February, 2003
HGS Meetings

HGS Dinner Meeting

""Pre-Mississippian Carbonate Plays in ANWR on Alaska's North Slope"

Abstract:

Despite the economic importance of Alaska's North Slope as a major petroleum province containing the continent's largest producing oil field, the early history of Arctic Alaska is among the most poorly understood episodes in the geological evolution of what is now part of present-day North America. Disparity exists between our understanding of rocks above and below a regional sub-Mississippian angular unconformity developed across Northern Alaska. Carboniferous and younger rocks above this unconformity are less intensely deformed, exposed over a broader surface area, have been penetrated by extensive drilling, and have received the bulk of attention from industry and academic geologists. In contrast, the sub-Carboniferous record is a complex assemblage of sedimentary, metasedimentary, and volcanic rocks that have been deformed by early to late Paleozoic orogenic events that predate deposition of the overlying sequences. The anticlinal cores of the Sadlerochit and Shublik mountains of the Arctic National Wildlife Refuge (ANWR) contain an over 4 km-thick package of Precambrian through Lower Devonian carbonate, clastic and igneous “basement complex” rocks, unequaled in northern Alaska, that record the early depositional and tectonic geologic history of Arctic Alaska and warrant much greater attention as potential petroleum reservoir rocks.

There are three distinct Pre-Carboniferous megasequences in the Sadlerochit and Shublik mountains that have bearing on the 1002 subsurface of ANWR. The oldest sequence, consisting of the polydeformed ‘Nularvik slate and quartzite’, represents the stratigraphic record, albeit poorly preserved, of a Proterozoic or older precursor basin. The middle sequence records Neoproterozoic rift to drift passive margin sedimentation and is represented by pillow basalts overlain by the ~2500 m thick Katakturuk Dolomite. The Katakturuk depicts a SE-dipping carbonate ramp complex with a complete spectrum of facies types, from proximal tidal-flat complexes, ramp edge coated-grain oolite to pisolite shoals, and distal allodapic slope deposits. The Katakturuk ramp was an extensive cyclic carbonate depositional system that was terminated by a major karst event marked by widespread cave breccias exposed in the Sadlerochit Mountains. The upper sequence, represented by the Nanook and Mt. Copleston limestones, has a paleodepositional setting similar to the middle sequence, and the distribution of lithofacies indicate a laterally extensive south-facing carbonate platform as well, possibly a carbonate ramp. This sequence’s upper boundary is a karst horizon beneath the sub-Mississippian regional unconformity.

Observations of structural and lateral facies relationships of these three megasequences in the Sadlerochit and Shublik mountains provide insight into pre-Carboniferous petroleum play strategies in the 1002 area of ANWR north of the mountain front. Northeast-trending normal faults in the middle and upper sequences are perpendicular to the prevailing platform margin facing direction (southeast) suggesting that these faults are extensional in nature and initially formed during Neoproterozoic rifting events associated with passive margin development. Abrupt lateral facies changes in the overlying Nanook Limestone (Cambrian-Ordovician) imply the NE-trending faults were active in Early Paleozoic time as well, and that the Sadlerochit Mountains were a topographic high during most of Nanook deposition.

Erosion beneath a sub-Nanook unconformity (Precambrian or Early Cambrian in age) has likely removed the entire Katakturuk section south of the Shublik Mountains. Lower Devonian carbonates (Mt. Copleston Limestone) are restricted to the Shublik Mountains and likely were not deposited to the north-consistent with a northern topographic high or later removal by the sub-Mississippian unconformity. Where not removed by the sub-Mississippian or the Lower Cretaceous unconformities, beneath the 1002 coastal plain north of the mountain front both the upper karst cave-breccia of the Katakturuk Dolomite and the coated-grain facies throughout its entire section are potentially attractive petroleum reservoir targets. Finally, at Hue Creek in the Shublik Mountains, the Katakturuk Dolomite is thrust over the Prudhoe Bay source rock Shublik Formation, providing a tantalizing prospect for “basement complex” petroleum potential in the 1002 subsurface.

Biographical Sketch:

After receiving a B.A. in geology from the College of Wooster, Jim Clough headed from Ohio to Alaska to begin a M.Sc. degree program at the University of Alaska Fairbanks (1981). Jim has been with the Alaska Division of Geological & Geophysical Surveys since 1981 and is Chief of the Energy Resources Section. The focus of Jim’s work has been mostly in energy-related studies including ANWR 1985-1997, coal 1981 to present, and mostly recently coalbed methane. Jim is married and has one daughter in the first grade in Fairbanks. Jim’s other interests include ice hockey, swimming, scuba diving (tropics only!), dog mushing (retired) and languages (earned a B.A. in Yup’ik Eskimo in 1986).

HGS Environmental / Engineering Dinner Meeting

Title: TBD

Abstract:

Biographical Sketch:

HGS International Dinner Meeting

"Cyclic Attributes on Seismic Data and Sequence Stratigraphy-New Criteria for Exploration, New Interpretation Styles"

Abstract:

Biographical Sketch:

HGS North American Exploration Dinner Meeting

“Jonah Field Area: Seismic Coherency Cube Technology Used to Define Trap Boundaries and Stratigraphic Features”

Figures:

One Jonah Gas Field index map.
Two Type logs for west and east parts of the Jonah Field.
Three . Arbitrary 3-D seismic line displaying five key well logs as shown on Figure 2.

Abstract:

Jonah Field, Sublette County, Wyoming is expected to produce at least 1.5 TCF of natural gas from lenticular, over-pressured, tight formation gas fluvial sandstones of the Cretaceous-age Lance Formation. Depth of production is 7,500 to 12,400 feet and gross producing interval is 1500 feet to 3200 feet. Jonah was indicated to be a significant field in early 1993 (Robinson, 2000) and now produces more than 400 MMCFD from more than 200 wells (Figure 1 ). In-fill drilling on 40-acre spacing has been underway since mid-2000. Entrapment may result from a combination of dip reversal and fault zone deformation associated with faults that intersect up dip to form a wedge-shaped compartment. Apparent throw on the bounding faults is variable, but commonly is less than 200 feet.

Seismic imaging of the Jonah Field is challenging because of complex fault throws and generally dim and discontinuous reflections within the producing interval. Reservoir heterogeneity is the result of both depositional and tectonic processes. First-order and second-order heterogeneities were created by a direct interplay of tectonics and deposition. Third-order and forth-order heterogeneities reflect depositional details within channel-fill and channel-belt facies.

Tectonics, including regional asymmetric subsidence in front of the Wind River allochthon and local syndepositional movements, are associated with three important unconformities at Jonah field. These unconformities range in age from Late Cretaceous (Campanian) to Middle? Paleocene. From oldest to youngest these unconformities are: base of Ericson Formation; base of Lance Formation; and base of the Fort Union Formation. The Lance formation thickens northeastward across Jonah Field from 2500 to 4000 feet as a result of changing accommodation space induced by flexural loading of the crust during emplacement of the Wind River Uplift (Figure 2 ). Conversely, the updip thinning is accomplished by basal onlap, intraformational truncation, and gradual convergence of strata. In the eastern part of the field, down dip from section 27, we interpret local southwestward onlap of the basal Lance Formation onto the eroded top of the Mesaverde Group. Separately, a thick interval of younger lower Lance Formation strata is beveled southwestward towards the apex of the field in the area updip from section 27. Erosion of the Lance Formation at the base of the Fort Union Formation becomes important west of Jonah field. Figure 3 is an arbitrary seismic line traversing Jonah Field in the direction of regional dip.

Depositional processes are believed to be the most important contributors to 3rd and 4th order reservoir heterogeneities in Jonah Field. Integrated well log, core, seismic, and regional geologic data support the interpretation that Jonah reservoirs are primarily lenticular channel fill and channel belt sandstones deposited by low-sinuosity fluvial systems which flowed southeastward along the rapidly subsiding basin axis towards the Interior Cretaceous seaway. Within the Lance Formation the more continuous reflections are usually associated with flood basin mudstone bodies. Questions of well spacing and well density are probably most dependent upon the depositional fabric of fluvial facies in addition to the degree of compaction and diagenetic occlusion of the intergranular pores.

Advanced seismic techniques have been applied to a proprietary 3-D seismic survey to define the trap boundaries and to optimally locate development wells at Jonah Field. One of the main tools used for our interpretation has been a 3-D broad-band amplitude-based coherency algorithm (Marfurt, and Kirlin, 2000) that has edge detection capabilities. This algorithm looks at the reflector amplitude gradient and captures the lateral change in amplitude with azimuthal angle. This allows the interpreter to “illuminate” a particular feature from the optimal angle to see the maximum detail within the data. On the southern part of the Pinedale Anticline east of Jonah Field, this technology allows us to visualize large Fort Union Formation sandstone bodies comprised of coalesced fluvial (meander belt) channels fills. These sandstone bodies abruptly terminate along the west flank of the anticline suggesting a mid-Paleocene phase of structural development although most of the folding of the southern part of the Pinedale Anticline clearly affects the Early Eocene Wasatch Formation.

Biographical Sketch:

Victor Vega is currently Project Manager of Jonah Field for BP. Victor started with Amoco in 1994 as a geophysicist and has worked all over the world doing interpretation for exploration and development work, regional studies and AVO analyses. He received his MS in Geophysics from the University of South Carolina in 1993 after having completed a BS in Geology from the Universidad Nacional de Colombia. Victor is a member of the AAPG, SEG and ACGGP (Colombian Association of Petroleum Geologists and Geophysicists). He is the International Coordinator for the VIII Simposio Bolivariano in Cartagena next year.

HGS Lunch Meeting

"Gulf of Mexico "Bright Spots"- Early Shell Discoveries
1967 -1973"

Figures:
Click here to see the figures and a copy of the abstract on "Search and Discovery" .

Abstract:

Acknowledgment: Thanks to Shell Offshore in New Orleans for allowing the author to review old files so that data “from the time” could be included in this paper.

The author observed a strong seismic reflection, with attenuation below the event, at a depth of approximately 2500 feet on the crest of a low-relief structure in Main Pass area, offshore Louisiana during 1967. The most likely interpretation was that a calcareous zone, a “hard streak,” caused the strong reflection. Later, two exploration wells penetrated the shallow reflection and found a 25-foot gas pay with very low sonic log velocity, a “soft” reflection.

In late 1968, a strong seismic event that conformed to fault closure was observed on the south flank of Bay Marchand Field. The strong event was considered a positive factor in estimating the reserve potential of the prospect. After leasing the block, drilling found the amplitude anomaly corresponded with a 100+ foot oil sand with approximately 100 MMBO. This was the first qualitative application of Bright Spots.

During 1968 and early 1969, strong seismic reflections were observed at depths of 5000 to 10,000 feet on exploration prospects in the offshore Texas and Louisiana Pleistocene trend. Digital acquisition and processing preserved the relative amplitudes of seismic data in contrast to automatic gain control. Because the Pleistocene trend was essentially an unexplored province at the time, well data was not available to help determine the cause of the strong reflections.

The term Bright Spot was coined during informal discussions. Seismic was primarily used to map structure at that time, and most geoscientists doubted the relationship of Bright Spots to gas/oil pays.

In mid 1969, several oil and gas fields in the offshore Louisiana Pliocene/Miocene trend were studied and Bright Spots were correlated with gas sands with low velocities on the sonic logs. Shell senior management acted quickly and an operations/research team was formed to study seismic amplitude changes that may be related to gas and oil pays.

Prospect Posy, Eugene Island 330 Field

The first significant quantitative application of Bright Spot technology was in 1970 when Shell technical mapped two pays and predicted the thickness of a gas sand on Eugene Island Block 331 (150 MMBOE). Ultimate recovery of the entire EI 330 Field, in the Plio-Pleistocene trend, is 750 MMBOE.

At the “J” sand map level at 6500 feet, a good Bright Spot conformed to structural closure (Figures 1 and 2). Amplitude/Background (A/B) and thickness measurements at “J” sand level were made, using the program Payzo written by Shell Geophysicist Aubrey Bassett (Figures 2 and 3).

There is a good match between seismic amplitude interpretation and well data (Figures 5 and 6). All of the oil and gas pays correlate with amplitude anomalies of varying quality. In hindsight, the “L” sand, a few hundred feet deeper than the “J” sand, was the first oil sand recognized as a Bright Spot.

Crossplots called “trend curves” show reflection coefficient vs. depth for gas, oil, and wet sands were derived from petrophysical data in different geologic provinces in offshore Louisiana. “Trend curves” were used to help interpret amplitude anomalies for the 1972 Federal lease sale.

Prospect Pine, South Marsh Island 130 Field

The first detail application of Runsum (integration of the seismic trace) seismic processing was made at Prospect Pine (250 MMBOE ultimate reserve in SMI 130 Field) in 1972. Seismic amplitudes were calibrated to petrophysical trend curves. Bright Spots were used successfully to predict oil pays; this was very important at the time as oil was a much more valuable resource than gas.

The West Pine amplitude anomaly located on the west side of Block 131 has the same measured amplitude as an oil pay across the syncline at Pine. Shell tested low quantities of gas, and the sonic log showed cycle skipping, suggesting that the sand had about 10% gas saturation.

Summary

Shell discoveries using Bright Spots on the shelf of the Gulf of Mexico (GOM) are estimated to found 1.5 to 2 BBOE. In the GOM deep water, the estimate of recoverable hydrocarbons is approximately 4 BBOE. The present of Bright Spots was a key factor in entering GOM Deep Water during 1983 to 1986.

Lessons from Shell initial Bright Spot studies and Prospect Posy and Pine successes

References:

David S. Holland, John B. Leedy, David R. Lammlein, 1990, Eugene Island Block 330 Field-U.S.A. Offshore Louisiana, in Structural Traps III: Tectonic Fold and Fault Traps: AAPG Treatise of Petroleum Geology Atlas of Oil and Gas Fields, p. 103-143.

Michael C. Forrest, 2002, Gulf of Mexico Bright Spots - Shell Early Discoveries AAPG Search & Discovery website

Biographical Sketch:

Mike Forrest is a Petroleum Exploration Consultant after a career with Shell Oil Company and Maxus Energy Corporation.

Forrest retired from Maxus in 1997 as Senior Vice President of Business Development and Technology. He joined Maxus in 1992 as Vice Chairman/Chief Operating Officer and continued working for the company after the YPF purchase of Maxus in 1995.

Mike worked with Shell Oil Company for 37 years and he retired in 1992 as President of Pecten International Company, a Shell U.S.A. subsidiary. During his Shell career, he had extensive experience in Gulf of Mexico exploration plus Alaska, onshore Gulf Coast and the Mid-Continent. He is a graduate of St. Louis University with a BS degree in Geophysical Engineering.

Forrest serves on the Board of Trustees for the Institute for the Study of Earth and Man at Southern Methodist University and he is a Trustee Associate with the Society of Exploration Geophysicists. He is a director of Matador Petroleum, a private oil company, and Corporate Advisor of Alliant Geophysical, a seismic data processing company.