Vicksburg Formation Research Articles

Structural and stratigraphic controls on reservoir architecture: A case study from the lower Oligocene Vicksburg Formation, Brooks County, Texas

A detailed structural and stratigraphic framework provides a precise understanding of the controls on the vertical and spatial distribution of reservoir units, as well as the identification of the most prospective hydrocarbon accumulation. In southern Brooks County, Texas, the Lower Oligocene Vicksburg Formation (LOVF), is being influenced by the Vicksburg Fault Zone (VFZ). This zone is characterized by listric-normal faults that have formed highly faulted rollover anticlines, which are valuable structural traps for hydrocarbon exploration. This study integrated 568 3D seismic lines, 39 well logs, and three velocity surveys to build a comprehensive conceptual model that explores how secondary synthetic (dipping east), antithetic (dipping west), and Texas Gulf Coast-perpendicular faults are influencing accumulation and spatial distribution of hydrocarbons within the LOVF (La Rucias Field). Results indicate that synthetic, antithetic, and coast-perpendicular faults affecting the V-102, V-17, and V-19 horizons provide conduits for hydrocarbon migration. Antithetic faults and coast-perpendicular faults within the rollover anticline are terminating beneath an overlying shale seal layer between the V-16 and V-17, influencing economic hydrocarbon accumulations through multiple reservoirs. While synthetic faults affect the overlying seal layer migrating hydrocarbon out of the V-102, V-17, and V-19, bidirectional faulting linking antithetic and coast-perpendicular faults provide additional pathways for hydrocarbon accumulation. Spatial distribution of hydrocarbons varies with the targeted horizon. V-102 reservoirs are situated on the western flank of the rollover anticline, whereas the V-17 and V-19 reservoirs are located on structural highs where overlying shale seal layer remains unaffected by the antithetic faults. V-17 and V-19 reservoirs are influenced by bidirectional faulting that terminates beneath the shale seal layer, enabling the accumulation within the rollover anticline. Petrophysical and lithological investigations of the seal layers within the V-102, V-17 and V-19 are highly recommended for better understanding of vertical compartmentalization of reservoir intervals and accumulation estimates within the La Rucias Field. Investigating the control of these fault systems enhances our understanding of subsurface fluid migration and accumulations (oil, gas, groundwater, and contaminants) in the expanded Vicksburg productivity trends. Furthermore, the insights gained from the examination of these fault systems not only contribute to our comprehension of subsurface fluid migrations within the Vicksburg trends but also serve as a valuable reference for similar geological systems and reservoirs worldwide, ultimately aiding in the development of more effective resource management.

Application of thin-bed indicator and sweetness attribute in the evaluation of sediment composition and depositional geometry in coast-perpendicular subbasins, South Texas Gulf Coast

My focus of study is the nature of sediments within late Eocene to middle Oligocene, coast-perpendicular subbasins located on the southwest side of the San Marcos Arch in Refugio County, near the South Texas Gulf Coast. Methods of investigation consist of 3D seismic interpretation, seismic attribute, and isochron mapping. Depositional geometry, inferred sediment composition, and bed-thickness data are examined by extraction of amplitude-envelope, sweetness, and thin-bed-indicator (TBI) attributes from the 3D seismic volume. Four subbasins, numbered SB1 through SB4 from northeast to southwest, are recognized. Although the coast-perpendicular subbasins formed at the same time and by the same processes, the sediment distribution, basin-fill history, and tectonics differ from subbasin to subbasin within the Jackson, Vicksburg, and Frio Formations. Amplitude envelopes extracted at base Jackson and at near-base Vicksburg Formation show that, although the distribution pattern of interpreted sandstone-prone sediments within each subbasin is mainly of sheet geometry, SB2 displays a pattern of short, narrow, linear features. Based on available well control, the sweetness and TBI attributes correlate well with [Formula: see text]. Crossplots between [Formula: see text] and sweetness exhibit a strong, linear, negative relationship — the sweetness value increases as the [Formula: see text] value decreases, suggesting an increasing sandstone content. In contrast, crossplots between [Formula: see text] and TBI exhibit a positive linear relationship — the TBI value increases as the [Formula: see text] value increases, suggesting an increasing shale content. Because the sweetness attribute may in some cases not detect some thin shale bed within a stratigraphic interval, it may overestimate the net:gross ratio. Therefore, a combined TBI and sweetness procedure is required to determine the net:gross ratio. The results show that the net:gross ratio decreases from SB1 closest to the San Marcos Arch, to SB4 farthest into the Rio Grande Embayment. The approach adopted in this study can be used to estimate net:gross ratios in frontier areas.

Pitfalls in the seismic interpretation of fault shadow events — Vicksburg formation of south Texas

Reliance on prestack time-migrated seismic data to define structural highs without incorporating all subsurface data and without taking into account the regional and local lateral depositional trends may result in dry holes or poorly positioned production wells due to local velocity changes, which are usually caused by some depositional or structural phenomenon. Tying check-shot control to depositional units may reveal those phenomena and permit assumptions to be made about velocities in areas beyond check-shot control points. We discovered a significant gas accumulation in an area surrounded by dry holes and marginal wells in the Vicksburg Formation in McAllen Ranch Field, Hidalgo County, Texas, by treating a seismic velocity anomaly as a geologic problem and by simple application of arithmetic and geometry to a 3D velocity model. Due to the effects of the anomaly, seismic data displayed in time gave no indication of the existence of a 325 ha (800 ac), 150 BCFG anticlinal structure. A subsurface model that accounted for the velocity anomaly was able to predict its extent and severity by readily identifiable thickness changes in the anomalous units. The resulting discovery yielded a sevenfold increase in field production within a two-year time span.

Structural evolution of a detached delta system—the Vicksburg of south Texas

The Oligocene Vicksburg formation of South Texas was deposited as a coarse clastic delta system on the fringe of the uplifted Sierra Madre mountains in Mexico. Earliest Vicksburg sediments were initially deposited in a simple delta lobe, which detached due to gravity from underlying Eocene formations and crept seaward as a block, creating a depositional center. The upper Early Vicksburg contains expanded sets of deltaic sediments which infilled a depression formed by the initial movement. Downlap surfaces indicate that the expansion was oriented northeast-southwest. Middle Vicksburg uplift in the Sierra Madre mountains to the south caused erosion and a change in strike direction to northeast-southwest and a significant change in structural style. West to easterly oriented ridges formed in conjunction with significant north-south, en-echelon, counter-regional growth faults. The ridges later accumulated hydrocarbons in deformed sandstones. Counter-regional faults formed as a deeper detachment within the underlying Eocene during Late Vicksburg time. This resulted in formation of two different structural provinces. The Slick Ranch Field province illustrates a complex extensional zone dominated by horst and graben structures. In contrast, the McAllen Ranch Field province is simpler, without Late Vicksburg extension. One of the keys to successful exploitation of the Vicksburg is unraveling extensive, low angle, discontinuous fault sets that dominate the majority of rotated fault blocks. These faults formed during growth and rotation of individual slump structures. Faulting occurred when curvature on listric fault planes was reduced and the slump rotated to a horizontal position. When rotation was complete, all the curvature from the base of the slump was transposed to the upper surface. Subsequent low angle faults dissected the crest of the slumps. The study area, in Starr and Hidalgo counties, South Texas (Figure 1), borders the Rio Grande River and Mexico. More than six trillion ft3 of gas and …

ABSTRACT: Developing an Exploration Tool in a Mature Trend: a 3D AVO Case Study in South Texas

Summary Successful exploration for new reservoirs in mature trends often requires trying techniques unproven in the area. The Vicksburg Formation in South Texas has been heavily explored using subsurface geology and structural mapping based on conventional seismic data. Although there is a scarcity of direct hydrocarbon indicators such as bright spots, models generated using dipole sonic data suggested that Class 2 AVO anomalies would be associated with gas reservoirs. A pilot reprocessing study demonstrated that gas reservoirs generate Class 2 AVO anomalies and that incident angles greater than about 26o are required to observe them. A large non-exclusive 3D survey was reprocessed using non-hyperbolic moveout and resulting angle stacks were analyzed. Several untested anomalies were identified, including stratigraphic traps. Wildcat drilling based on this effort has resulted in six commercial discoveries and two dry holes, a success rate significantly higher than was achieved through conventional subsurface geology and structural mapping.

Origin and Growth Mechanism of Authigenic Chlorite in Sandstones of the Lower Vicksburg Formation, South Texas

ABSTRACT Authigenic chlorite, occurring as grain coatings, pore fillings, and rosettes, is common in deltaic sandstones of the lower Vicksburg Formation in South Texas. Chlorite rosettes are isolated and occur late in the diagenetic history, whereas grain-coating and pore-filling chlorite occur early, predating the development of secondary porosity and the precipitation of quartz overgrowths and Fe-poor calcite. Grain-coating and pore-filling chlorite, which are interstratified with approximately 15 percent 7 A layers, are Fe-rich with a mean Fe/(Fe+Mg) ratio of 0.68. Stable-isotope data (18O averages 13.5o/oo (SMOW)) indicate that the grain-coating and pore-filling chlorite began precipitating between 20°C to 40°C within the upper 1.8 km (6000 ft) of burial. Sandstones of the lower Vicksburg Formation were deposited in a relatively shallow deltaic environment as part of a large fluvial system draining the volcanics of Sierra Madre Occidental, Mexico and Trans Pecos, Texas. Weathering of these volcanics brought large amounts of particulate Fe to the river mouth. An increase in salinity in the distributary channel complex caused Fe flocculation and deposition. During periods of high river discharge, or when coastal currents acted to concentrate particulate Fe, large amounts of particulate Fe were deposited in the delta system. This resulted in thick layers of Fe-rich clay (odinite?) around grains. During periods of low river discharge, or when coastal currents caused wide distribution of particulate Fe, less particulate Fe was deposited. It is proposed that the grain-coating and pore-filling chlorite began forming through the transformation of an Fe-rich clay precursor in the formation-water hydropressure zone following Ostwald processes. The presence of this synsedimentary Fe-rich clay, and its recrystallization to Fe-chlorite, strongly influenced fluid flow and played a large role in developing the diagenetic heterogeneity seen in lower Vicksburg sandstones today.

ABSTRACT: Sequence Stratigraphy as a Major Control of Depositional Facies of the Vicksburg Formation in the South Texas Gulf Coast Area

ABSTRACT: Sequence Stratigraphy as a Major Control of Depositional Facies of the Vicksburg Formation in the South Texas Gulf Coast Area

Pore Pressure/Stress Coupling and its Implications for Seismicity

Periodic pressure measurements made during the depletion of oil fields and virgin pressure measurements through normally- and over-pressured sequences in sedimentary basins both demonstrate that changes in pore pressure and minimum horizontal stress (σh) are coupled to one another. Pore pressure/stress coupling is predicted by poroelastic theory. Data from the North Sea (Ekofisk Field) and Texas (Travis Peak Formation of east Texas and Vicksburg Formation of south Texas) suggest that σh decreases at approximately 80% and 50% of the rate of depletion of reservoir pore pressure respectively. Virgin pressures in overpressured sedimentary basins suggest that σh increases at approximately 60-80% of the rate of increase in pore pressure in the Canadian Scotian Shelf, the Australian North West Shelf and the Gannet/Guillemot Fields area of the North Sea. The total vertical stress (σv) is given by the weight of the overburden and is unaffected by changes in pore pressure. Hence, contra to simple, uncoupled models of the effect of pore pressure on rock failure, differential stress in normal fault regime basins (σv - σh) increases as pore pressure decreases, and decreases as pore pressure increases. Increased differential stress with decreased pore pressure can account for depletion-induced seismicity, despite effective stresses increasing. Decreased differential stress with increased pore pressure implies that a greater increase in pore pressure can be withstood prior to failure than would otherwise be predicted, and increases the propensity of tensile, rather than shear failure, occurring with overpressure development.

Abstract: Variations and consistencies of depositional patterns within one sequence across three structural elements: Vicksburg Formation, Texas

Abstract: Variations and consistencies of depositional patterns within one sequence across three structural elements: Vicksburg Formation, Texas

ABSTRACT: A Re-Evaluation of the Hackberry--New Life for a Comatose Trend

Abstract The Oligocene Hackberry trend of southeast Texas and southwest Louisiana has posed one of the Gulf Coast's most perplexing targets for petroleum exploration. Thick, high-quality pays and moderate drilling depths have lured many explorationists to try to unlock its potential. However, reservoir extent has, in the past, been unpredictable. The play was all but abandoned during the late 1980s and early 1990s. A regional re-evaluation of the geologic model arose from the assimilation of well log correlations, dipmeter use and evaluation, interpretation of paleontological reports, and the combination of quality 2-D seismic data. From this work it became very apparent that the majority of the trend should be interpreted as a sub-unconformity/slump block play and not a deep-marine, basin-floor/turbidite sequence. The new model predicted reservoir extent and thickness concisely and logically. The history of the trend is one of prograding shallow-marine deposition from the lower Frio Formation through the Nodosaria blanpiedi and Nonion struma zones, followed by thick shallow-water deposition of up to 500 feet of strand plain sands in the upper Frio Formation. Basin collapse, resulting from regional salt withdrawal and development of salt domes, caused over-steepening of the sea floor. The result was slumping of the soft sediments from the underlying Vicksburg Formation through the early Upper Frio strand plain deposits. Wave-base erosion removed most of the youngest sand section. The erosion was followed by marine shale deposition containing the diagnostic Hackberry faunal assemblage. As subsidence ceased and the basin finally filled with shale, shallow-marine strand plain deposition continued through deposition of the upper Frio section. Armed with this geologic model, a group of industry partners partook to gather regional 3-D seismic coverage in order to take advantage of more than 500 undrilled square miles that still existed in the trend. Eventually the effort resulted in 25 successful wells out of 30 attempts. End_of_Record - Last_Page 281-------

Abstract: Origin of Chlorite Grain Coats in Sandstones of the Lower Vicksburg Formation, South Texas 

Abstract: Origin of Chlorite Grain Coats in Sandstones of the Lower Vicksburg Formation, South Texas 

Evaluation of Fracture Treatments Using a Layered-Reservoir Description: Field Examples

Summary This paper presents a practical analysis technique to determine actual fracture geometry and proppant profile using a three-dimensional (3D) hydraulic-fracturing simulator. The hydraulic-fracturing model used in this study considers the variation of in-situ stress, Young's modulus, Poisson's ratio, and net pay thickness in the productive interval.1–4 When our method is applied, the results from the fracture propagation model conform well with the results we obtain from pressure-buildup and production-data analyses. This study analyzed hydraulic-fracturing treatments from several wells in the Vicksburg formation of the McAllen Ranch area in south Texas.5,6 We have provided guidelines to properly describe the treatment interval, how to use this information in the analysis of such fracture treatments, and how to confirm the results using pressure-transient tests and production-data analyses. This paper presents examples illustrating that a detailed description of the reservoir layers is essential to properly evaluate hydraulic-fracture treatments. For the example wells presented in this paper, post-fracture-production and pressure-transient data were available. We have analyzed production and pressure-transient data to estimate permeability and fracture half-length. The values of fracture half-length used to analyze the production data matched closely with those predicted by the fracture model.

Effects of Diagenesis on Enhanced-Resolution Bulk Density Logs in Tertiary Gulf Coast Sandstones: An Example from the Lower Vicksburg Formation, McAllen Ranch Field, South Texas

Diagenetic heterogeneity strongly influences porosity and permeability distribution in sandstone reservoirs of the lower Vicksburg Formation. Enhanced-resolution bulk density logs, which use a 3-cm (1.2-in.) rather than the standard 15-cm (6-in.) sampling increment, offer important new information in understanding diagenetically complex sandstones in the subsurface. Detailed petrographic mapping and sedimentologic description of core from the Oligocene lower Vicksburg Formation of McAllen Ranch field, south Texas, have identified cement variations that result in diagenetic zones ranging in thickness from 0.1 cm (0.04 in.) to 0.9 m (3 ft). The petrographic and petrophysical properties of these diagenetic zones define three diagenetic facies that can be correlated with log esponse from the enhanced-resolution bulk density log: (1) the quartz-cemented facies, averaging 13% porosity and 0.342 md permeability, and having a recorded density greater than or equal to 2.43 g/cm3 but less than 2.48 g/cm3, (2) the chlorite-cemented facies, averaging 16.7% porosity and 0.193 md permeability, and having a recorded density less than 2.43 g/cm3, and (3) the calcite- or transitional-cemented facies, averaging 9.4% porosity and 0.04 md permeability, and having a recorded density greater than or equal to 2.48 g/cm3. Intervals cemented with different minerals are identified by the enhanced-resolution bulk density log based on the ranges in density that define each diagenetic facies. This identification of diagenetic facies not only influences the accurate determination of the net sandstone thickness and porosity of reservoirs within the lower Vicksburg Formation, but also directly controls permeability calculations. For example, classification of cement intervals from lower Vicksburg gas reservoirs using enhanced-resolution bulk density logs and porosity and permeability regressions for each of the diagenetic facies results in estimated permeability thicknesses as much as 50% greater than those calculated using standard log analysis. Because standard log analysis ignores the effects of diagenetic eterogeneity, the use of the enhanced-resolution bulk density log provides significant information that leads to more accurate reservoir and field evaluations in diagenetically complex sandstones.

Effects of Diagenesis on Enhanced-Resolution Bulk Density Logs in Tertiary Gulf Coast Sandstones: An Example from the Lower Vicksburg Formation: ABSTRACT

Effects of Diagenesis on Enhanced-Resolution Bulk Density Logs in Tertiary Gulf Coast Sandstones: An Example from the Lower Vicksburg Formation: ABSTRACT

The Vicksburg Formation of Texas: Depositional Systems Distribution, Sequence Stratigraphy, and Petroleum Geology

The lower Oligocene Vicksburg Formation of the Gulf Coastal plain contains major petroleum reservoirs in the Rio Grande embayment and is an economically viable target in other areas of Texas. Knowledge of the distribution of Vicksburg depositional systems is essential to understanding sandstone concentrations and, therefore, is fundamental to effective exploration and production of the Vicksburg section. The depositional setting of the Vicksburg reservoirs, their position in a sequence stratigraphic framework, and the influence these factors have on the petroleum geology of the Vicksburg are the focus of this paper. Surface and subsurface geological and geophysical data provided the framework for an analysis of the depositional systems and the petroleum geology of the Vic sburg. The two primary Texas Vicksburg depocenters, the Rio Grande embayment and the Houston embayment, are separated by the San Marcos arch, a deep-rooted structural nose. Within the embayments, sand-rich deltaic complexes merged along strike with barrier/strand plains. Contemporaneous growth faulting controlled depositional patterns of shelf-edge deltas in the Rio Grande embayment, but had only a minor effect on the configuration of the shelfal deltas in the Houston embayment. Smaller wave-dominated shelf delta complexes interspersed with barrier/strand plains extended across the San Marcos arch. Updip of these sandy paralic depocenters, fluvial systems traversed mud-rich coastal plain units. Seaward of the paralic systems, sand and mud deposits prograded across and built up over the r lict Jackson shelf and shelf-margin shales. These depositional complexes are contained in the systems tracts of one eustatic (Exxon) sequence. Vicksburg production from each of the three structural regions of Texas is characterized by reservoirs from different systems tracts and of distinct, different depositional origins.

Deltaic Depositional Systems on an Unstable Shelf Margin, Vicksburg Formation, South Texas

Deltaic Depositional Systems on an Unstable Shelf Margin, Vicksburg Formation, South Texas

Relationships between Cement, Rock Fabric, Porosity and Permeability, Lower Vicksburg Formation, McAllen Ranch Field, South Texas

Detailed petrographic mapping of cement distribution, combined with sedimentologic description and petrophysical data, is a powerful technique for describing distribution of reservoir properties. Two cores from the lower Vicksburg Formation, McAllen Ranch field, south Texas, indicate that porosity and permeability, which vary over several orders of magnitude, are related to a complex interplay between centimeter-scale cement variations, grain size, sedimentary structures, and the development of secondary porosity. Porosity and permeability plugs in combination with thin section analysis, taken every 5 cm through several representative intervals, reveal the complex controls on reservoir properties. For example, within an upward-coarsening interval a strong relationship exists between grain size, the development of secondary porosity, and permeability. The coarsest sands of the interval are cemented by quartz overgrowths and variable amounts of calcite. The preferential development of secondary porosity in this 'band' results in an average permeability of 0.169 md. In contrast, as grain size decreases, calcite cementation increases, resulting in a decrease in the development of secondary porosity and an average permeability of 0.008 md. When chlorite is the predominant cement, permeability is dependent on the development of secondary porosity and is independent of grain size. Within a chlorite-cemented interval, with a relatively constantmore » measured porosity of 16.6 ({plus minus}1)%, permeability ranged from 0.026 md to 0.372 md. Secondary porosity ranged from 1.5% to 5.5% over this same interval. These variations, which occur in distinct bands in core, result in a complex but predictable distribution in porosity and permeability.« less

Depositional Systems Distribution of the Lower Oligocene Vicksburg Formation, TX: ABSTRACT

Depositional Systems Distribution of the Lower Oligocene Vicksburg Formation, TX: ABSTRACT

Petroleum Geology of the Vicksburg Formation, Texas: ABSTRACT

Petroleum Geology of the Vicksburg Formation, Texas: ABSTRACT

Diagenesis and Cement Fabric of Gas Reservoirs in the Oligocene Vicksburg Formation, McAllen Ranch Field, Hidalgo County, Texas: ABSTRACT

ABSTRACT McAllen Ranch field produces natural gas from 12 deep, overpressured sandstone reservoirs, each interpreted to be the deposit of a prograding shelf-edge delta. Correlation of petrographic and sedimentologic features reveals a predictable pattern of sandstone cementation. The sandstones are feldspathic litharenites containing subequal proportions of volcanic rock fragments (VRF), feldspar, and quartz grains. Grain size ranges from very fine to coarse sand. Porosity is mostly secondary, having formed through dissolution of VRF and feldspar grains. Four major diagenetic facies in cored reservoir rock can be grouped by the predominance of one diagenetic cement type and by appearance in hand specimen: (1) calcite-cemented; (2) chlorite-cemented, tight; (3) chlorite-cemented, porous; and (4) quartz overgrowths, porous. The calcite-cemented facies predominates in very fine-grained sandstones and siltstones and encroaches into adjoining sandstones irrespective of grain size. Core permeabilities are generally less than 0.01 md, and porosities range from 7% to 15%. Authigenic chlorite generally cements sandstones intermediate in grain size between those cemented by calcite and those cemented by quartz. Two types of diagenetic chlorite fabric are interbedded, forming distinct alternating bands 0.1 in (0.25 mm) to 3 ft (1 m) thick. In the tightly chlorite-cemented facies, permeabilities are less than 0.3 md, and porosities range from 8% to 16%. In the porous chlorite-cemented facies, dissolution of framework grains and early yellow chlorite cement increased porosity, and a second coarsely crystalline chlorite cement was precipitated. Core permeability ranges from 0.1 to 1 md, and porosities range from 15% to 20%. The quartz overgrowth facies occurs in 1- to 2-ft-thick (0.3- 0.6-m) zones within the coarsest grained sandstones. Although these overgrowths constitute only 5% of the rock volume, they are the predominant cement. A relative abundance of intergranular pores results in permeabilities ranging from 1 to 20 md. Porosities range from 15% to 20%. Three depositional facies are present in McAllen Ranch reservoirs: (1) mid-delta-front deposits that are characterized by thin upward-fining sequences; (2) massive upper delta-front sandstones; and (3) distributary channel-fill sandstones. The diagenetic facies are localized into a distinct pattern within each depositional element. Mid-delta-front upward-fining sequences 0.5 to 5 ft thick (0.2 to 1.6 m) are cemented by calcite at the base and top. Porous and tightly cemented chlorite bands occur in the middle of the upward-fining sequences, with the proportion of porous bands increasing toward the top. Within massive delta-front sandstones, porous and tightly chlorite-cemented bands are commonly parallel to sedimentary structures. Distributary channel fills consist of thicker (10 to 20 ft), poorly sorted, upward-fining sandstones. The basal 1 to 2 ft (0.3 to 0.6 m) of the distributary channel fills, where underlain by shales, are tightly cemented with calcite. Porous, quartz-cemented diagenetic facies form 1- to 2-ft-thick (0.3- to 0.6-m-) intervals in the coarsest grained sandstones. The rest of the coarse channel fill is dominated by porous, chlorite-cemented facies. The upper, finer grained portions of the channel fills are tightly cemented with chlorite and calcite. A predictable relationship between depositional facies and diagenetic facies allows extrapolation of the distribution of cements and the resultant reservoir characteristics to uncored wells and intervals with the objective of maximizing recovery of natural gas.