Douglas S. Hamilton

Geological and hydrological controls on the producibility of coalbed methane

Geological and hydrological comparison of two United States coalbed methane basins, the prolific San Juan Basin and the marginally producing Sand Wash Basin, indicates that coal distribution and rank, gas content, permeability, ground-water flow, and depositional and structural setting are critical controls on coalbed methane producibility. A complex interplay, and moreover, a synergy amongst these controls determines high productivity. This paper proposes a basin-scale explanation for the prolific and marginal production in the two basins and that can be applied to evaluation of coalbed methane potential in coal basins worldwide. High productivity is governed by (1) thick, laterally continuous coals of high thermal maturity, (2) basinward flow of ground water through coals of high rank and gas content orthogonally toward no-flow boundaries (regional hingelines, fault systems, facies changes, and/or discharge areas), and (3) conventional trapping along those boundaries to provide additional gas beyond that sorbed on the coal surface.

3-D seismic imaging and seismic attribute analysis of genetic sequences deposited in low‐accommodation conditions

A multidisciplinary team, composed of stratigraphers, petrophysicists, reservoir engineers, and geophysicists, studied a portion of Boonsville gas field in the Fort Worth Basin of North‐Central Texas to determine how modern geophysical, geological, and engineering techniques could be combined to understand the mechanisms by which fluvio‐deltaic depositional processes create reservoir compartmentalization in a low‐ to moderate‐accommodation basin. An extensive database involving well logs, cores, production, and pressure data from 200‐plus wells, 26-mi2 (67km2) of 3-D seismic data, vertical seismic profiles (VSPs), and checkshots was assembled to support this investigation. The reservoir system we studied was the Bend Conglomerate, a productive series of gas reservoirs composed of Middle Pennsylvanian fluvio‐deltaic clastics 900 to 1300 ft (275 to 400 m) thick in our project area. We were particularly interested in this reservoir system because evidence suggested that many of the sequences in this stratigr...

Approaches to Identifying Reservoir Heterogeneity and Reserve Growth Opportunities in a Continental-Scale Bed-Load Fluvial System: Hutton Sandstone, Jackson Field, Australia

We applied an integrated geologic and engineering approach devised to identify heterogeneities in the subsurface that might lead to reserve growth opportunities in our analysis of the Hutton Sandstone at Jackson field, Eromanga basin, Australia. Our approach involves four key steps: (1) determine geologic reservoir architecture, (2) investigate trends in reservoir fluid flow, (3) integrate fluid-flow trends with reservoir architecture, and (4) estimate original oil in place, residual oil saturation, and remaining mobile oil to identify opportunities for reserve growth. Although the Hutton reservoir is interpreted as the deposit of a continental-scale bed-load fluvial system and is dominated by highly permeable sandstone, the genetic stratigraphic analysis identified numerous thin, but widespread, shale units deposited during lacustrine flooding that periodically interrupted episodes of coarse clastic Hutton deposition. These shales represent chronostratigraphically significant surfaces, but more importantly, the trends in reservoir fluid flow, established from monitoring aquifer encroachment, production response to water shut-off workovers, and differential depletion in repeat formation tests, indicate that these shale units act as efficient barriers to vertical fluid flow. Erosion of the upper part of the Hutton reservoir by the younger Birkhead mixed-load fluvial system caused further stratigraphic complexities, introducing additional barriers to vertical and lateral migration of mobile oil and aquifer encroachment. These stratigraphic complexities were not fully appreciated in previous field development and production strategies, and the potential exists for incremental reserve growth through geologically targeted infill drilling and recompletions.

Approaches to identifying reservoir heterogeneity in barrier/strandplain reservoirs and the opportunities for increased oil recovery: an example from the prolific oil-producing Jackson-Yegua trend, south Texas

Abstract The Jackson-Yegua Barrier/Strandplain sandstone play is a prolific oil-producing trend in south Texas, although it is characterized by low recovery efficiencies. Low oil gravity, weak solution gas drive, complex stratigraphy and structural complications contribute to low recoveries. This is despite very high average porosity (31%) and permeability (600 mD). There is potential for substantial reserve growth by targeting the remaining mobile oil resource. Seventy-Six West is a typical field of the Jackson-Yegua play. Detailed reservoir characterization of this field indicates a highly complex reservoir architecture consisting of a mosaic of strike-oriented barrier-core, shoreface and inner shelf shoal sandstones and mudstone-rich back-barrier/lagoonal deposits that are cross-cut by dip-oriented tidal inlet fills and fluvial channels. Reservoir continuity is further disrupted by small-scale (10–100 ft; 3–30.5m) normal faults and dip reversals. Production trends are controlled by the complex reservoir sandstone geometry and faults, and eight discrete compartments are interpreted from the reservoir architecture, structure and trends in oil and water production. This internal reservoir heterogeneity provides potential for bypassed mobile oil in untapped compartments and partially swept zones in waterflood areas and, thus, defines targets for infill drilling and highlights the opportunity to optimize waterflood design. A new field discovery was made and a potential field extension also defined. The case study at Seventy-Six West is applicable to all Jackson-Yegua fields and will ultimately help to increase oil recovery. Furthermore, the approaches outlined here are not unique to barrier/strandplain reservoirs such as the Jackson-Yegua play and have application to all siliciclastic reservoirs where low recovery efficiencies indicate the likelihood of bypassed mobile oil.

Integrating 3-D seismic imaging and seismic attribute analysis with genetic stratigraphy; implications for infield reserve growth and field extension, Budare Field, Venezuela

Despite being a mature oil producer, the Budare Field in the Eastern Venezuela Basin offers considerable reserve growth potential because of stratigraphic and structural complexity. Our ability to resolve these complexities was enhanced following acquisition in 1995 of a 3-D seismic data set over a large part of the field. The seismic data were tied by synthetic to well-log data by several wells having sonic and density information and then integrated with the high-resolution genetic stratigraphic framework established from well-log correlations. Two key surfaces identified on the seismic data correlated directly to two stratigraphically defined sequence boundaries, maximum flooding surfaces (MFS) 80 and 100. A third seismic surface correlated approximately with the stratigraphically defined MFS 62. Collectively, these surfaces form fundamental control surfaces from which seismic attribute analysis and imaging from inverse modeling were undertaken. Four depositional trends detected by the seismic imaging and attribute analysis have important implications for reserve growth potential, guiding future field development. An incised valley, filled primarily with thick fluvial sandstones, was detected by mapping average seismic amplitudes between the MFS 62 and 80 markers, and several step-out drilling locations were identified where the sandstones intersect structurally high positions. The distribution of thick distributary-mouthbar facies, and moreover, the boundary with adjacent thin-bedded strandplain facies, were similarly detected by mapping average seismic amplitudes in a 35-ms time window below MFS 80. The mouth-bar facies coincide with the crestal position of a potentially large, structurally defined field extension supporting multiple potential infill wells. Several high-negative-amplitude anomalies coinciding with thick fluvial sandstones overlying MFS 62 display faulted boundaries and are interpreted as direct hydrocarbon indicators, providing obvious infill drilling locations, and finally, a marine ravinement surface separating the key oil-producing reservoirs below MFS 80 was identified by seismic inversion.

Reactivation of mature oil fields through advanced reservoir characterization: A case history of the Budare field, Venezuela

Budare field has produced 95 million bbl of oil since discovery in 1954, but a sustained 6 yr decline during the early 1990s reduced daily production to 3000 bbl of oil. Reactivation of the field as a result of this reservoir characterization study increased production by 13,000-16,000 BOPD, a rate that has been maintained in the 4 yr since the study was completed, resulting in an incremental recovery of more than 24 million bbl of oil. This increase in production was achieved through integrated reservoir characterization that identified the depositional heterogeneities and structural complexities responsible for intrareservoir entrapment of the bypassed oil in the field. The main producing zones are the Tertiary-age Merecure and Oficina reservoirs that are interpreted as the deposits of large-scale bed-load and mixed-load fluvial and wave-dominated deltaic depositional systems. The geologic analysis indicates that the large-scale systems are divided internally, or vertically stratified, by thin but widespread shale markers resulting from flooding episodes and that facies variability introduces lateral discontinuities. Syn- and postdepositional faulting further disrupts reservoir continuity. Trends in fluid flow established from engineering analysis of initial fluid levels, response to recompletion workovers, and pressure depletion data demonstrated that these geologic heterogeneities (flooding shale markers, lateral facies pinch-out, and faults) are effective barriers to lateral and vertical fluid flow. Considerable potential for sustained production exists at Budare field because the reservoir units are highly compartmentalized. Identification and targeting of the poorly drained and uncontacted compartments at Budare facilitated the development of a production optimization portfolio that encompassed four principal advanced-recovery opportunities: field extension or step-out; attic areas of the reservoir that are structurally higher than existing production and, hence, poorly drained; stratigraphically and structurally defined compartments that have not been tapped; and compartments that are poorly drained. Successful geologically targeted infill wells and strategic recompletions in these bypassed compartments achieved a sustained fivefold increase in daily production in the mature Budare field.

Characterization of reservoirs in the Tertiary section of Block B in the south of Lake Maracaibo

Substantial hydrocarbon resources reside in stratigraphically and structurally complex Tertiary reservoirs in South Lake Maracaibo, but in Block B (Figure 1), production to date has amounted to little more than 70 000 barrels. This poor production performance motivated Lagoven SA, an affiliate of Petroleos de Venezuela SA, to initiate a joint contract with the Bureau of Economic Geology to investigate the reservoir characteristics and ultimately to produce commercially the hydrocarbons in place. The primary objectives of the study were (1) to identify the remaining oil reserves in the Tertiary reservoirs of Block B through integrated geologic, geophysical, and engineering analysis and (2) to develop drilling and completion strategies to exploit the existing reserves. To understand the fundamental characteristics of the reservoir and design a development program that incorporates the inherent reservoir heterogeneity, the Bureau applied a four‐step procedure: (1) determine geologic reservoir architecture wi...

Abstract: Potential Use of Geothermal Fluids for Thermally Enhanced Recovery of Heavy Oil in South Texas

ABSTRACT In a five-county area of South Texas, geopressured-geothermal reservoirs in the Eocene Wilcox Group occur below heavy-oil reservoirs in the Eocene Jackson Group. This co-location warrants consideration of the use of geothermal fluids for a thermally enhanced water flood. Geothermal fairways comprise thick deltaic sandstone within growth-fault-bounded compartments containing geopressured water in excess of 250° F. Geothermal reservoirs occur at depths of 11,000 to 15,000 ft in continuous sandstones 100 to 200 ft thick. Permeability ranges from 1 to 150 md, and porosity from 12 to 24 percent. Updip pinchout of shallowly buried (200 to 2,000 ft) barrier-bar/strandplain sandstones largely controls the distribution of heavy-oil reservoirs. Subtle structure, small faults, and sandbody pinchouts form lateral barriers of the reservoirs. Structural, depositional, and diagenetic variations affect reservoir compartmentalization. The heavy-oil reservoirs are typically porous (25 to 35 percent) and permeable (100 to 1,000 md), slightly clayey, fine to medium sand. Calcite-cemented zones of low porosity (>5 percent) and permeability (0.01md) compartmentalize reservoirs. Injection of hot (300° F) moderately fresh to saline brines will improve oil recovery by lowering viscosity and decreasing residual oil saturation. Matrix clays are smectites, which could swell and clog pore throats if injected waters were fresh. The high temperature of injected fluids will collapse some of the interlayer clays, thus increasing porosity and permeability. Reservoir heterogeneity resulting from facies variation and diagenesis must be considered when siting production and injection wells within the heavy-oil reservoir. The suitability of abandoned gas wells as geothermal production wells and their long-term well productivity also affect the economics of geothermally enhanced hot-water flooding. End_of_Record - Last_Page 855-------