Jin Lai

Deep burial diagenesis and reservoir quality evolution of high-temperature, high-pressure sandstones: Examples from Lower Cretaceous Bashijiqike Formation in Keshen area, Kuqa depression, Tarim basin of China

The deep high-temperature, high-pressure Lower Cretaceous Bashijiqike sandstone (buried to depths as great as 6.5-7.1km) is an important natural gas reservoir in Keshen gas field, Kuqa depression of the Tarim Basin. Reservoir quality is a critical risk factor in the development of these ultradeep reservoirs. Integrated approaches incorporating routine core analyses, mineralogical, petrographic, and geochemical analyses have been used to investigate the diagenetic history of these rocks and their impact on reservoir quality with the aim to unravel the mechanisms for maintaining anomalously high porosities in sandstones that are buried to such a great depth. These sandstones are dominantly fine to medium-grained, moderately to good sorted lithic arkoses and feldspathic litharenite. Most primary pores have been lost by mechanical compaction or carbonate cementation, and the reduction of porosity by mechanical compaction was more significant than by cementation. Dissolution of framework grains contributed to the enhancement of reservoir quality. Eogenetic diagenetic alterations mainly include mechanical compaction, precipitation of calcite cements and grain-coating clays; mesogenetic diagenesis is characterized by dissolution of framework grain by organic acids and subsequent precipitation of clay minerals and quartz; infiltration of meteoric water related to teleodiagenesis would result in dissolution of the framework grains. The meteoric leaching events during teleodiagenesis are of great importance for the Bashijiqike sandstones. Grain-coating clay minerals (mixed-layer illite/smectite clays) help to preserve porosity at depth by retarding quartz cementation and pressure solution. The unique burial regime as early-stage shallow burial with late-stage rapid deep burial contributes to porosity preservation in eodiagenesis. Fluid overpressure caused by intense structural compression in the middle Himalayan movement retarded compaction and helped preserve porosity in the late rapid deep burial stage. Anomalously high porosities are mainly found in medium-grained, good sorted sandstones with grain-coating clays, but with low clay and carbonate cement content, of which the porosity is preserved primarily and enhanced secondarily. The lowest porosities are associated with sandstones that are tightly compacted or cemented with carbonates or rich in detrital matrix. Porosity-depth trends may vary significantly with lithofacies due to its differences in textural and compositional attributes. Five lithofacies are defined in terms of detrital composition and texture, type and degree of diagenesis. The reservoir quality prediction models of various lithofacies are constructed, and the results of this study provide insights into mechanisms for maintaining anomalously high porosity and permeability in high-temperature, high-pressure sandstone reservoirs, and may help explain hydrocarbon distribution.

Fractal analysis of tight shaly sandstones using nuclear magnetic resonance measurements

Assessing quantitatively the microscopic pore structures of porous rocks, including irregularities of pore shapes and pore size distributions, is becoming one of the most challenging efforts. Nuclear magnetic resonance (NMR) measurements were used to provide insights into the pore geometry (pore size and shape) and pore connectivity of the Chang 7 tight shaly sandstones (in situ permeability <0.1 md) in Ordos basin. The incremental transverse relaxation time (T2) distributions for the 100% brine-saturated samples display unimodal and bimodal behaviors, presenting a geometrical arrangement composed of small to large pore size domains. The NMR parameters such as bulk volume irreducible (BVI) (capillary and clay-bound water), free fluid index (FFI) (movable water), the value of T2 separating the BVI from FFI, the amplitude weighted mean on a logarithmic scale (T2gm), and the value of T2 that shows the highest frequency on the T2 spectrum (T2peak) for each sample were determined. Then the fractal theory was adopted to quantitatively express the complexity and heterogeneity of the sandstones. The results show that only minor primary intergranular porosity remains, and variable amounts of micropores and secondary intragranular porosity with poor connectivity occur in the Chang 7 tight shaly sandstones. Assuming spherical pores, a new model to calculate the fractal dimension of pore structure from the NMR T2 distributions is proposed. The fractal dimensions of all the samples are calculated, and the accuracy of the proposed model is verified by the regression coefficients. The microscopic pore structures are heterogeneous in these tight sandstones according to the high value of fractal dimensions. Micropores are the primary causes of heterogeneity in tight sandstones, and samples with unimodal T2 distribution behaviors and high content of short components have the highest fractal dimension and heterogeneity. The calculated fractal dimension is strongly correlated with T2peak and T2gm; therefore, the fractal model proposed in this study can be used to calculate the fractal dimensions and evaluate the heterogeneities of the porous rocks satisfactorily. The fractal model proposed in this study helps to quantitatively assess the pore structures of tight sandstones using NMR measurements.

Three-dimensional quantitative fracture analysis of tight gas sandstones using industrial computed tomography

Tight gas sandstone samples are imaged at high resolution industrial X-ray computed tomography (ICT) systems to provide a three-dimensional quantitative characterization of the fracture geometries. Fracture networks are quantitatively analyzed using a combination of 2-D slice analysis and 3-D visualization and counting. The core samples are firstly scanned to produce grayscale slices, and the corresponding fracture area, length, aperture and fracture porosity as well as fracture density were measured. Then the 2-D slices were stacked to create a complete 3-D image using volume-rendering software. The open fractures (vug) are colored cyan whereas the calcite-filled fractures (high density objects) are colored magenta. The surface area and volume of both open fractures and high density fractures are calculated by 3-D counting. Then the fracture porosity and fracture aperture are estimated by 3-D counting. The fracture porosity and aperture from ICT analysis performed at atmospheric pressure are higher than those calculated from image logs at reservoir conditions. At last, the fracture connectivity is determined through comparison of fracture parameters with permeability. Distribution of fracture density and fracture aperture determines the permeability and producibility of tight gas sandstones. ICT has the advantage of performing three dimensional fracture imaging in a non-destructive way.A correction to this article has been published and is linked from the HTML and PDF versions of this paper. The error has been fixed in the paper.

A logging identification method of tight oil reservoir lithology and lithofacies: A case from Chang7 Member of Triassic Yanchang Formation in Heshui area, Ordos Basin, NW China

Abstract Based on the observation results of cores, structural analysis, sedimentary microfacies analysis, lithologic analysis and other analytical tests and logging data, the characteristics of lithology and lithofacies of the Member Chang7 tight oil reservoir of the Triassic Yanchang Formation in Heshui area are described and summarized and the criteria for identification of lithology and lithofacies by logging are established. The lithofacies in the Chang7 tight oil reservoir were classified into five types: fine sandstone deposited by sandy debris flow, turbidite fine siltstone, fine sandstone deposited by slump, semi-deep to deep lacustrine mudstone, and oil shale. The lithology and lithofacies in the Chang7 tight oil reservoir were characterized, both qualitatively and quantitatively, with electric logging and imaging logging and several means and methods, the response characteristics of different lithology and lithofacies were summarized through analyzing the image log and conventional log data, and the parameters characterizing sandstones structures were used to quantitatively characterize the lithology and lithofacies, the criteria for identification of different lithology and lithofacies by logging were established. The vertical and horizontal identification and classification of lithology and lithofacies in a single well was then accomplished by processing the log data from each well, the results of lithology and lithofacies identification tally well with the results of formation testing. In-depth lithology and lithofacies analysis proves to be an important method of tight oil reservoir evaluation and “sweet spot” prediction.