Roger M. Slatt

Petroleum systems of deepwater settings

This course provides the working geophysicist with a broad overview of the petroleum systems of deepwater settings. The six main elements of petroleum systems will be covered: reservoirs, traps, seals, source rocks, generation, migration, and timing. The course is designed to teach students approximately 80% of what is important. For those interested in further study of a specific topic, each chapter has extensive references for the current literature. About 10% of the current cutting-edge information remains proprietary and cannot be included.nnDeepwater depositional systems are the one type of reservoir system that cannot be easily reached, observed, and studied in the modern environment, in contrast to other sili-ciclastic and carbonate reservoir systems. The study of deepwater systems requires many remote-observation systems, each of which can provide only one view of the entire depositional system. As a consequence, the study and understanding of deepwater depositional systems as reservoirs have lagged behind those of the other reservoir systems, whose modern processes are more easily observed and documented.nnFor this reason, geoscientists use an integrated approach, working in interdisciplinary teams with multiple data types (Figure 1-1). The types of data used in the study of deep-water deposits include detailed outcrop studies, 2D and 3D seismic-reflection data (both for shallow and deep resolution), cores, log suites, and biostratigraphy. These data sets are routinely incorporated into computer reservoir modeling and simulation (Figure 1-1).nnThe following chapters integrate all of these data types and disciplines to characterize the many facets of deepwater systems. Technologies for deepwater exploration and development are improving rapidly. The intent of the course is to provide information that will be usable even as the technologies advance beyond what we present here.nnWith that in mind, this chapter introduces basic deepwater terminology and concepts for deepwater systems that will be used throughout this book.nnGeoscientists routinely use several terms to describe the sedimentary processes and characteristics of deepwater settings and deposits. For the sake of consistency in this book, we define these terms as follows.nnThe term deep water is used informally in industry in two ways. First, deep water refers to sediments deposited in water depths considered to be “deep,” i.e., those under gravity-flow processes and located somewhere in the upper- to middle-slope region of a basin. Sediment gravity-flow processes are operative in lakes in relatively shallow water and in cratonic basins where water depths may be less than 300 m. Thus, unless stated otherwise, we use the term deepwater systems to refer to marine-sediment gravity-flow processes, environments, and deposits.

Developing and managing turbidite reservoirs – case histories and experiences: results of the 1998 EAGE/AAPG research conference

This paper summarizes the results of a joint EAGE/AAPG research conference that was convened in Almeria, Spain in October 1998. The theme of the conference was how to better produce deep-water reservoirs based on lessons learned from the past 25 years. A repeated message at the conference was that there is more complexity than anticipated in turbidite reservoirs, contrary to the expectations of many geoscientists. Such complexity may go unnoticed during initial depletion, and only be observed during secondary injection of fluids. Early recognition of shale occurrences and geometries, bed continuity, and stratigraphic variations in net-to-gross ratios appear to be the main issues related to maximizing well performance.

Outcrop-behind Outcrop (Quarry): Multiscale Characterization of the Woodford Gas Shale, Oklahoma

An outcrop-behind outcrop study was conducted in and adjacent to a 300 100 16 m (980 330 50 ft) quarry of the gas-producing Woodford Shale to structurally/stratigraphically characterize it from the pore to subregional scales using a variety of techniques. Strata around quarry walls were described and correlated to a 64 m (210 ft) long continuous core drilled 150 m (500 ft) back from the quarry wall and almost to the Woodford-Hunton unconformity. Borehole logs obtained include neutron and density porosity (NPHI and DPHI) logs, and logs from Elemental Capture Spectroscopy (ECS™), Combinable Magnetic Resonance (CMR-Plus™), Fullbore Formation MicroImager (FMI™), and sonic scanner (Modular Sonic Imaging Platform, or MSIP™)—all manufactured by Schlumberger. The strata around the quarry are horizontally bedded. Borehole logs were used to identify a basic threefold subdivision into an upper relatively porous quartzose interval; a middle, more clay-rich, and less porous interval; and a lower interval of intermediate quartz-clay content. These intervals correspond to the informally named upper, middle, and lower Woodford. Detailed core and quarry wall description revealed several types of finely laminated lithofacies, with varying amounts of total organic carbon (TOC). The FMI log revealed a much greater degree of variability in laminations than can be readily seen with the naked eye. Organic geochemistry and biomarkers are closely tied to these lithofacies and record cyclic variations in oxic-anoxic depositional environments, which correspond to relative sea level fall-rise cycles. At the scanning electron microscopy scale, microfractures and microchannels are common and provide tortuous pathways for gas (and oil) migration through the shales. Based on FMI and core analysis, fracture density is much greater in the upper quartzose lithofacies than in the lower, more clay-rich lithofacies. A laser imaging detection and ranging (LIDAR) survey around the quarry walls documented two near-vertical fracture trends in the quartzose lithofacies: one striking N85E with spacings of 1.2 m (4 ft) and the other striking N45E related to the present stress field. The FMI analysis only imaged the latter fracture set. Both log-derived and laboratory-tested geomechanical property measurements documented a significant relationship between shale fabric (laminations and preferred clay-particle orientation) and rock strength, and a secondary relationship to mineral composition. Porosity and microfractures or microchannels also appear to influence rock strength. This integrated study has provided insight into the causal relations among Woodford properties at a variety of scales. In particular, a stratigraphic (vertical) segregation of lithofacies can be related to cyclic variations in depositional environments. The resulting stratified zones exhibit variations in their hydrocarbon source and reservoir (fracturable) potential. Such information and predictive capability can be valuable for improved targeted horizontal drilling into enriched source rock and/or readily fracturable reservoir rock in the Woodford and perhaps other gas shales.

Morphology of Hydrocarbon Droplets During Migration: Visual Example from the Monterey Formation (Miocene), California

In this paper, we describe the various morphologies of hydrocarbon residue found in the Miocene Monterey Formation in California. Scanning electron microscope photomicrographs clearly show various shapes of hydrocarbon droplets in microchannels in the Monterey Formation and hence provide insight not only into the shape of hydrocarbon droplets during migration, but also about the migration pathways themselves. The small (5-10 µm) diameter droplets are observed to have various shapes that include spherical droplets, amalgamated droplets, sausage-shaped droplets, and elongate rod-shaped droplets. Observations suggest that hydrocarbon droplets move through the rock matrix into microchannels where they coalesce into larger droplets and then move into larger fractures. Dif erent morphologies are simply a result of amalgamation of simple droplets during migration.

Turbidite systems; Part 2, Subseismic-scale reservoir characteristics

Part I of this two‐part paper (TLE, April 1999) outlined the general types of turbidite systems (gravel‐rich, sand‐rich, mixed sand/mud, and mud‐rich) and their seismic stratigraphic and wireline log characteristics. In this paper, we summarize reservoir properties, their measurement and identification, and their value in predicting reservoir performance. Approximately 75% of the world’s giant turbidite fields have a stratigraphic component to their trapping mechanism (Pettingill, 1998), so we focus here only on stratigraphic and related properties.

From Geologic Characterization to 'Reservoir Simulation' of a Turbidite Outcrop, Arkansas, USA

Detailed geologic mapping and correlation of several outcrop exposures and subsurface core borings of the Lower Pennsylvanian, upper Jackfork Group in the DeGray Lake Spillway-Intake area of Arkansas have allowed us to develop a 5,600ft. X 1,600ft. X 90ft.

Visualization Technology for the Oil and Gas Industry: Today and Tomorrow

The fifth Archie Conference, Visualization Technology to Find and Develop More Oil and Gas, brought together 130 scientists and technologists to review current and future visualization technologies that are being developed and used in the petroleum and other industries. Visualization in the oil and gas industry can be considered a tool for characterizing and understanding surface and subsurface phenomena. In addition to allowing one to view and more easily understand large quantities of data, visualization is dramatically enhancing communications, and thus interaction, among members of integrated exploration and development teams. Current and potential end-users of visualization technology consider the most important aspects to include common formats for data interchang , greater availability to consultants and independents (perhaps through PC-based visualization hardware and software), bigger bandwidth capabilities to drive more powerful machines, and the application of sensitivity analysis to document uncertainty in visualizations at all scales. Visualization technology is in its infancy, but growing so rapidly that it promises to have major impact on many aspects of the petroleum industry, from improved day-to-day communications to better technology transfer and more powerful interpretive capabilities, all of which can ultimately lead to better economic decision making.

Outcrop-Behind Outcrop Characterization of Thin-bedded Turbidites for Improved Understanding of Analog Reservoirs: New Zealand and Gulf of Mexico

Well log, well test, and seismic data provide excellent structural and stratigraphic information on subsurface reservoirs, but may not be able to resolve small-scale vertical and lateral attributes which may control oil or gas production. Outcrops can provide this important information provided they are of sufficient areal extent. In this paper, we demonstrate the application of outcrop and behind-outcrop characterization for improved understanding of thin-bedded turbidite reservoirs in the Gulf of Mexico and elsewhere. A 200m high by 10km long coastal cliff section of the Late Miocene Mt. Messenger Formation, New Zealand consists of 200+ meters of thick-bedded turbidite fan sands and associated thin-bedded fan-fringe sandstone/siltstone, overlain by 300m of thin-bedded slope fan, levee/overbank sandstone/siltstone. This section was characterized at the seismic to individual bed scales. Also, 47 and 105m deep holes were drilled behind the cliff face, cored, and logged through the slope fan facies with Fullbore Formation Micro Imager and Platform Express* logs. A slope-fan model is presented which differentiates proximal levee facies composed mainly of discontinuous, erosionally-truncated Bouma Tb-c beds from distal levee/overbank facies composed of more continuous, thin-bedded strata owing to fewer truncations. An associated channel-fill facies is composed of sandstone/siltstone interbeds which become muddier upward. These three facies exhibit distinctive dip and borehole image patterns. The model demonstrates the application of outcrop-behind outcrop characterization for improved understanding of thin-bedded turbidites in analog reservoirs. For example, a permeability vs. lithofacies relationship established for the Mt. Messenger strata is common in Gulf of Mexico thin-bedded turbidites. Also, the thin-bedded levee/overbank reservoir facies of the Ram/Powell Field L sand in the Gulf of Mexico exhibits very similar features to those observed in outcrop and behind-outcrop cores and logs. Gas production rates of ∼100 MMCFD and 9600 BCPD have been achieved from a horizontal well placed in the L sand proximal levee facies. In the broader sense, interactive workstation analyses of lithology, bed thickness, and dip-set groupings seen in the high resolution, behind-outcrop borehole images were used to identify depositional cycles and facies transitions based upon calibration with core and outcrop patterns. The same image analysis methods have been applied to other exploration and production wells in the Gulf of Mexico; one Neogene turbidite example is illustrated.

Turbidite systems; Part I, Sequence and seismic stratigraphy

With the increased emphasis on deepwater exploration and development globally, considerable work has been done to understand turbidite systems. These are defined as sediments initially deposited in deep water, and which may now occur in the deeper parts of sedimentary basins (sometimes in great water depths). These deposits have been studied in terms of the lithofacies distribution, reservoir architecture, 2-D and 3-D seismic appearance, and their production capabilities. There are considerable stratigraphic variabilities in turbidite systems that affect reservoir performance and development plans. The petroleum industry’s increased understanding of these variabilities and their effects has occurred through the integration of a number of disciplines: 2-D and 3-D seismic, wireline logs, biostratigraphy, cores, petrophysics and rock properties, reservoir simulation, and outcrop studies for building semiquantitative reservoir models.

Stratigraphic and Structural Compartmentalization Observed Within a Model Turbidite Reservoir,"Pennsylvanian Upper Jackfork Formation, Hollywood Quarry, Arkansas: ABSTRACT"

Hollywood Quarry is a 600 x 375 x 150 ft. (200 x 125 x 50m) excavation which provides a window into lower Pennsylvanian Jackfork Formation turbidite stratal architecture along the crest of a faulted anticlinal fold. A variety of turbidite facies are present, including: (a) lenticular, channelized sandstones, pebbly sandstones, and conglomerates within shale, (b) laterally continuous, interbedded thin sandstones and shales, and (c) thicker, laterally continuous shales. The sandstone and shale layers we broken by several strike-slip and reverse faults, with vertical displacements of up to several feet. This combination of facies and structural elements has resulted in a highly compartmentalized stratigraphic interval, both horizontally and vertically, along the anticlinal flexure. The quarry can be considered analogous to a scaled-down turbidite reservoir. Outcrop gamma-ray logs, measured sections, a fault map, and cross sections provide a database which is analogous to what would be available for a subsurface reservoir. Thus, the quarry provides an ideal outdoor geologic and engineering {open_quote}workshop{close_quote} venue for visualizing the potential complexities of a combination structural-stratigraphic (turbidite) reservoir. Since all forms of compartmentalization are readily visible in the quarry, problems related to management of compartmentalized reservoirs can be discussed and analyzed first-hand while standing in themorexa0» quarry, within this {open_quote}model reservoir{close_quotes}. These problems include: (a) the high degree of stratigraphic and structural complexity that may be encountered, even at close well spacings, (b) uncertainty in well log correlations and log-shape interpretations, (c) variations in volumetric calculations as a function of amount of data available, and (d) potential production problems associated with specific {open_quote}field{close_quote} development plans.«xa0less