Porosity Of Reservoir Sandstones Research Articles

Facies-Related Diagenesis and Multiphase Siderite Cementation and Dissolution in the Reservoir Sandstones of the Khatatba Formation, Egypt's Western Desert

In the fluvio-deltaic, quartz-arenitic sandstones of the Jurassic Khatatba Formation in the Salam field (Egypt9s Western Desert), diagenesis and sedimentary facies control reservoir quality. Fluvial channel sandstones have the highest porosities (10-15%) and permeabilities (100-600 md), in part because of siderite cementation, which (1) inhibited compaction and quartz cement and (2) was later dissolved, creating intergranular secondary porosity (1/4 of total porosity). Fluvial crevasse-splay and marine sandstones have the lowest reservoir quality because of an abundance of depositional kaolin matrix and pervasive, shallow-burial Fe-dolomite cement, respectively. Siderite precipitation was multiphase and separated by distinct dissolution events. The earliest siderite precipitated near surface, within suboxic tropical coastal swamps containing predominantly meteoric waters. Some influence of marine waters is indicated by local enrichments in Mg and Ca. The next major siderite generation shows a trend to decreasing Mn and Ca contents, and is of shallow-burial origin. The last major siderite phase is Mg rich and interpreted as deeper-burial in origin. Some dissolution occurred during shallow burial related to climatically controlled meteoric water fluxing under unconformities. The most important dissolution, however, occurred during deep burial, resulting in (1) a major corrosion surface predating the last Mg-rich zone, (2) selective dissolution of some earlier zones, and (3) secondary porosity. This burial dissolution is interpreted to have been caused by cooling of compactional waters expelled from the basin along major faults. Other diagenetic phases observed include early-diagenetic pyrite, kaolin, quartz, bitumen, and late-diagenetic barite and illite. Kaolinite precipitated at shallow depths ( 130°C) during and/or after rapid Late Cretaceous burial. Quartz developed in two phases, separated by oil migration. This paper illustrates that, in fluvio-deltaic quartz arenites deposited under the influence of humid tropical climate, reservoir quality can be largely controlled by the contrasting pathways of carbonate diagenesis followed by the different sedimentary facies. This paper also documents a case in which siderite dissolution generated significant secondary porosity in reservoir sandstones, and where both siderite cementation and dissolution took place in multiple phases during different diagenetic stages, including early, shallow-burial, and deep-burial diagenesis. The present study also shows that, in multiphase siderite cements, the earlier growth zones can be selectively dissolved and replaced by later siderite zones (i.e., recrystallized) during burial diagenesis. These findings contrast with the general thought that siderite cements are not susceptible to generation of significant secondary porosity by dissolution and that earlier-formed siderites are essentially stable during diagenesis.

Abstract: Diagenetic evolution of packing flaws and well-packed porosity in reservoir sandstones

Abstract: Diagenetic evolution of packing flaws and well-packed porosity in reservoir sandstones

Dissolution, Compaction, and Destruction of Secondary Porosity in Reservoir Sandstones in the western San Joaquin Basin, California: ABSTRACT

Dissolution, Compaction, and Destruction of Secondary Porosity in Reservoir Sandstones in the western San Joaquin Basin, California: ABSTRACT

Dissolution, Compaction, and Destruction of Secondary Porosity in Reservoir Sandstones in the San Joaquin Basin, California

Dissolution, Compaction, and Destruction of Secondary Porosity in Reservoir Sandstones in the San Joaquin Basin, California

Depositional environments, diagenesis, and porosity of reservoir sandstones in the Malong Field, offshore West Malaysia

Depositional environments, diagenesis, and porosity of reservoir sandstones in the Malong Field, offshore West Malaysia

Secondary Porosity in Sandstones: ABSTRACT

Secondary porosity in sandstones is caused by dissolution and fracturing, and is common in the sedimentary record. Secondary porosity commonly develops in the deep subsurface and thus provides an opportunity to extend exploration to depths traditionally considered unsuitable for exploration. Two contrasting routes of diagenesis exist in nature: porosity reduction and porosity enhancement. Porosity reduction is commonly caused by compaction and cementation, whereas porosity enhancement is primarily caused by dissolution of carbonate minerals. The dissolution of carbonate minerals in the deep subsurface can be attributed to release of carbon dioxide during thermal maturation of kerogen. Clay-carbonate reaction and flushing of undersaturated meteoric water from erosional unconformity are equally important mechanisms in generating secondary porosity at various depths. Two basic types of primary pores (intergranular and intragranular) and four basic types of secondary pores (grain fractures, rock fractures, intergranular, and intragranular) can be differentiated on the basis of (1) position of pores, (2) timing of origin, and (3) processes of origin. The proposed classification system is useful in inferring reservoir quality. Various types of secondary porosity are recognized using a comprehensive set of 20 criteria. The various criteria are based on manner of breakage, pore geometry, grain geometry, products of dissolution, and sediment packing. Examples of secondary porosity gathered in part from investigation of 2,000 thin sections will serve as a guide for recognizing secondary porosity in outcrop, in hand specimen, under the scanning electron microscope, and most importantly, under the petrographic microscope. New evidence suggests that silicate minerals, including quartz, dissolve more commonly than have been reported. The abundant occurrence of secondary porosity in reservoir sandstones emphasizes the importance of secondary porosity in evaluating deep reservoirs. Since the first recognition of secondary porosity by Nutting in 1934, Chepikov in 1959 and 1961 not only developed the first set of criteria for recognition of secondary porosity but also introduced the concept in which development of secondary porosity is related to arrival of oil. End_of_Article - Last_Page 547------------

Development of Secondary Porosity in Reservoir Sandstones by Dissolution of Silicate Mineral Constituents: ABSTRACT

Although considerable pore space in reservoir sandstones may result from chemical removal of carbonate rock as cement or mineral replacements, significant porosity may develop by direct dissolution of silicate mineral constituents. Feldspar and volcanic rock fragments, in particular, appear highly susceptible to dissolution in many reservoir sands. Dissolution of detrital feldspar represents a most important source of secondary porosity. Sanidine, orthoclase, and plagioclase occurring as discrete grains or constituents in rock fragments may undergo intense dissolution. Microcline and authigenic feldspar growths, however, are generally much less affected. Early unaltered carbonate cement (pre-feldspar dissolution) in some sandstones indicates that dissolution may occur under alkaline as well as acidic conditions. Although resultant pores may be moldic, most voids contain remnants of undissolved material. In feldspathic sandstones, extensive dissolution can cause weakening and subsequent readjustment of the detrital framework. Dissolution of volcanic rock fragments (VRFs) may also account for considerable pore space in reservoir sandstones. Finely crystalline volcanic fragments and volcanic glass appear to be especially prone to dissolution. Voids resulting from dissolution of VFRs are commonly moldic appearing and may be characterized by a skeletal framework of straight to curvilinear shards and veinlets(?) resembling chert. In some specimens, chloritized VRFs appear to be more susceptible to dissolution than unaltered fresh-appearing fragments. As chlorite is relatively soluble under lower pH conditions, this possibly indicates that formation waters attending dissolution were somewhat acidic. Although dissolution of silicate mineral constituents results in increased porosity, it does not necessarily result in enhanced permeability. In some places, the development of authigenic clay as a dissolution product may serve to constrict pore throats, resulting in a decrease in pore communication. End_of_Article - Last_Page 737------------

The Effect of Overburden Pressure on Relative Permeability

Laboratory relative permeability data on reservoir rock are obtained onsamples which are not subjected to overburden pressure during the permeabilitymeasurements. These data are then used for calculating the performancecharacteristics of reservoirs in which the rock is under the pressure of theoverburden. Recent observations have shown that the permeability and porosityof reservoir sandstones are decreased by application of overburden pressure.These observations led us to a study of the effect of overburden pressure onthe relative permeability characteristics of sandstones. A previous note from this laboratory showed that overburden pressure, simulated by applying hydraulic pressure to the outside of a plastic mountedcore, caused a reduction in permeability of the core by as much as 50 per centat 10,000 psig. In a multi phase fluid flow system, the relative permeabilityat a given saturation will change if the permeability or the effectivepermeability changes but not if both permeability and effective permeabilitychange by the same ratio. The tests described in this note were made todetermine the effect of overburden pressure on permeability and effective gaspermeability in the gas-oil system. The gas-oil system was chosen because theavailable equipment was best suited for studying this system. The resultantdata can be applied to other systems of interest because the gas permeabilityin the gas-oil system is the permeability of the nonwetting phase and, as such, is equivalent to the gas permeability in the gas-oil-water system and to theoil permeability in the oil-water system. Cylindrical test plugs, one in. in diameter and one in. long, were cut fromsandstone core samples from three different reservoirs. After extraction intoluene, the plugs were mounted in Lucite by conventional core mountingmethods. The core properties are given in the legend in Fig. 1. The mountedcores were machined to fit the apparatus shown in Fig 4. Air permeabilities asa function of overburden pressure were measured by connecting lines (1) and (2)to a conventional air permeameter. T.N. 194