Abstract The long-term production history of some offshore and onshore Gulf Coast reservoirs reveals that gas production exceeds assigned reserves for no readily apparent reason. The distinct possibility exists that surrounding shales contribute significant quantities of gas during the reservoir lifecycle. Direct evidence for economic gas production from non-fractured shale intervals comes from the Devonian of the Appalachian Basin and from Tertiary-Pleistocene reservoirs in the Gulf of Mexico. Intergranular pores occur between detrital clay particles in true shales of the Devonian interval. The ability of this intergranular pore system to transmit gas (permeability) is controlled primarily by the microfabric of the shale. It is reasonable, therefore, to expect that Gulf Coast shales with similar internal characteristics will yield sufficient gas to impact reservoir economics. The Gulf Coast area contains significant proportions of sediments deposited in distal deltaic and deep water environments. These environments produce thick, fine grained “shale” intervals that, in reality contain numerous thin (<1 inch) laminations of porous and permeable silt and/or sand separated from one another by layers rich in clay minerals (true shales). Given a large number of silt/sand interbeds, sufficient permeability thickness can be developed in the interval to yield gas at high rates. Routine methods of log analysis fail to resolve the thin-bedding in these pay intervals, many of which are therefore bypassed. Reserve calculations can also be significantly effected by gas production from true shales in traditional reservoir settings (such as the Wilcox Formation). The amount of gas recovered in reservoirs developed in relatively thin sand bodies (generally <50ft) can be increased by gas migration from surrounding shales during production-related pressure depletion of the main reservoir body. Improved reserve calculations require that potentially productive shales are included in all aspect of reservoir evaluation, from petrophysics to simulation.

Abstract An integrated geological/petrophysical and reservoir engineering study has been performed for a large, mature waterflood project (>250 wells, 80% water cut) at the North Robertson (Clear Fork) Unit, Gaines County, Texas. The primary goal of the study was to develop an integrated reservoir description for “targeted” 10-ac (4-ha) infill drilling and future recovery operations in a low- permeability carbonate reservoir. Integration of geological/petrophysical studies and reservoir performance analyses provided a rapid and effective method for developing a comprehensive reservoir description. This reservoir description can be used for reservoir flow simulation, per-formance prediction, infill targeting, waterflood management, and optimizing well developments (patterns, completions, and stimulations). The following analyses were performed as part of this study: Geological/petrophysical analyses: (core and well log data) Rock typing based on qualitative and quantitative visualization of pore- scale features. Reservoir layering based on rock typing and hydraulic flow units. Development of a core-log model to estimate permeability using porosity and other properties derived from well logs. The core-log model is based on “rock types.” Engineering analyses: (production and injection history, well tests) Material balance decline type curve analyses performed to estimate total reservoir volume, formation flow characteristics (flow capacity, skin factor, and fracture half-length), and indications of well/boundary interference. Estimated ultimate recovery analyses yield movable oil (or injectable water) volumes, as well as indications of well and boundary interference. Well tests provide estimates of flow capacity, indications of formation damage or stimulation, and estimates of drainage (or injection) volume pressures. Maps of historical production characteristics (contacted oil-in-place, estimated ultimate recovery, and reservoir pressure) have been compared to maps generated from the geologic studies (rock type, permeability/thickness, hydrocarbon pore volume) to identify the areas of the unit to be targeted for infill drilling. Our results indicate that a close relationship exists between the rock type distribution and permeability calculated using porosity and other properties derived from well logs. The reservoir performance data also suggest that this reservoir depletes and recharges almost exclusively according to the rock type distribution. This integration of rock data and the reservoir performance attributes uses existing data and can eliminate the need for evaluation wells, as well as avoiding the loss of production that occurs when wells are shut-in for testing purposes. In short, a comprehensive analysis, interpretation, and prediction of well and field performance can be completed quickly, at a minimal cost, and this analysis can be used to directly improve our understanding of reservoir structure and performance behavior in complex formations.

Abstract The modern fore arc basin of Guatemala receives non-marine sediments as a result of deposition of airfall ash, glowing avalanches (nuées ardentes), debris flows (lahars), and fluvial sediments. The lateral and vertical distribution of these deposits allows ready subdivision into four facies, including 1) the volcanic core facies, 2) proximal volcan- iclastic facies, 3) medial volcaniclastic facies, and 4) distal volcaniclastic facies. Recent sediments of the study area have been deposited during the past 20,000 to 30,000 years, in a series of similar and repeated cycles. Each cycle consists of four phases: 1) The Inter-Eruption Phase (Phase 1) which is characterized by low rates of sediment deposition, incision of meandering streams, and delta reworking. This phase has a duration of 80 to 125 years. 2) The Eruptive Phase, (Phase 2) dominated by the ejection of airfall ash and glowing avalanches. This phase generally lasts less than one year. 3) The Fan Building Phase (Phase 3) dominated by debris flows and the deposition of coarse grained fluvial sediment. This phase lasts for some two years after an eruption. 4) The Braiding Phase, (Phase 4) characterized by the introduction of large volumes of sediment into the stream systems, resulting in the transformation of the incised meandering channels to rapidly aggrading, braided channels, and rapid deltaic progradation. This phase lasts for some 20 to 30 years following an eruption. Phases 3 and 4 are triggered only by major eruptions which produce more than 6 × 10 7 m 3 ejecta. Smaller eruptions do not significantly affect the sedimentation system. Non-marine volcaniclastic sedimentation therefore proceeds as a series of relatively short-lived pulses (20 to 30 years duration) separated by longer periods (80 to 125 years duration) of comparatively minor depositional activity. The failure of the sedimentary system to respond in a similar fashion to all eruptions, indicates the existence of a geomorphic threshold, controlled entirely by the amount of ejecta produced during an eruption. In areas, dominated by fluvial activity (generally the distal volcaniclastic facies) the geologic record consists of superimposed or interdigitating deposits from braided and meandering streams. The change from braiding to meandering is not a function of change in slope or rainfall. Rather it is a response to the amount of sediment introduced into the fluvial systems.