ABSTRACT This field trip provides a rare opportunity to visit outcrops and structures that highlight the geology, history, and natural beauty of Santa Cruz Island, a remnant of prehistoric California isolated off Santa Barbara. Santa Cruz Island provides some of the most southwestward positioned subaerial outcrops of the North American landmass, while displaying a rare glimpse of prehistoric coastal southern California and picturesque and seldom accessible exposures of Tertiary strata. Most of the stops are difficult to reach and many are closed to public access. Stops 1, 9, 9B, 9C, 13, and 13B are within the Channel Islands National Park, and access to the park portion of the island is by public boat transport (Island Packers) from Ventura Harbor to Prisoners Harbor. Stop 1 is near the pier at Prisoners Harbor and easily accessible; however, the other stops require roundtrip hikes of at least 10 miles from the pier. One of the goals of this four-day trip is to visit as much of the island’s varied geology as possible. A significant body of widely recognized geologic research has been done on the island from late Quaternary sea-level and climate changes to the tectonic evolution of the western North American plate boundary, and in particular the transformation of a subduction to transform plate boundary along a continental margin. Discovery that SCI and the western Transverse Ranges have rotated ~90° clockwise since the early Miocene (Kamerling and Luyendyk, 1979, 1985; Luyendyk et al., 1980) brought on an intense period of research on the island from the late 1970s through the 1990s. Much of this work has been published in both the formal and informal literature. Two decades later, this field trip is an opportunity to review much of these additions to geologic understanding with the advantage of gains in knowledge since then. The guide will emphasize each stop’s importance, offer questions for future research, and showcase the island’s earth science educational opportunities. This four-day trip requires 4WD vehicles and includes some 3–6 km (~2–4 mile) hikes. Dedicated to Dr. Lyndal Laughrin, Santa Cruz Island Reserve Director, Emeritus, The Sage of Santa Cruz Island

Abstract Study of a regional three-dimensional seismic data set by Cumella and Ostby (2003) indicated the potential existence of wrench faults in the southern Piceance Basin, Colorado. Although the faults could be inferred to cut through the productive interval, no direct observation was possible until the Reservoir Characterization Project (RCP) conducted a multicomponent seismic study at Rulison Field. This study confirms the existence of faults and coduments their importance in creating fracture zones critical to higher expected ultimate recovery (EUR) well production within the field. Three-dimensional seismic data were acquired at Rulison Field by RCP to investigate whether zones of high fracture density within the Mesaverde reservoir interval could be detected. Three time-lapse, multicomponent seismic surveys were acquired in 2003, 2004, and 2006. The study confirmed the existence of wrench faults, documented zones of high fracture density, and observed pressure depletion within these zones. Wrench faults and fracture zones play an important role in the creation of “sweet spots” associated with wells of high EUR. Sweet spot identification with multicomponent seismic data can improve the economics of tight gas exploration and production.

Abstract This chapter describes an integrated approach to reservoir characterization and three-dimensional (3-D) geologic modeling of the San Andres Formation at Vacuum field, New Mexico, United States. We present techniques to identify significant heterogeneities within a carbonate reservoir using stratigraphic, petrophysical, and 3-D multicomponent seismic data. This integrated approach provides a detailed static description of reservoir heterogeneity and improved delineation of the reservoir framework in terms of flow units. We use a petrophysics-based method to identify hydraulic flow units within a sequence-stratigraphic framework. Flow units are characterized within high-frequency carbonate sequences through analysis of the vertical variation of flow (kh) and storage capacity (ϕh) and pore-throat radius (R35) associated with successions of subtidal, intertidal, and supratidal rocks. Pore-throat radii from cored wells are used to modify the empirically derived Winland equation to estimate values of pore-throat radius in non-cored wells. Flow profiles, constructed from log porosities and neural-network permeabilities, are correlated and used to build a 3-D geologic-model framework. Characterization of both matrix and fracture properties within a reservoir is possible using 3-D multicomponent seismic data and wire-line logs. Compressional- and shear-wave amplitude attributes together provide more accurate porosity estimates than those determined from compressional-wave data alone. Shear-wave anisotropy measurements provide information about inferred fracture density and orientation that can be used to modify permeability models to account for regions with open fractures. Because of this study, reservoir-simulation models that incorporate modified permeability distributions more accurately account for unexpected early CO 2 -breakthrough times observed in the field. In addition, flow-simulation results indicate that the need to upscale the geologic model was significantly reduced or eliminated by describing flow units using the combined sequence-stratigraphic- and petrophysics-based method.

Abstract Rock properties such as lithology and porosity can be obtained from com-parative P- and S-wave traveltimes or velocities measured from multicom-ponent (3-D, 3-C) seismic reflection data. A 3-D, 3-C seismic reflection data survey was acquired by the Colorado School of Mines Reservoir Characterization Project at Joffre field, Alberta, to map the complex porosity distribution in a shelf carbonate reservoir. Velocity ratio analysis, of compressional velocity to shear velocity (Vp/Vs), indicates a linear correlation with porosity in the Devonian Nisku reservoir. Vertical porosity distribution at wells and horizontal porosity distribution derived from seismic reflection data are used to map 3-D porosity distribution using geostatistical methods.The results show enhanced mapping of porosity distribution and better defi-nition of the lateral limits of the reservoir. These results will assist in reser-voir simulation of this field.

This field trip is an overview and reappraisal of the prolific oil basins of southern California (Fig. 1A) using exploration methods now commonly used in international exploration. As a result of the dramatic decline in oil and gas exploration in California during the last decade these mature and well known basins have received limited modern hydrocarbon research and it is hoped that our field trip and guidebook will outline some of the important aspects and questions of these intriguing petroleum systems. We have used balanced cross sections and other types of structural analyses integrated with basin modeling, geochemical and geophysical data to gain new insights into the structure, trapping mechanisms, and petroleum systems (Magoon and Dow, 1994) in a setting combining strike-slip and convergence (transpression). Southern California geology also has the scientific advantage, but societal disadvantage, of earthquakes (Fig. IB) which provide useful data about the deeper structure which will be presented during the trip. Our field examples are in the eastern Ventura basin, Ridge Basin, southern San Joaquin basin, Cuyama basin and western Ventura basin as well as a transect of the western Transverse Ranges (Fig. 1A).

Abstract Three-dimensional (3-D) seismic surveys have proved to be powerful tools for imaging the subsurface since their introduction in the mid-1970s. Today, 3-D seismic surveys demonstrate high cost/benefit ratios by reducing dry-hole risk and by providing better well placement for flow rates and drainage. Additional benefits include improved reserves estimates and shorter cycle times for appraisal and development project planning. Also, old fields with declining production profiles are being rejuvenated. 3-D seismic surveys are revolutionizing the geophysical industry, with far-reaching effects on the exploration and production business worldwide. With improvements provided by substantial investments in technology, 3-D seismic surveys will play an even more significant role in field development and production strategies in the years to come.

Abstract We have begun the integration of rock physical properties, production data, reservoir modeling, and 4-D seismic monitoring from multiple generations of 3-D surveys to track changes of seismic attributes with pool drainage. Here we present the 4-D seismic monitoring technologies in order to (1) predict reservoir characteristics from seismic data, (2) locate bypassed pay, and (3) isolate drilling strategies that will maximize additional recovery for future fields. The test study is from the Eugene Island 330 Field of the offshore Gulf of Mexico. These results will have general application to other fields in the Gulf of Mexico, Nigeria, the North Sea, the Caspian Sea, and Indonesia—those with multiple generations of 3-D seismic coverage and seismically illuminated hydrocarbons.

Abstract We integrate 3-D seismic, wireline log, and production data to demonstrate that seismic amplitude maps of two pools in a Pleistocene lowstand delta complex of the offshore Gulf of Mexico image reservoir compartmentalization by depositional features and faults. The GA interval of the Eugene Island Block 330 Field is composed of stacked deltaic lobes, each of which consists of complex associations of distributary channels, clinoforms, and base-of-slope failure complexes. Production is from “updip” facies (including delta front and mouth bar sands) at the top of the interval. The highest amplitudes associated with the seismic horizon that marks the flooding surface at the top of the reservoir are associated with high-porosity (and high-permeability) clean, charged sands that depositional processes have not distributed uniformly. One of the two pools has a gas cap, and so the high amplitude response is expected (classic “bright spot”). The other pool has no gas cap, but the charged sands are also associated with high amplitudes because the in situ gas-oil-ratio of the oil is high (400 to 500 scf/bbl). In this second pool, there is a good qualitative relationship between production character and the combination of seismic amplitudes and structural position, with the best, most consistent production from high-amplitude areas on the crest of an anticline.

Abstract We investigated the following problem: “How do fluvial depositional processes create compartmented gas reservoirs?” Using vertical seismic profile (VSP) data to define where selected thin-bed gas reservoirs were positioned in a 3-D seismic data volume, we created horizon slices through this 3-D image that showed the reflection amplitude behavior across the depositional surfaces where targeted thin-bed reservoirs were located. We saw intriguing meander features on these 3-D amplitude displays, which appeared to be realistic depictions of intermeshed fluvial channels. We then overlaid well-log cross sections on these 3-D seismic images, which inferred the depositional environments that were found by wells that penetrated the reservoir system, and these geologic constraints confirmed that the imaged meander features were indeed channels. The most important nonseismic data that we used to understand how 3-D seismic images can reveal reservoir compartment boundaries were various forms of reservoir engineering data that proved which wells shared a common pressure compartment and which wells did not. Using these engineering constraints, we showed that many of the seismically imaged channel features created reservoir compartment boundaries that impeded lateral fluid flow. Equally important, we showed that some seismically imaged channels had minimal effect on lateral flow and did not form compartment boundaries. We concluded that in any effort where 3-D seismic data are used to infer the internal compartmentalized architecture of a reservoir system, good quality reservoir engineering control, such as pressure interference tests and pressure decline curves, must be incorporated into the 3-D interpretation.

Abstract A combination of seismic trace attributes including instantaneous frequency and reflection amplitude was successfully used to seismically delineate gas-prone reservoir facies consisting of thin, discontinuous sandstone reservoirs in a shale-rich stratigraphic sequence. This type of reservoir section poses special problems for seismic interpretation due to a high degree of lateral and vertical variation in the ratio of net sandstone to gross interval thickness. Individual sandstone reservoirs are also below the limit of seismic bed resolution, further complicating the evaluation. Instantaneous frequency maps were used directly to map the areal distribution of reservoir-prone intervals. The addition of calibrated average amplitude maps provided the ability to discriminate between homogenous shale-rich sections and relatively homogenous sandstone-rich sections characterized by amalgamated siltstones and sandstones. The lithofacies prediction model developed using this integrated geological, petrophysical, and seismic interpretation technique was confirmed by the results of two new wells which penetrated the target interval described in this study. Instantaneous frequency maps with overlays of amplitude and time structure contours successfully identified stratigraphic intervals favorable for gas accumulation and trapping.

Abstract 3-D surveys have proven to be a powerful structural risk reducer for oilmen in West Central Texas. While the biggest structures were found using single-fold and 2-D common depth point (CDP) shooting, the success rate for stepout Mississippian and Canyon reefs drilled on 3-D surveys has increased substantially in this area: 3-D surveys have gained wide acceptance by the oil community in North and West Central Texas. Whereas 2-D has been relatively ineffective in stratigraphic situations, this paper will showcase a 3-D survey which was used as a tool to pinpoint a shallow 1500-ft (460-m) meandering channel in the upper Pennsylvanian Cisco system. Regional studies report evidence of a lowstand of sea-level for this formation, locally called the King, which occurred near the end of deposition (Brown et al., 1990). The 3-D data appear to demonstrate the presence of another relative lowstand of sea level, which occurred early during deposition of this formation. Significant detail can apparently be seen in these data, including point bars, levees, and overbank deposits. The data appear to correlate with all logs that penetrate the 3-D volume: i.e., where a well penetrates the channel location depicted in the seismic image, the logs show evidence of a channel. This 3-D survey was designed for objectives at 3000–6000 ft (425–1830 m). Because of this, the fold at the shallow fluvial unit is quite low (three- to four-fold). Additionally, the calculated bandwidth of the data is extremely high, in the 200 Hz and greater range. These data were acquired with an I/O II system and deep-hole dynamite, illustrating the increase in resolution available with modern 24-bit systems. Because an oil show was reported in this zone during drilling for a deeper objective, a well was drilled to test a point bar identified in the 3-D data. Although no oil was found, an excellent point bar was encountered, which further authenticated the seismic survey's ability to provide stratigraphic detail about this shallow fluvial unit. This is significant, because most of the oil remaining to be found in this and other areas will come from stratigraphic traps.

Abstract The Apiay–Ariari oil field of the Llanos Basin, Colombia, is located within a structurally complex area. A 3-D seismic survey was necessary to understand the structural factors controlling the distribution of hydrocarbons within the field. The results of the interpretation were used in conjunction with core, production, and log data to complete an integrated reservoir evaluation. Time structure maps were converted to depth using geostatistical techniques which resulted in a more detailed realization of strike-slip, normal, and reverse faults, consistent with a right lateral shear system. The 3-D interpretation is also much more simplified than the 2-D interpretation. This integrated study realized an increase of field reserves of greater than 60.7 million bbl over those originally calculated. The study also identified several exploration plays, such as that successfully tested by the Gavan-1 well. The ability to fully integrate the new 3D seismic information with all available data resulted in a more accurate understanding of structural components responsible for the trapping of hydrocarbons within the Apiay–Ariari fields. This knowledge has proven to be essential for proper management of the field development.

Abstract The structural and stratigraphic framework of Maraven's Block I was re-interpreted using 3-D seismic and existing data as part of an evaluation of the remaining oil potential. More than 1800 MMBO have been produced from Block I in the past 40 years, mainly from structural traps. In order to maintain production levels, it has become increasingly important to define the seismic stratigraphic framework for the area and to accurately locate faults and stratigraphic pinchouts. The dominant structures are the Icotea fault, its conjugate fault system, and the Eastern Boundary fault. The most prominent fault is the NE-striking Icotea fault, which subdivides the area into two main structural blocks, a graben in the West Flank and a horst in the East Flank. The Icotea fault is a highly complex fault zone with a long history of deformation. It is a nearly continuous fault zone with both vertical and lateral offsets and is locally inverted. Along the eastern flank of the Icotea, prominent reverse-fault bounded upthrown blocks, called the Attic, have developed. Along the western flank, contraction has re-activated listric faults into reverse and thrust faults. Major northwest-striking normal faults delineate a large paleoarch that occurs in the south-center of the East Flank. This phase of faulting produced small horst and graben blocks bounded by normal faults that dip to the northeast and southwest. The Eastern Boundary fault is subparallel to the Icotea fault and is an east-dipping normal fault that has been locally inverted and occurs in a synclinal area of the block. Two play concepts, utilizing (1) horizontal wells in Attic and (2) vertical wells along the Eastern Boundary fault, were successfully tested during this study. The stratigraphic section includes, from oldest to youngest, pre-Triassic basement rocks; the Jurassic graben-fill Quinta Formation; the Cretaceous Rio Negro, Cogollo Group, La Luna, Colon, and Mito Juan formations; the Paleocene Guasare Formation; the Eocene Misoa Formation; the Miocene La Rosa, Lagunillas, and La Puerta formations; and the Quaternary El Milagro Formation. Only the lower part of the Eocene Misoa Formation (C sands) is preserved in Block I, and most of the Eocene B sands and all of the Pauji were either eroded or not deposited in this area. The main reservoirs occur in the Eocene Misoa Formation and the basal Miocene Santa Barbara member of the Lagunillas Formation. Sedimentation occurred throughout the Eocene and was strongly influenced by tectonism. The Eocene section in the horst block is up to 760 m thick and is bracketed by two major unconformities. The upper angular unconformity places the basal Miocene Santa Barbara member (16–25 Ma) over the Eocene Misoa C sands (45–54 Ma). The lower disconformity (54 Ma) occurs at the top of the Paleocene Guasare Formation. In between, eight seismic sequences occur within the Eocene horst section. The adjacent stratigraphic sections east and west of the horst block are thicker than the East Flank section. The C sands in Block I form a retrogradational clastic sequence deposited as transgressive (70–80%), highstand (10–15%), and lowstand wedge and incised valley fill (10–15%) systems tracts with prominent marine-flooding surfaces separating these systems tracts. The main reservoirs are thick-bedded transgres-sive sandstone deposits.

Abstract The Dirkala Field is located in the southern Murta block of Petroleum Exploration Licenses (PELs) 5 and 6 in the southern Cooper and Eromanga Basins of central Australia. Excellent oil production from a single reservoir sandstone in the Jurassic Birkhead Formation in Dirkala 1 had indicated a potentially larger resource than could be mapped volumetrically. The hypothesis that the resource was stratigraphically trapped led to the need to define the fluvial sand reservoir seismically and thereby prepare for future development. A small (16 km 2 ) 3-D seismic survey was acquired over the area in December 1992. The project was designed not only to evaluate the limits of the Birkhead sand but also to evaluate the cost efficiency of recording such small 3-D surveys in the basin. Interpretation of the dataset integrated with seismic modeling and seismic attribute analysis delineated a thin Birkhead fluvial channel sand reservoir. Geological pay mapping matched volumetric estimates from production performance data. Structural mapping showed that Dirkala 1 was optimally placed and that no further development drilling was justifiable. Seismic characteristics comparable with those of the Dirkala 1 Birkhead reservoir were noted in another area of the survey, beyond field limits. This led to the proposal to drill an exploration well, Dirkala South 1, which discovered a new oil pool in the Birkhead Formation. A post-well audit of the pre-drill modeling confirmed that the seismic response could be used to determine the presence of the Birkhead channel sand reservoir. The acquisition of the Dirkala 3-D seismic survey demonstrated the feasibility of conducting small 3-D seismic surveys to identify subtle stratigraphically trapped Eromanga Basin reservoirs at lower cost and risk than appraisal/development drilling based on 2-D seismic data.

Abstract Ping Hu Field, discovered in 1982 in the East China Sea, 365 km offshore China, consists of two structural closures on a complex, faulted anticline. Chinese authorities have planned for the field to provide natural gas to Shanghai in the 21st century. Five wells have been drilled, and more than 2400 km of 2-D and 118 km 2 of 3-D seismic data have been interpreted. Both structures were identified by 2-D data and drilled prior to acquisition of the 3-D seismic data. Interpretation included mapping key reservoirs and fault analysis. Reservoir composition, distribution, and lateral variations were described. These variations were determined by studying geophysical attributes of the data, which included instantaneous amplitude, frequency, phase, and acoustic impedance. Seismic data were inverted to acoustic impedance (density and velocity) and transformed into reservoir parameters. Crossplot regression analyses of petrophysical parameters were performed, and relationships between pairs of values of porosity, acoustic impedance, permeability, and water saturation were derived. An integrated geological–geophysical–reservoir engineering evaluation was required for accurate hydrocarbons-in-place calculations. The interpretation was utilized for field development planning, but implementation has been delayed due to distance from shore relative to field size.

Abstract The Saudi Arabian Oil Company has reduced development drilling costs and increased oil reserves by selecting well locations using 3-D seismic data in the Ghinah and Umm Jurf Fields, Central Saudi Arabia. 3-D seismic data provide more accurate structural interpretation of strike-slip structures, and more important, provide stratigraphic predictability within a heterogeneous braided stream reservoir. The success rate for wells with high flow rates (>2000 BOPD) has increased from 43% to over 90% since 3-D seismic data have been used to locate development wells. In addition, the cumulative reserves of the two fields have increased 400%.

Abstract Pickerill Field is a relatively thin, highly faulted gas reservoir in the southern gas basin of the North Sea. The 100- to 250-ft (30-to 76-m) thick, Permian Rotliegend reservoir consists primarily of thin dune and interdune deposits overlying generally poorer-quality fluvial sands. There is a rapid lateral variation in reservoir quality due to facies changes and compartmentalization due to diagenesis associated with faults. A combination of petrophysics and geophysics was used to develop seismic criteria that could be used to optimize the location of development wells. An analysis of horizon attributes from the 3-D seismic survey produced a detailed reservoir fault map. Analysis of log data, seismic modeling, and horizon attributes produced an estimated reservoir porosity map. These have been used to help optimize the position of development wells in the field. Adetailed interpretation was made of several horizons in the 3-D seismic survey, including the Top Rotliegend (top reservoir) reflection. A set of seismic horizon attributes, based on horizon structure and reflection amplitude, were generated at the Top Rotliegend. Reservoir faults with throws as small as 15 ft (5 m) were interpreted and mapped. Since many faults were sealed by diagenesis subsequent to faulting, these results have helped identify potential compartmentalization and have allowed development wells to be positioned away from these potential barriers to flow. Synthetic seismic modeling using log data from exploration wells indicated a linear relationship between reservoir reflection amplitude and average reservoir porosity. Log-based wavelet extraction was used to correct phase errors in the seismic data. Phase-corrected reflection amplitude from the Top Rotliegend reflection was correlated with porosity at exploration wells. The resulting empirical amplitude-porosity relationship has been used to successfully predict gross reservoir porosity in several wells drilled since the work was concluded.

Abstract Most deep-water development projects are planned using high-quality 3-D seismic data and sparse well control. Economic considerations require large reservoir volumes to be drained with relatively few wells. We have used 3-D seismic data to constrain large-scale, deterministic reservoir bodies in a 3-D architecture model of Pliocene turbidite sands of the “E,” or “Pink,” reservoir, Prospect Mars, Mississippi Canyon Areas 763 and 807, Gulf of Mexico. A geological interpretation derived from 3-D seismic data and three wells was linked to 3-D architecture models through seismic inversion, resulting in a reservoir rock property distribution incorporating all available data. High-resolution reprocessing of a high-quality marine seismic dataset resulted in the ability to deterministically map sedimentary reservoir bodies. Distinguishing subtle stratigraphic shingles from faults was accomplished by detailed, loop-level mapping and was important to characterize the different types of reservoir compartments. Seismic inversion was used to detune the seismic amplitude, adjust the sand-body thickness, and update the rock properties. This modeling project illustrates how high-quality seismic data and architecture models can be combined in a pre-development phase of a prospect, in order to optimize well placement.

Abstract The Green Canyon Block 205 prospect has five primary reservoirs, which range in age from late Pliocene to early Pleistocene. The N1 and N3 sands, which contain 60% of the resource in the prospect, were deposited primarily as turbidites in a middle- to lower-slope environment within bathyal water depths. Key uncertainties which affect fluid displacement paths and displacement efficiencies were defined during a detailed reservoir characterization. They include (1) facies type and distribution, (2) reservoir architecture, and (3) reservoir continuity. A probabilistic approach allowed the manipulation of a facies based geologic model to quantify the range of these and other reservoir uncertainties. Geologic and geophysical data indicate that the N1 and N3 sand lithofacies and their associated subenvironments are distinctly different. The N1 sand was deposited as a sand-rich, early lowstand fan by a series of low-density turbidity flows. Facies range from massive sand to thin-bed-ded turbidites, and subenvironments include channel, channel margin, levee, interchannel/overbank, and possibly fan fringe. The N3 sand was deposited as a very sandrich, middle-to-late lowstand fan by a series of high-density turbidity flows. It is composed of a massive sand facies within an amalgamated channel complex. A lateral offset stacking pattern, which became progressively younger to the west, is the dominant architectural element for both the N1 and N3 reservoirs. Relative to the N1 sand, the N3 sand exhibits a greater degree of overlap between successive depositional units and therefore has a higher probability of amalgamation. Drill stem test (DST)-type curve analyses indicate the presence of transmissibility restrictions in both sands, which correspond to discontinuities seen in the seismic data. In the N1 sand, the analyses indicate that fluid flow may not be inhibited between channel and thin-bedded facies but may be restricted between laterally offset depositional units. Seismically defined amalgamation surfaces in the N3 sand do not impede fluid flow within the radius of investigation of the DST.