Gas-bearing Sandstones Research Articles

Effects of Diagenesis on Reservoir Properties and Log Response, Upper Jurassic Taylor Sandstone, Cotton Valley Group: ABSTRACT

The Taylor Sandstone in Terryville field, Lincoln Parish, Louisiana, is one of many tight gas-bearing sandstones of the Upper Jurassic Schuler Formation, Cotton Valley Group. This coastal strand-plain sandstone is fine to very fine grained, well sorted, with grains that are subrounded to well rounded. It is highly quartzose with an abundance of carbonate cement and lesser concentrations of quartz cement, clay precipitates, and pyrite. Mechanical compaction has caused a 10% reduction in primary porosity with increasing overburden. Chemical diagenesis has altered the texture and composition of the sandstone and has affected porosity and permeability through cementation, dissolution, and authigenic clay precipitation. Early stages of diagenesis included pyritization, mechanical compaction, and hinderance of compaction by precipitation of quartz cement at grain contacts. The middle stages were dominated by carbonate cementation, which replaced large amounts of detritus and quartz cement and reduced primary porosity to irreducible limits. Finally, the latest stages of diagenesis included development of secondary porosity by localized dissolution of replacive and interstitial carbonate and reduction of porosity by precip tation of pore-lining and pore-filling illite and illite/smectite clays. Poor permeabilities in the sandstone are a direct consequence of incomplete dissolution of carbonate in pore throats and the obstruction of voids by the late clay precipitates. The conductive property of authigenic pyrite has affected the response of the deep induction resistivity log, consequently causing abnormally high calculated water-saturation values in the Taylor Sandstone. The effect pyrite has on formation resistivity can be clearly seen on Rt-^phgr plots (Pickett method). Formation resistivity is affected even at low percentages of pyrite, and shows an exponential decrease with increasing pyrite concentration. A correction of resistivity was made possible by determining End_Page 1430------------------------------ pyrite concentrations in the laboratory. Furthermore, the Rt-^phgr plot may confirm the presence of pyrite in a sandstone where core samples are not available. End_of_Article - Last_Page 1431------------

Geologic and Engineering Parameters Used in Stimulating Tight Gas-Bearing Sandstones by Modified Hydraulic Fracturing Techniques: North Douglas Creek Arch Field, Colorado: ABSTRACT

Low-permeability gas-bearing sandstones present in basins of the Rocky Mountain area are commonly bounded by lithologies that are not barriers to hydraulically induced fracture migration. Use of standard hydraulic fracture treatments commonly results in most of the induced fracture area developing outside of the pay zone. Modified hydraulic fracturing techniques may be employed to optimize placement and penetration of the induced fracture area when the geologic and in-situ stress properties of boundary and pay zone lithologies are known. Laboratory and field efforts have been made to improve stimulation treatments in the Mancos B formation within the North Douglas Creek Arch field near Rangely, Colorado. To evaluate these efforts, a combination of core analyses and in-situ stress measurements was used in developing a modified hydraulic fracturing program. Whole core samples were taken from upper and lower boundary lithologies as well as within the Mancos B pay zone for special core tests including gas permeabilities, static elastic moduli, fracture toughness, and fluid compatibility tests measured at simulated in-situ conditions. Reservoir quality within pay zones was determined by a combination of petrography, x-ray diffraction, and scanning electron microscopy. In-situ minimal horizontal stress was determined in the field from instantaneous shut-in pressure (ISIP) data which were measured in all three lithologies. One modified hydraulic fracturing technique that has been field tested and shows promising results is based on fracture initiation placement (perforation placement). A second technique to be tested in the near future will use lightweight additives in fracturing fluids to help seal vertical propagation of hydraulically induced fractures, thereby insuring a deep penetrating fracture into the pay zone. End_of_Article - Last_Page 938------------

Structural Influences on Facies Distribution in Silurian Medina Group of Northwestern New York: ABSTRACT

The gas-bearing sandstones of the Medina Group in western New York are the basal Whirlpool Sandstone and the Grimsby Sandstone. Toward the west, these are separated by the Cabot Head Shale and the Manitoulin Limestone. Farther east, the Grimsby overlies and interfingers with the Whirlpool. The reservoir is underlain by the Ordovician Queenston Shale and is capped by shales of the Silurian Clinton Group. The depositional sequence of the Medina Group may be summarized as a marine transgression toward the east that yielded the Whirlpool, Cabot Head, and Manitoulin formations, followed by westward progradation of the deltaic Grimsby formation. Aspects of internal stratigraphy noted in subsurface studies may be correlated with anomalies in units much higher in the Silurian section and with disturbances on the Silurian-Devonian unconformity. Repetitive adjustments of large-scale structural features are inferred. These changes mark the transition from the westward-facing depositional front of the Ordovician to development of the isolated basins that dominated the Silurian Period. End_of_Article - Last_Page 1926------------

Stratigraphy and Depositional Environments of Catskill Deltaic Sequence, Northern West Virginia: ABSTRACT

The deltaic sequence (Upper Devonian-Lower Mississippian) is inadequately mapped and subdivided in the subsurface of northern West Virginia (central Appalachian basin). Stratigraphic interpretations are often hindered by the liberal use of drillers' names for noncontemporaneous gas-bearing sandstones. Base-line analysis of 275 gamma-ray logs permits the resolution of lithostratigraphic units in this sequence. Five regionally mappable units are recognized, within which the position, geometry, trend, and distribution of reservoir sandstones are interpreted. Three units are within the Upper Devonian Chemung Formation, and two are considered equivalents of the Hampshire (Upper Devonian) and Pocono (Lower Mississippian) Formations. Stratigraphic cross sections graphically display relative thickness variations of reservoir sandstones and document the inter-tonguing facies of the deltaic sequence that are attributable to cyclic marine transgression and regression, and/or to changing sedimentation or subsidence rates in the basin. Five lithofacies (A-E) are identified by the study of equivalent strata on outcrop. Facies A consists of gray shales and thin-bedded siltstones, interpreted as interbedded hemipelagic shales and turbidites. Facies B is comprised of thick-bedded and amalgamated siltstones and sandstones containing hummocky cross-stratification, representing composite storm deposits of the shelf and slope. Facies C consists of thick-bedded to massive clean sandstones and interbedded red and gray shales, interpreted as barrier-beach and back-barrier deposits. Facies D is dominated by red beds (silty mudstones and siltstones) with some interbedded sandstones, representing vertical accretion and channel deposits of an alluvial plain. Facies E consists of gray sandstones containing marine fossils and greeni h-gray shales (Pocono Formation), interpreted as marine and marginal marine deposits developed during net transgression of the sub-aerial Catskill delta. Contrary to some previous studies, this study indicates these strata are best interpreted within the context of deltaic sedimentation. More specifically, stratigraphic and sedimentologic evidence suggests deposition in a wave- and storm-dominated deltaic complex. End_of_Article - Last_Page 1923------------

Exploration Geology and Depositional Modeling of a Continental Tight Sand Reservoir, Abo Formation, Chaves County, New Mexico: ABSTRACT

The Wolfcampian-Leonardian age Abo Formation has been the major objective of exploration efforts in southeastern New Mexico since 1980. The Abo Formation in Chavez County consists of red and green mudstones and shales interbedded with very fine-grained reddish-orange sandstones. The sandstones are subarkosic arenites deposited in a fluvial/delta plain environment on the northwest shelf of the Permian basin. Producing sandstones are characterized by very low in-situ permeabilities (0.006 to 0.01 md) and porosities (determined from CNL density logs) ranging from 5 to 12%. Petrographic analysis of the producing zones yields only traces of visible porosity (^approx 1%), indicating the relative importance of fractures to total porosity. The importance of this secondary porosit is substantiated by the concentration of production within an area of major southwest-northeast-trending buckles that result in folded and fractured zones parallel to their strike. Abo sediments were derived from the predominantly granitic Pedernal uplift to the north and west of the producing area. The prograding fluvial/delta plain is evidenced by calcareous mudstones at the base of the Abo with calcite fracture fillings grading upward into anhydritic mudstones containing anhydrite fracture fillings and bird's-eye lenses. In general, three main producing zones are found in the upper Abo Formation. These sandstones occur either as a single thick (6 to 10 m, 20 to 33 ft) sand or several thin (2 to 4 m, 6.5 to 13 ft) sands separated by thin mudstones. Changes in thickness and character o these three major sands represent lateral shifts in subaerially deposited, braided paleochannels. The relatively homogenous mudstone intervals between producing sands and at the base of the section represent delta switching and tidal backreef (submarine) deposition. Gas wells in the Abo initially produce from 200 to 4,000 MCFGPD of dry (1,000 Btu) gas after considerable acidizing and fracturing. The modeling of the depositional environment of the Abo is critical to the selection of prime drilling locations. Paleochannel development and trends, as well as significant interbedded mudstone intervals, are essential for good Abo potential. Several stratigraphic and diagenetic trapping processes may result in hydrocarbon accumulations within these anastomosed fluvial sandstones. Channel fills are most commonly contained laterally and vertically by mudstones. Differing amounts of calcite and anhydrite cement and argillaceous matrix within the sandstones may create diagenetic traps within the channels. The best Abo wells are located in areas where paleoc annels are well developed and intersect southwest-northeast-trending structural zones. The completion of these wells can be complicated by inadequate cementing prior to fracturing resulting in the fracturing of containing mudstones and shales instead of gas-bearing perforated sandstone intervals. The relatively shallow, 950 to 1,300 m (3,100 to 4,300 ft), depths to encounter pay, combined with the higher allowable tight gas (107) price in the Abo, have stimulated significant activity in this new play that is certain to expand as the reservoir and trapping mechanism is better understood. End_of_Article - Last_Page 476------------

In-Situ Stresses: The Predominant Influence on Hydraulic Fracture Containment

Summary In-situ experiments, which are accessible by mineback, have been conducted to determine the parameters that control hydraulic fracture containment. These experiments demonstrate that a stress contrast between the pay zone and a bounding layer is the most important factor controlling fracture height. Material property interfaces are shown to have little effect. Introduction Hydraulic fracturing has been used extensively for more than 30 years to stimulate the production of natural gas from many different reservoir rocks. Most treatments were small since their primary, purpose was to link the wellbore to the undamaged reservoir rock, and fracture lengths greater than a few hundred feet seldom were required. With increasing depletion of conventional natural gas reserves, attention has been focused on producing gas from unconventional gas resources such as tight gas sands and Devonian shales. Presently, stimulation of these formations is being attempted by massive hydraulic fracturing, a scale-up of at least an order of magnitude over conventional fracturing treatments. It is proposed that fractures longer than 4,000 ft (1200 m) be propagated in the low-permeability, gas-bearing formations to provide a high-conductivity path for the gas to reach the wellbore. Unlike small conventional treatments in which the fractures are propagated only a short distance, it is imperative that the large and massive hydraulic fractures be contained largely within the pay zone. Obviously, if only a small portion of the fracture surface is in contact with the reservoir rock, the result may well be an uneconomic well in a reservoir that has sufficient resources if stimulated correctly. Detrimental results will occur should the fracture break into a water-bearing zone. When referring to massive hydraulic fracturing in the tight gas sands, containment may referto confinement of the fracture to specified intervals comprising both gas-bearing sandstones lenses and surrounding shale zones orto the usual concept of confinement within a single reservoir zone. In either case, the study of the containment of hydraulic fractures is directed toward determining the parameters and the conditions that will limit the height of a fracture and control its direction of propagation so that the necessary fracture lengths will be obtained. Implicit in these studies is the presumption that sufficient understanding of these conditions will allow operators to alter treatment parameters to help control containment, at least in those formations where there is already some propensity for containing the fractures. If this is not possible, it still may be possible to define a priori those zones that most likely will provide economic production as a result of favorable fracture growth (or containment) conditions. Background The parameters that are considered to have some effect on the containment of hydraulic fractures have been detailed previously in the literature. A difference in elastic modulus between the reservoir rock and the barrier rock usually is singled out as the primary mechanism controlling containment. In their work on composite materials, Cook and Erdogan calculated the stress intensity factor for the two-dimensional crack approaching an interface between two materials with different clastic moduli. Simonson et al. and Rogers et al. applied these results to hydraulic fracturing and observed that since the stress intensity factor K at the tip approaches zero as a fracture in a lower-modulus material propagates toward a higher-modulus material, the fracture will tend to be arrested. JPT P. 653^

Subsurface Stratigraphy of Midway-Wilcox, Zapata County, Texas: ABSTRACT

A subsurface study of the Midway-Wilcox (Paleocene-Eocene) in Zapata County, south Texas, led to the recognition of several stratigraphic units of possible formation rank within the Wilcox section. These units, which together with the Midway may reach a thickness of 15,000 ft (4,570 m) in extreme eastern Zapata County, were established mainly on the basis of depositional patterns as reflected on electric well logs. Four Wilcox units have been identified and named, in ascending order, the Lopeno, Volpe, Vela, and Hinnant. Although gas-bearing sandstones are present in all four units, the more important ones are in the Hinnant and Volpe. Deposition of the Midway-Wilcox appears to have been closely controlled by synchronous structural activity initiated in connection with th formation of the Tertiary Rio Grande embayment. This structural activity caused extensive faulting and great variations in sedimentary thicknesses, and is also responsible for the formation of local and regional unconformities in the study area. End_of_Article - Last_Page 1596------------

Application of Palynology to Age Determination, Correlation, and Paleoecology of Gas-Bearing, Nonmarine Rocks in Central Rocky Mountains: ABSTRACT

Potentially economic, low-permeability (tight), gas-bearing sandstone reservoirs in the Uinta, Piceance Creek, and greater Green River basins are found in predominantly nonmarine rocks of Late Cretaceous, Paleocene, and Eocene ages. Accurate subsurface correlations are essential to the estimation of reserves and to the understanding of the nature of reservoirs; but, in the absence of paleontologic data, the nonmarine rocks historically have proven to be difficult to correlate with geophysical logs. Pollen, spores, and other plant micro-fossils recovered from surface exposures and from boreholes have provided data on the age of the rocks and have facilitated accurate biostratigraphic correlation of surface and subsurface sections. The rocks generally represent sediments deposited in lacustrine, alluvial-fan, braided- and meandering-stream, delta-plain, lagoonal, and littoral-marine environments. The nature of source, reservoir, and trapping units in these rocks is commonly, in part, a function of the depositional environment of the units. Palynologic data in combination with sedimentological, petrographic, mineralogic, geochemical, and other paleontologic data, all derived from the same samples, have been used to refine interpretations of lithofacies and to determine the paleoclimate, paleoecology, and paleoenvironment End_Page 502------------------------------ at several key reference sections in the study area. End_of_Article - Last_Page 503------------

Containment of Massive Hydraulic Fractures

Abstract Hydraulic fracture containment is discussed in relationship to linear elastic fracture mechanics. Three cases are analyzed,the effect of different material properties for the pay zone and the barrier formation,the characteristics of fracture propagation into regions of varying in-situ stress, propagation into regions of varying in-situ stress, andthe effect of hydrostatic pressure gradients on fracture propagation into overlying or underlying barrier formations. Analysis shows the importance of the elastic properties, the in-situ stresses, and the pressure gradients on fracture containment. Introduction Application of massive hydraulic fracture (MHF) techniques to the Rocky Mountain gas fields has been uneven, with some successes and some failures. The primary thrust of rock mechanics research in this area is to understand those factors that contribute to the success of MHF techniques and those conditions that lead to failures. There are many possible reasons why MHF techniques fail, including migration of the fracture into overlying or underlying barrier formations, degradation of permeability caused by application of hydraulic permeability caused by application of hydraulic fracturing fluid, loss of fracturing fluid into preexisting cracks or fissures, or extreme errors in preexisting cracks or fissures, or extreme errors in estimating the quantity of in-place gas. Also, a poor estimate of the in-situ permeability can result in failures that may "appear" to be caused by the hydraulic fracture process. Previous research showed that in-situ permeabilities can be one order of magnitude or more lower than permeabilities measured at near atmospheric conditions. Moreover, studies have investigated the degradation in both fracture permeability and formation permeability caused by the application of hydraulic fracture fluids. Further discussion of this subject is beyond the scope of this paper. This study will deal mainly with the containment of hydraulic fractures to the pay zone. In general, the lithology of the Rocky Mountain region is composed of oil- and gas-bearing sandstone layers interspaced with shales (Fig. 1). However, some sandstone layers may be water aquifers and penetration of the hydraulic fracture into these penetration of the hydraulic fracture into these aquifer layers is undesirable. Also, the shale layers can separate producible oil- and gas-bearing zones from nonproducible ones. Shale layers between the pay zone and other zones can be vital in increasing successful stimulation. If the shale layers act as barrier layers, the hydraulic fracture can be contained within the pay zone. The in-situ stresses and the stiffness, as characterized by the shear modulus of the zones, play significant roles in the containment of a play significant roles in the containment of a hydraulic fracture. The in-situ stresses result from forces in the earth's crust and constitute the compressive far-field stresses that act to close the hydraulic fracture. Fig. 2 shows a schematic representation of in-situ stresses acting on a vertical hydraulic fracture. Horizontal components of in-situ stresses may vary from layer to layer (Fig. 2). For example, direct measurements of in-situ stresses in shales has shown the minimum horizontal principal stress is nearly equal to the overburden principal stress is nearly equal to the overburden stress. SPEJ P. 27

Permeability Control in Cretaceous Gas-Bearing Sandstones: ABSTRACT

Permeability Control in Cretaceous Gas-Bearing Sandstones: ABSTRACT

Evaluation of Low-Permeability Gas-Bearing Formations in Rio Blanco County, Colorado

This evaluation was conducted in connection with an experiment in stimulating formations with multiple nuclear explosions. The values for reservoir properties were obtained by core and computerized log analyses for the nuclear stimulated well and by analysis of pressure buildup tests on another well nearby. Gas production was predicted on the basis of the values obtained. Introduction The existence of major volumes of gas in thick, low-permeability sandstone reservoirs in Colorado, Wyoming, and Utah has tantalized producers for decades. Conventional efforts to obtain commercial production from these resources have been generally production from these resources have been generally unsuccessful, not only because the permeabilities are extremely low (on the order of several microdarcies to several tens of microdarcies) but also because the gas-bearing sandstone beds are generally scattered throughout sand/shale intervals greater than 1,000 ft thick. Typical tight gas reservoirs are found in the Tertiary Fort Union and the Cretaceous Mesaverde formations of the Piceance Basin in northwestern Colorado. These formations have been drilled and conventionally fractured in Rio Blanco County without successfully obtaining commercial production. New gas production operations in this area have been sparked, however, by the potential for successfully stimulating gas production with multiple nuclear explosions. The 94,000-acre Rio Blanco Unit area (Fig. 1) has been established and a nuclear stimulation treatment has been carried out in Well RB-E-01 with three 30-kt explosives. Emplaced at depths of 5,839, 6,230, and 6,690 ft, these explosives should have effectively fractured a 1,300-ft gross section of the Fort Union and Mesaverde formations from 5,530 to 6,830 ft, subsurface. The evaluation of a stimulation treatment's effectiveness is, of course, dependent upon a knowledge of reservoir characteristics, particularly permeability and net pay thickness. The development of such knowledge for conventionally commercial reservoirs is facilitated by a rather extensive base of proved empirical and theoretical relationships. The extent to which this base is applicable to low-porosity and low-permeability reservoirs, such as those in the Fort Union and Mesaverde formations, is uncertain. Because of this uncertainty, greater than normal effort was made to evaluate cores, logs, and production tests. This report presents the reservoir property values obtained and the predictions of gas production based upon these values. production based upon these values. Area Geology The Piceance basin is a northwest trending structural downwarp (Fig. 1). It contains a sedimentary section dating from lower Paleozoic to Tertiary with a maximum thickness of about 30,000 ft. The east-west cross-section (Fig. 2) shows the asymmetric nature of the basin, with gentle dips on the west and steep dips on the east. The surface rock throughout the unit area is the Tertiary Green River formation, which is composed of oil shales, marlstones, and sandstones. The Wasatch formation, consisting of brightly colored clays and shale with minor sandstone, underlies the Green River formation and overlies the Fort Union formation.

Detonability of Nitroglycerin contained in Porous Rock

IN the course of experiments to determine the feasibility of using liquid explosives to enhance the productivity of oil- and gas-bearing sandstones after hydraulic fracturing, it has been found that dry porous sandstone could imbibe sufficient nitroglycerin-ethylene glycol dinitrate (50–50 NG-EGDN1) to yield a detonable charge.

THE MINERALOGY AND PETROLOGY OF THE PERMIAN SANDSTONES AT GIDGEALPA, SOUTH AUSTRALIA

Detailed mineralogical and petrographic examinations were carried out on the gas-bearing Permian sandstones at Gidgealpa, South Australia, on behalf of Delhi Australian Petroleum Ltd. The investigation was carried out to obtain data on the possible formation damage during drilling. The rocks consist dominantly of clay-cemented protoquartzites and contain sedimentary and rare (?)granitic rock fragments in the upper members, and acid volcanics fragments in the lower members. The matrix consists of kaolin, illite and quartz. Some of the kaolin is authigenic and consists of vermicular kaolinite. Silicification of the rocks is a common feature, and its effect on the recovery of petroliferous constituents is considered significant. Treatment of the clays with artesian water, saline solution and drilling mud filtrate revealed no modification to the crystal structures, but flocculation of the clays with salt solution was evident. The significance of the laboratory characteristics of these samples to their behaviour in situ is discussed.