Lower Cretaceous Travis Peak Formation Research Articles

Opening-mode fracture systems: insights from recent fluid inclusion microthermometry studies of crack-seal fracture cements

Abstract Overpressuring, tectonic stretching and thermoelastic contraction are all processes that can drive the formation of opening-mode fractures in the subsurface. Recent studies on crack-seal quartz deposits in opening-mode fractures have yielded fluid inclusion microthermometric data, which for the first time allow us to constrain the pressure–temperature conditions under which these fractures formed. Here, we utilize the results from studies in the Lower Cretaceous Travis Peak Formation in the East Texas Basin and the Upper Cretaceous Mesaverde Group in the Piceance Basin to construct stress history models based on mechanical properties, burial history and tectonic setting to evaluate the various driving mechanisms for opening-mode fracture formation. Our results show progress towards separating and independently evaluating these mechanisms. Although high fluid pressure and tectonic stretching can play a major part in the formation of opening-mode fractures, our results suggest that the persistence of fracture growth during uplift could have been strongly influenced by thermoelastic contraction associated with exhumation and cooling. For sandstone reservoirs, thermoelastic contraction will be more pronounced for stiffer, high Young's modulus rocks with higher quartz contents. These models can therefore be used to provide additional insights into the distribution of opening-mode fractures in exhumed basins.

Dimensions and quality of reservoirs originating in low and high sinuosity channel systems, Lower Cretaceous Travis Peak Formation, East Texas, USA

Abstract Quantification of the dimensions and quality of fluvial reservoirs requires knowledge of channel style, depositional environment and diagenesis. Two styles of fluvial channel co-existed during the rapid aggradation of >600 m of Lower Cretaceous, Travis Peak sediments in East Texas: (1) high sinuosity (meandering) channels, and (2) low sinuosity (straight) channels. Each was restricted to a specific geographic area, the result of long-term, geomorphic stability. In both channel systems, reservoir sandstones originated principally in channel and crevasse splay environments. Reservoir models developed through sedimentological analysis are similar to those developed independently through reservoir simulation studies. Reservoir sandstones originating as point bars in high sinuosity channel systems are relatively small (1.2 km 2 or less), thin (3.6 m), heterogeneous, and isolated within non-pay mudrocks. Reservoir sandstones originating as medial and transverse/oblique bars in the low sinuosity system are areally extensive (>20 km 2 ) thick (3.6 to 13.7 m), homogeneous, and display complex pressure relationships due to avulsion of long stream segments, and the lateral and vertical stacking of successive channels in well-defined channel belts. The greatest volume of channel sandstone occurs in the low sinuosity channel system. The high sinuosity system is dominated by overbank deposits. Travis Peak sandstones have been extensively modified by compaction and cementation. Despite extensive diagenesis, permeability values reflect original depositonal environment and bedding style, even in rocks which have lost more than 80% of their original, depositional porosity. Channel sandstones have higher permeability than associated splay sandstones. Within a channel sandstone, the highest values of permeability occur in destratified, and flat- to low-angle cross-bedded sandstones: planar cross-bedded and ripple-bedded sandstones have the lowest values of permeability. Original depositional environment and bedding style exercise important control on permeability (particularly potential gas flow) even in rocks in which the pore systems have been modified significantly by diagenesis. A knowledge of depositional environment and bedding style is therefore important in predicting potential producibility in tight, gas sandstones such as the Travis Peak formation.

Evolution of Porosity and Permeability in the Lower Cretaceous Travis Peak Formation, East Texas (1)

Porosity and permeability decrease significantly with depth in low-permeability, gas-bearing Travis Peak sandstones on the western flank of the Sabine arch, east Texas. The Travis Peak Formation is approximately 2000 ft (610 m) thick and is buried to depths of 6000-10,000 ft (1830-3050 m). Reservoirs consist chiefly of sandstones of fluvial and paralic origin. Thin-section and core-analysis data from a total of 3680 ft (1122 m) of core from 26 wells indicate that both depositional environment and diagenetic history influenced the present distribution of porosity and permeability. Porosity in clean sandstones decreases from an average (geometric mean) of 16.6% at 6000 ft (1830 m) to 5.0% at 10,000 ft (3050 m). Permeability is reduced four orders of magnitude over the same depth range, from an average (geometric mean) of 10 md at 6000 ft (1830 m) to 0.001 md at 10,000 ft (3050 m). Loss of porosity by mechanical compaction took place mainly within the first 3000 ft (900 m) of burial, prior to significant cementation. The observed decline in porosity and permeability with depth between 6000 and 10,000 ft (1830 and 3050 m) results from (1) increasing quartz cement, (2) decreasing secondary porosity, and (3) increasing overburden pressure that closes narrow pore throats. At any given depth, average permeability is 10 times higher in clean fluvial than in clean paral c sandstones. Clean fluvial and paralic sandstones contain similar volumes of quartz cement, but paralic sandstones are finer grained and contain an average of 7% more total cement.

Depositional, Diagenetic, and Structural Controls on Reservoir Properties of Low-Permeability Sandstone, Travis Peak Formation, East Texas

ABSTRACT The Lower Cretaceous Travis Peak Formation in East Texas is a low-permeability gas-bearing sandstone that commonly requires hydraulic fracture treatment to produce at economic rates. Stratigraphic, petrographic, and structural characterization of the Travis Peak has resulted in information that can be used by operators to evaluate and complete these reservoirs more efficiently. Depositional systems of the Travis Peak Formation in this region include braided to meandering fluvial, deltaic, and paralic systems. Reservoirs in the upper Travis Peak are tidal-channel, tidal-flat, and meandering fluvial channel sandstones, whereas reservoirs in the lower Travis Peak are braided fluvial deposits in wide channelbelts. Mudstones through out the Travis Peak are highly silty and thus do not stop vertical growth of hydraulic fractures created during well stimulation. As a result, hydraulic fractures are circular and may connect several stacked sandstones. Petrographic studies indicate that extensive quartz cement is the major cause of low permeability in Travis Peak sandstones. Because the volume of quartz cement increases with depth, matrix porosity and permeability decrease. However, natural fractures are more abundant in structurally deeper, more intensely quartz-cemented sandstones than in shallower sandstones. Mean azimuth of natural fractures is N80°E. Drilling-induced fractures and borehole breakouts indicate that maximum horizontal stress (SHmax) is oriented east-northeast, which is the direction in which hydraulic fractures will propagate. Because the hydraulic fractures propagate in a direction subparallel to the natural fractures, hydraulically induced fractures may not intersect as many natural fractures as they might if SHmax had some other orientation relative to fracture strike.

Episodic Quartz Cementation in the Lower Cretaceous Travis Peak Formation, East Texas: ABSTRACT

Episodic Quartz Cementation in the Lower Cretaceous Travis Peak Formation, East Texas: ABSTRACT

History of Quartz Cementation in the Lower Cretaceous Travis Peak Formation, East Texas

ABSTRACT Quartz is the most abundant authigenic mineral in sandstones of the Travis Peak Formation in East Texas, but the extent of quartz cementation varies widely. To determine major controls on quartz cement distribution, this study used 431 thin sections from 1,100 m of core from 26 wells. Volume of detrital clay matrix is the main textural control on quartz cement. In sandstones lacking detrital clay, no significant correlation exists between quartz cement and grain size, sorting, bed thickness, or sedimentary structure. Depositional facies was an indirect control on quartz cement distribution because facies controlled detrital matrix content, but no significant difference exists between average quartz cement volume in matrix-free paralic (16.7%) and matrix-free fluvial (17.1%) sandstones Quartz cement increases significantly with present depth from an average of 14.6% at 1,825 m to 20.0% at 3,050 m. This trend of increasing quartz cement is interpreted to be the result of 1) an early episode of quartz cementation by meteoric water that resulted in relatively uniform distribution of quartz within the formation, and 2) a later episode related to the development of stylolites that preferentially added quartz cement in the deepest sandstones. Approximately 10 to 20% of the authigenic silica in Travis Peak sandstones was derived internally from intergranular pressure solution and stylolitization; the remaining 80% was imported from unknown sources outside the sandstones.

Paleostress directions from the preferred orientation of closed microfractures (fluid-inclusion planes) in sandstone, East Texas basin, U.S.A.

Closed extensional microfractures are useful indicators of paleostress directions in shallowly buried quartz-cemented quartz-arenites of the Lower Cretaceous Travis Peak Formation, a tabular sandstone and shale unit approximately 670 m thick that was deposited in the gradually subsiding northern Gulf of Mexico basin. The closed microfractures are syndiagenetic fluid-inclusion-rich planes that have an ENE strike that is subparallel to contemporary quartz-filled extension veins and regional normal faults, indicating that closed microfractures contain the maximum paleostress direction. These microstructures are potentially useful for mapping paleostress trajectories in passive margin and platform settings, particularly where samples are obtained from core. Previous experimental studies of microfracture closure suggest that microfractures evolved into fluid-inclusion planes by dendritic quartz precipitation. In East Texas, microfracture closure may have occurred at temperatures as low as 85°C and depths as shallow as 1500 m.

Fracture Detection in Low-Permeability Reservoir Sandstone: Comparison of BHTV and FMS Logs to Core: ABSTRACT

Detection and characterization of fractures in low-permeability reservoirs is an important goal of reservoir analysis. Natural fractures may increase porosity in low-permeability rock and may enhance or limit the success of hydraulic fracture treatment. Two logging tools used for fracture detection are the borehole televiewer (BHTV), an acoustic device that maps the smoothness of the borehole wall, and Schlumberger's Formation Microscanner (FMS), a resistivity tool that produces a conductivity map of two 2.8-in. wide strips of the borehole wall. Their analysis compares BHTV and FMS logs to 1028 ft of core from three wells in the 2000-ft thick Lower Cretaceous Travis Peak Formation, a sandstone and shale unit that produces gas from low-permeability sandstone in east Texas. Core was obtained from depths of 5900 to 9900 ft. The Travis Peak provides a good test of fracture-imaging logs because natural fractures have complex geometry and variable mineral fill and because there are borehole breakouts, drilling-induced fractures, and vertical sedimentary structures that must be distinguished from natural fractures for successful fracture analysis.

Controls on Permeability Distribution in Lower Cretaceous Travis Peak Formation, East Texas: ABSTRACT

Porosity and permeability decrease significantly with depth in low-permeability, gas-bearing Travis Peak sandstones on the western flank of the Sabine uplift. The Travis Peak Formation is about 2000 ft thick and is buried to depths of 6000-10,000 ft. Thin-section and core-analysis data from 3550 ft of core from 25 wells indicate that both depositional environment and diagenetic history influenced the present permeability distribution. Reservoir sandstones are divided into two main types: fluvial sandstones deposited in a sand-rich environment and paralic sandstones deposited in mud-rich environments. Paralic sandstones are finer grained than fluvial sandstones (average of 0.12 mm vs 0.17 mm, matrix-free sandstones only) and thus probably had lower original permeability.

Subsurface fractures and their relationship to stress history in East Texas basin sandstone

Subsurface fractures were sampled with more than 400 m of core from the Lower Cretaceous Travis Peak Formation, a tabular sandstone and shale unit approximately 600 m thick that was deposited in the gradually subsiding Gulf Coast basin. Depth to the top of the formation in East Texas now ranges between 1800 and 2900 m. Fractures in sandstone exhibit features that are due to intermittent fracturing and sealing (“crack-seal”), which suggest that the fractures are the result of episodes of fluid pressure in excess of hydrostatic. Correlation of the vein-mineral precipitation sequence with the diagenetic history and the results of previous δ 18 O studies of quartz cement, indicates that fractures propagated at depths of between 900 and 1500 m during the migration of quartz-precipitating fluids. Fracture permeability provides a mechanism for the passage of large fluid volumes recorded by the precipitation of extensive quartz cement in the formation. Fractures stopped propagating before maximum burial depth was achieved. During approximately 1500 m of subsequent burial, fractures either remained partly open or were sealed by postkinematic ankerite and clay minerals.

Cementation and burial history of a low-permeability quartzarenite, Lower Cretaceous Travis Peak Formation, East Texas

Fine-grained quartzarenites (and subar-koses) in the Lower Cretaceous Travis Peak Formation were extensively modified during burial diagenesis. Timing of diagenetic events can be constrained by combining petrographic and geochemical data with data on subsidence and thermal history. The geothermal gradient in the East Texas study area is 38 °C/km now, but it may have been as high as 44 °C/km when the Travis Peak was deposited because of elevated heat flow caused by crustal stretching associated with rifting of the Gulf of Mexico. Illite rims and dolomite were the first authigenic minerals to precipitate in Travis Peak sandstones. Dolomite probably formed soon after deposition at about 25 °C from water with a δ 18 O composition near SMOW. Next, extensive quartz cement, averaging 17% of the rock volume in well-sorted sandstones, occluded much of the primary porosity. The average δ 18 O composition of the quartz overgrowths indicates that they precipitated from meteoric fluids at temperatures of between 55 and 75 °C, at depths of 1 to 1.5 km. Dissolution of orthoclase and albitization of plagioclase followed quartz cementation and occurred prior to mid-Cretaceous movement of the Sabine Uplift. Illite, chlorite, and ankerite precipitated after feldspar diagenesis. The ankerite may have precipitated over a range of temperatures from about 80 to 125 °C, from fluids with δ 18 O composition of about +2‰ (SMOW); +2‰ is the average present composition of Travis Peak water. Most diagenesis ended when oil migrated into the Travis Peak. Later de-asphalting of the oil by solution of gas filled much of the remaining porosity with reservoir bitumen in some zones near the top of the formation.

Significance of Natural and Coring-Induced Fractures in Travis Peak Formation for Reservoir Stimulation: ABSTRACT

ABSTRACT Efficient hydraulic facture treatment of low-permeability sandstone gas reservoirs depends on an assessment of natural-fracture length, width, and abundance and on reliable predictions of the stimulation-fracture strike, which generally is parallel to the maximum horizontal stress. Analysis of 565 natural and coring-induced fractures in more than 1,800 ft of whole core from seven wells in the Lower Cretaceous Travis Peak Formation in East Texas (Fig. 1), together with borehole televiewer and other fracture-imaging logs from three wells, shows that (1) the abundance, physical properties, and orientation of natural fractures could potentially affect the success of hydraulic fracture treatment and (2) the orientation of coring-induced petal and petal-centerline fractures can be used to infer the direction of stimulation-fracture propagation. Reservoir sandstone in the Travis Peak contains subvertical natural extension fractures that are locally open in the subsurface with widths of as much as 0.2 in (5 mm) (Fig. 2) at depths of greater than 9,900 ft in hydrostatically pressured rocks. Fractures are more abundant in the hinges of gentle monoclines and in sandstone with pervasive quartz cement. Natural fractures strike east-northeast (Fig. 3), but they are not precisely parallel to the direction of stimulation-fracture propagation. During hydraulic fracture treatment, these characteristics will tend to cause fracture branching, curvature, and development of auxiliary fractures. The resulting tortuous fracture network, variable fracture widths, and potential for leakoff of treatment fluid could promote screenout and, consecquently, inefficient fracture treatment, if not considered in fracture treatment design. Figure 1. Structural setting of the study area (outlined by box) in the northern Gulf of Mexico basin. FIGURE 2. [Grey Scale] Natural extension fracture in Travis Peak Formation sandstone at 9842 ft (3000 m), S.A. Holditch & Associates SFE No. 2, Nacogdoches County, TX. Long dimension of the photograph is 4.7 in (12 cm). Figure 3. Rose diagram of natural extension-fracture attitudes in the Travis Peak Formation, East Texas. End_of_Record - Last_Page 591-------

Organic Geochemistry of Lower Cretaceous Travis Peak Formation, East Texas Basin: ABSTRACT

Organic Geochemistry of Lower Cretaceous Travis Peak Formation, East Texas Basin: ABSTRACT

Pore Characterization by Scanning Electron Microscope of Low-Permeability Gas Sandstones, Travis Peak Formation, East Texas: ABSTRACT

The scanning electron microscope (SEM), used in conjunction with thin-section petrography and mercury-injection analysis, is a valuable tool to evaluate authigenic cements, pore size, and pore geometry in low-permeability sandstones of the Lower Cretaceous Travis Peak Formation, east Texas. Abundant cements, which include quartz, ankerite, illite, and chlorite, are the main cause of low permeability in these quartzarenite and subarkose sandstones. In addition, reservoir bitumen occurs in zones near the top of the formation, and where abundant, it further reduces porosity and permeability. SEM and mercury-injection analysis distinguished two types of pore systems in Travis Peak samples. Matrix-rich sandstones have less authigenic cement and higher porosity and permeability than do matrix-free sandstones. Values of pore-aperture radii have a unimodal distribution, most radii being between 0.1 and 5 ..mu..m. Under SEM, the larger pores were identified as intergranular and solution pores; micropores (pore-aperture radii less than 0.5 ..mu..m) occur among detrital clay minerals. In contrast, sandstones that lack detrital clay matrix have abundant authigenic cement and reservoir bitumen, and lower values of porosity and permeability. These sandstones have a bimodal distribution of pore-aperture size, the major mode being 0.1-0.5 ..mu..m and the minor mode being less than 0.055 ..mu..m in radius.more » Most of the larger pore apertures in these samples (0.1-0.5 ..mu..m) seem to be associated with micropores in clay minerals, and solution pores, and the smallest pore apertures (less than 0.055 ..mu..m) seem to occur within the reservoir bitumen. In a sample with 18% reservoir bitumen, one-third of the total pore-aperture radii is less than 0.055 ..mu..m in diameter.« less