and Oklahoma United Methodist Foundation. He currently serves as chairman of the Greater Oklahoma City Chamber of Commerce for 2000. He is a former president and member of the executive committee of the Oklahoma City Petroleum Club.

Joint AAPG - SEG Distinguished Lecture 1999-2000

"Let the Data Speak To You: How to Improve Your 3-D Seismic Interpretation"

Abstract:

There is no question about the success of 3D seismic technology, but we can still do better. Much 3D data remains underutilized, and some is strained beyond its limit by interpreters with unreasonable expectations. 3D interpretation, has become too popular for its own good. Geoscientists and engineers are working on the data without an adequate understanding of geophysical principles. In 2D interpretation the seismic data added information to an existing geological model. In 3D interpretation, we must let the data speak to us and try to believe it, modifying geological concepts if necessary. It takes time to interpret 3D seismic data, but we must use this time to maximum advantage. We must use all of the data without necessarily looking at it all. We must appreciate the precision of machine autotrackers, and investigate what part of that precision is geology and what part is noise. We must become familiar with unconventional displays. Faults don’t have to be recognized on a vertical section to be valid! How long will it take for everyone to embrace color and discard those old wiggles? There is a great need for the appreciation of geophysical principles. Seismic resolution is fundamental; we must know the magnitude of the seismic wavelength to appreciate the resolving power of our data. This determines the minimum thickness of flow units about which our engineers can discern information. We must correlate seismic traces to geology on character, not simply time, and be alert to phase distortion as we do so. Seismic attributes are wonderful, but they lack independence and should not be subject to too much statistical analysis. Let the data speak!

Biographical Sketch:

Education

Oxford University, United Kingdom, Physics Australian National University, Canberra, Australia, Geology

Experience

1966-1972 Bureau of Mineral Resources, Canberra, Australia 1972-1978 Geophysical Service Int., Croydon and Bedford, United Kingdom 1978-1987 Geophysical Service, Inc., Dallas, Texas 1987-present Consulting reservoir geophysicist, Dallas, Texas

Publications

Four editions of his book Interpretation of Three-Dimensional Seismic Data (AAPG Memoir 42) published in March 1997. (previous editions: 1992, 1989 and 1986)

Professional interests and experiences

Interpretation of 3D seismic data, stratigraphic interpretation, optimum use of interactive workstations, and seismic reservoir identification and evaluation. Alistair Brown spends much of his time teaching interpretation methods and advising on interpretation problems worldwide.

Memberships

American Association of Petroleum Geologists, Society of Exploration Geophysicists, European Association of Exploration Geophysicists, Dallas Geophysical Society.

HOGS Seminar
"Biodegradation rates in oilfields assessed using geochemistry and geology. Implications for petroleum exploration and deep, hot and slow biospheres(Largobiospheres)"

Abstract:

Biodegradation of crude oil in the reservoir is an important alteration process with major economic consequences, most of the worlds petroleum being biodegraded. While the effects of biodegradation on the molecular composition and physical properties of crude oils are empirically relatively well known, the actual processes taking place during biodegradation of crude oil in deep reservoirs remain obscure, as do the site and rates of degradation, the specific oxidants and the nature of the reduced products in most cases. While petroleum geoscientists worked with the concepts of deep(several kilometers) bacterial activity for most of the 20th century, recent developments in environmental geochemistry, molecular biology and microbial ecology have been almost explosive in impact on the field but little has been done to look at actual rates of degradation and see if this is relevant to pre-drilling degradation prediction. We have been trying to do just that. The recent exciting report of anaerobic hexadecane degradation mediated by water, reported by Zengler et al(Nature 1999), is slow on human timescales in the laboratory but it seems likely the processes of hydrocarbon degradation in deep subsurface petroleum reservoirs are orders of magnitude slower still which may explain why, to date, effective total lab simulation of subsurface anaerobic degradation has not been made.

Mixing of oils during degradation is a well known process to petroleum geochemists and is a key to understanding oil degradation in our view. I review some of our recent ideas and approaches in subsurface biodegradation and oil mixing1,2 which suggests that compositional gradients in classical degradation parameters in oil columns imply mass transport control on degradation rates with degradation primarily at the oil water contact. This in turn implies diffusive transport of nutrients and electron acceptors may be adequate to sustain degradation in many instances and, in turn, implies slow rates of biodegradation in-reservoir(equivalent to k=10-5......10-7 per year). Biodegradation rates in deep reservoirs seem similar to organic matter respiration rates in deep aquifers. This then indicates why with surface anaerobic degradation rates of ca 0.01 yr-1 or faster, lab simulations frequently fail to achieve totally realistic results. Using bacterial maintenance energy concepts we speculate that few bacteria may be active in degrading oil reservoirs and that the deep degrading biosphere is slow and may even operate at near maintenance energy rates. Thus we may have a slow largobiosphere with major implications for evolution and consequences for bacterial longevity! Typical oil degradation rates of ca 10-6yr-1 correspond to 10% oil degradation(n-alkane removal) in ca 5-10Ma for initially light oils but theoretical maximum rates correspond to 10% degradation in much less than 1Ma. For low levels of degradation, charge history and fresh oil in-mixing may be a dominant control on apparent level of degradation and basin modelling approaches are seen to be helpful.

References:

  1. Deep water exploration meets the largobiosphere: Biodegradation rates in petroleum reservoirs. S. R. Larter, M. Koopmans, I. M. Head, A. C. Aplin, A. Wilhelms, C. Zwach, N. Telnaes(ACS-2000).
  2. Biodegradation rates assessed geologically in a heavy oilfield-Implications for a deep, slow (Largo)biosphere. Steve Larter, Martin P. Koopmans, Ian Head, Andy Aplin, Maowen Li, Arnd Wilhelms, Nils Telnaes, Mei Bowen, Chunming Zhang, Wu Tieshen and Chen Yixian(Geo-Canada 2000).

Oklahoma Geological Survey,
U. S. Department of Energy, National Petroleum Technology Office, Tulsa,
Kansas Geological Survey

Co-sponsor
WORKSHOP AND PROGRAM

Petroleum systems of sedimentary basins in the southern midcontinent

Event Description:

Presentations will cover research and studies dealing with petroleum resources in sedimentary basins, including deposition, diagenesis, thermal histories, overpressuring, reservoir characterization, 3D seismic interpretation, exploration, and petroleum production.

This is the thirteenth work-shop/symposium in as many years, each program covering a special topic on exploration for, and development of, petroleum resources in Oklahoma and adjacent states.