Reservoir Quality Evaluation Research Articles

Nanopetrophysical characterization of the Mancos Shale Formation in the San Juan Basin of northwestern New Mexico, USA

The Mancos Shale of the San Juan Basin has been an important resource for the exploration and development of oil and gas. However, as with most unconventional plays, the shales have low porosity and extremely low permeability with predominantly nanometer-sized pores. Thus, it is critical to understand the nanopetrophysical properties of the reservoir so a proper assessment of the reservoir quality can be made. Working with three as-received core samples from three different wells of the Tacito Marine Bar and Offshore Mancos play types, we have developed an initial understanding of the nanopetrophysical properties of the pore structure as well as fluid-rock interactions in these tight reservoirs. We have performed a suite of integrated tests, such as mercury intrusion porosimetry (MIP), low-pressure nitrogen physisorption, core plug porosity and permeability, scanning electron microscopy imaging, water immersion porosimetry after vacuum pulling, contact angle, and fluid imbibition. In addition, we obtained supplementary data for total organic carbon, X-ray diffraction, and pyrolysis to further evaluate reservoir quality. The Mancos Shale samples exhibit petrophysical characteristics that are controlled by a predominant presence of nanometer-sized pore space, with 56%–96% pore volumes present as 3.4–50 nm in pore-throat sizes, as shown by the MIP approach. Contact angle and fluid imbibition tests demonstrate that samples are oil wet to mixed wet, with a tendency of pore networks to imbibe oil over water. The findings from integrated pore structure and wettability studies provide a database and some insights, from the perspectives of nanopetrophysical characterization, into the reservoir quality of the Mancos Shale.

Late Miocene provenance evolution at the head of Central Canyon in the Qiongdongnan Basin, Northern South China Sea

Abstract The head of the Central Canyon system in the Qiongdongnan Basin has been suggested as the key region for understanding the deposition and transportation processes in the northern South China Sea but the sedimentary provenance of this region remains uncertain. In this study, U–Pb geochronology of detrital zircon was used to constrain the source terranes, understand the sedimentary provenance, and reconstruct the provenance evolution in the late Miocene. Measured age populations from the upper Miocene sediments indicate that the sediments in the Central Canyon were mainly derived from the sources of the Red River and central Vietnam, whereas the nearby Hainan Island was not the major source terrane. The southwestern Yangtze Block was likely the primary source for the head of the Central Canyon through the Red River system and played an important role in contributing detritus to the northwestern South China Sea during the late Miocene. The results of this study also showed slight provenance variations in the vertical stratigraphic successions of the upper Miocene, suggesting a relatively stable and continuous detritus supply from the Red River at 10.5–8.2 Ma. In addition, the provenance study is capable to provide important insights in reservoir distribution and quality evaluation in future exploration and production.

Diagenetic alteration and its control on reservoir quality of tight sandstones in lacustrine deep-water gravity-flow deposits: A case study of the Yanchang Formation, southern Ordos Basin, China

Abstract The tight oil sandstone reservoir of the Upper Triassic Yanchang Formation is one of the main targets for hydrocarbon exploration in the Ordos Basin, China. Sandstones of the Upper Triassic Yanchang Formation within lacustrine deep-water gravity-flow deposits are characterized by ultralow porosity, ultralow permeability, and complex diagenetic alterations and sedimentary lithofacies. However, the diagenetic alterations and their controls on the reservoir quality of the Chang 6 tight sandstones remain poorly understood. This study integrated a variety of techniques, such as casting thin section analysis, scanning electron microscopy (SEM), back-scattered electron imagery (BSE), X-ray diffraction (XRD), cathodoluminescence (CL) microscopy, and fluid inclusion, to investigate the lithofacies, diagenetic history, and diagenetic intensity, and also evaluate their controls on reservoir quality. The research results indicated that the Chang 6 sandstones exhibit variable intensity of diagenetic alterations among the various lithofacies, which leads to variable reservoir quality. Mechanical compaction was the most important factor reducing primary porosity. Sandstones of the Ss lithofacies (siltstone to very fine-grained sandstones with graded bedding or ripple laminations) showed the highest loss of primary porosity. Carbonate cements were commonly present in sandstones of the Sc (fine-grained and cross-bedded sandstones) and Sm (fine-grained and massive sandstones) lithofacies near the sandstone–mudstone bounding surface. Sandstones with more authigenic illite rims were able to resist compaction to some extent and were favorable to the preservation of porosity; however, abundant pore-filling illite aggregates commonly bridged pore throats, causing a significant reduction in reservoir quality. Feldspar dissolution porosity leads to a slight enhancement in reservoir quality. Intergranular pores and feldspar dissolution pores are most abundant in the sandstones away from the sandstone–mudstone bounding surface of the Sc lithofacies, resulting in the best reservoir quality, which is followed by sandstones of the Sm lithofacies. Ultimately, four evolution patterns of diagenetic alterations that formed best, moderate, or poor reservoir quality were summarized by linking diagenetic alterations to lithofacies. The research results are conducive to the evaluation of reservoir quality and to understanding the genetic mechanisms of tight sandstones, so they should facilitate hydrocarbon exploration and production in similar lacustrine deep-water gravity-flow reservoirs.

Grid density overlapping hierarchical algorithm for clustering of carbonate reservoir rock types: A case from Mishrif Formation of West Qurna-1 oilfield, Iraq

The primary goal of this study is to solve a major challenge of reservoir rock typing in quantitatively understanding the relationship between geological and petrophysical properties of carbonate reservoir. This paper first presents an improved overlapping index based on the grid density to define the overlapping relationship between different clusters and a grid density overlapping hierarchical algorithm (GDOH) for clustering of carbonate reservoir rock types. GDOH clustering algorithm is a hybrid type which integrates the gird, density, overlapping index and the hierarchical clustering method using the number of grid divisions and the threshold value of the overlapping index as the key parameters. Taking the Mishrif Formation of West Qurna Oilfield-1 as a case, the GDOH clustering algorithm is employed for clustering of carbonate reservoir rock types. As a result, ten geological rock types are identified according to the lithological type and diagenetic type using the thin section data. We finally got four reservoir rock types using the GDOH clustering algorithm with the overlapping index of core porosity and the permeability data as the metric. These reservoir rock types are different in reservoir qualities and porosity-permeability relationships. Each reservoir rock type also shows a similar set of capillary pressure curves and a typical and unique set of pore throat size distribution. The clustering result gives us some clues to understand the control of depositional and diagenesis features on the variation of reservoir rock types in reservoir quality and porosity-permeability relationship. Compared with the model-based petrophysical rock-typing techniques such as Winland r35, FZI and FZI-Star (FZI*), GDOH algorithm shows some apparent advantages in the evaluation of reservoir quality and prediction of permeability in three dimensions based on geologic principles in addition to understanding the relationship between reservoir rock type and petrophysical static and dynamic rock type.

Earth stress and reservoir quality evaluation in high and steep structure: The Lower Cretaceous in the Kuqa Depression, Tarim Basin, China

Knowledge of the state of the in-situ stress field provides important insights into the petroleum engineering and geology. The in-situ stress orientation and magnitudes in the high and steep structure of Lower Cretaceous Bashijiqike Formation in Kuqa Depression were analyzed based on well log calculations, and the impacts of in-situ stress field on reservoir quality (macroscopic reservoir properties and microscopic pore structure as well as fracture aperture) were investigated. The maximum horizontal stress (SHmax) orientation was determined as nearly north-south according to the image log derived drilling induced fractures and borehole breakouts. The vertical stress (Sv), SHmax, and minimum horizontal stress (Shmin) magnitudes were calculated via well logs. The result reveals a dominant strike-slip stress regime (SHmax > Sv > Shmin) in the Bashijiqike Formation in the Kuqa Depression. The Sv at the depth ranging from 5000 to 7100 m is 150–180 MPa, and horizontal stresses (SHmax and Shmin) vary significantly from 130 to 210 MPa. The horizontal stress difference (Δσ) is in the range from 40 to 70 MPa, and fluid overpressures are commonly encountered. The effective stress (σe) has a positive relationship with the Δσ when the Δσ is less than 50 MPa. Intergranular pores can be preserved in layers with low Δσ values. The microscopic pore structure will be complex, and macroscopic reservoir quality will be poor with the increasing Δσ values. In addition, fractures are mainly corresponding with the layers where the Δσ value is low, and the fracture aperture and porosity decreased significantly with the effective stress σe. By determining the magnitude and orientation of in-situ stresses around the wellbore, insights can be provided into the wellbore instability, optimum drilling trajectories and reservoir quality evaluation.

Reservoir characterization of the Burgan Formation in northwestern Persian Gulf

Lower Cretaceous sequences of the Burgan Formation are notable siliciclastic reservoirs in the Middle East. Despite of this importance, a little is known about various geological characteristics of this reservoir in Iranian northwestern part of the Persian Gulf. In this study, an integrated sedimentological and reservoir geological evaluation has been carried out on the Burgan reservoir using a complete dataset of drilled cores, core plugs, thin sections and petrophysical logs along with laboratory data including XRD analysis of all components to define grain's mineralogy and porosity – permeability data for reservoir quality evaluation. Depositional facies and environments are interpreted and correlated in sequence stratigraphic framework of targeted reservoir across the studied fields and then compared with stratigraphic equivalents in the Middle East. Seven facies types are recognized that indicate deposition in a transitional environment from siliciclastic-dominated delta setting into shallow-marine carbonate platform. Diagenesis study indicates a simple history of post-depositional events that includes near surface (marine) and shallow to deep burial realms. Diagenetic processes are grouped into two categories based on their effects on reservoir properties. They include porosity enhancing (i.e. dissolution and fracturing) and porosity reducing (compaction and cementation) diagenetic processes. Reservoir evaluation of depositional facies has been carried out by defining petrographic rock-types (PRTs) and hydraulic flow units (HFUs) and their correlation in sequence stratigraphic framework. Results showed that semi-to unconsolidated sandstone facies accumulated in Burgan-B member provides the best reservoir units in the Burgan Formation. Organic-rich (rootled) and pelagic shale facies form several intra-reservoir barriers between the reservoir units, especially in Burgan-A member. These show close correlation with reservoir descriptions of this formation reported from the neighboring areas in the Persian Gulf (i.e. Kuwait).

Lower threshold of pore-throat diameter for the shale gas reservoir: Experimental and molecular simulation study

Low-field nuclear magnetic resonance (LF-NMR), high-speed centrifuge and low-pressure nitrogen adsorption (LPNA) experiments were conducted on shale samples from the Lower Silurian Longmaxi Formation to measure pore-throat parameters of the shale reservoir. We measured bound water saturation, helium porosity, bulk density, specific surface area, and pore-size distribution to evaluate reservoir quality. The thickness of the bound water film was calculated based on the equation established from these parameters, showing that its thickness ranges from 1.07 nm to 2.73 nm, with a mean of 1.72 nm. In addition, Grand Canonical Monte Carlo (GCMC) and molecular dynamics (MD) simulations were carried out to estimate the methane adsorption capacity and the number of the adsorbed layers in pores with different sizes at the given temperature and pressure (393.15 K, 65 MPa). The simulation results demonstrate that methane is unanimously adsorbed into pores <1.52 nm in diameter. Shale gas was present in both free and adsorbed states when the pore size was larger than 1.52 nm, and two layers were adsorbed on each pore wall. By combining the thicknesses of bound water film and adsorbed layers, the pore-throat lower limit for the shale gas reservoir was calculated to be about 4.96 nm.

Reservoir effectiveness evaluation based on comprehensive reservoir quality evaluation indexes of well logging: A case study on the Permian Qixia Fm in the western Sichuan Basin

In the western Sichuan Basin, the Permian Qixia Fm grained dolomite reservoirs are currently the new focus of natural gas exploration and development. The Qixia Fm is characterized by developed dissolved vugs and fractures, low matrix porosity and strong heterogeneity, so evaluation faults tend to occur if reservoir effectiveness is evaluated by means of the traditional porosity evaluation, and the consequently the predicted gas well productivity is more deviated from the actual measurement. In this paper, the characteristics of Qixia Fm reservoirs in this area were firstly analyzed. Then, the method and criterion of the effectiveness evaluation of Qixia Fm reservoirs in the western Sichuan Basin were established by means of numerical simulation and special logging data processing. And the following research results were obtained. First, surface porosity of matrix pores and secondary dissolved vugs calculated based on the special processing of conventional logging and electric imaging logging can be used to evaluate the reservoir properties of reservoirs. Second, deep and shallow dual lateral logging in combination with electric imaging logging and Stoneley wave energy data can be used to evaluate the filtration capacity of reservoirs. Third, the criterion of effective Qixia Fm reservoirs is established, including storage coefficient ≥0.6, deep lateral resistivity <5000 Ω·m, surface porosity >0.6%, Stoneley wave attenuation ≥10% and comprehensive reservoir evaluation index ≥0.25, and the evaluation criterion can well characterize reservoir quality and gas well productivity. The field application results of this evaluation method and evaluation criterion indicate that the coincidence rate of reservoir effectiveness has increased from 70% to over 90%. Thus, the technical difficulties related to the heterogeneous carbonate reservoir effectiveness evaluation are basically solved. Besides, they provide a basis for the determination of production test layer selection, completion engineering and development scheme so as to cut down the natural gas exploration and development cost.

Solid bitumen in the Montney Formation: Diagnostic petrographic characteristics and significance for hydrocarbon migration

The petrographic study of organic matter (OM) in fine-grained, shale and tight rocks can be complicated by ambiguities in distinguishing primary kerogen (deposited OM) from secondary solid bitumen (migrated and solidified petroleum). In this study, complementary thin-section, field emission scanning electron microscopy (FESEM) and organic petrology methods are used to examine core samples acquired from petroleum wells drilled into the Triassic Montney Formation in western Canada. The results show that OM in the medium- to coarse-grained siltstones of the Montney tight-gas and hydrocarbon liquids fairway is composed almost entirely of pore-filling solid bitumen/pyrobitumen. Here, we document a range of petrographic characteristics that are diagnostic of the solid bitumen and its origin as migrated liquid petroleum. These solid bitumen characteristics include (1) void-filling habit, (2) enclosure of earlier authigenic minerals, (3) margins with smoothly curved meniscate form, (4) internal flow structure, (5) entrained and aligned clay minerals, (6) isopachous rims along inorganic pore walls, (7) globular/granular aggregates and (8) fracture-filling habit. The petrographic results also show that the migration and flow of original oil through the thick Montney Formation (up to 340 m) was controlled at the micro-scale by sedimentary, ichnological, diagenetic and structural features. These features combined to form highly complex pathways and baffles for hydrocarbon migration. Petrographic recognition of OM as secondary migrated solid bitumen rather than primary deposited kerogen has vital significance for assessing unconventional shale and tight hydrocarbon plays including OM typing from Rock-Eval pyrolysis, interpreting depositional facies and environments, and evaluating reservoir quality.

An investigation into pore structure and petrophysical property in tight sandstones: A case of the Yanchang Formation in the southern Ordos Basin, China

Abstract The complex and heterogeneous pore structures, caused by complex diagenesis and sediment properties (such as rock compositions and grain size), play a critical role in macroscopic evaluating tight sandstone reservoir performance. In order to gain insight into the genetic mechanism of the pore structure and evaluate reservoir quality in tight sandstone reservoirs, this study investigated the impacts of diagenesis and sediment properties on pore structures and the relationship between microscopic pore structure parameters and macroscopic petrophysical performance, based on the analysis of pore structure features (including the morphology, pore throat types, sizes, combinations, distribution of combinations and pore connectivity), sedimentary and diagenetic features, and petrophysical properties. Samples from tight sandstones of the Yanchang Formation in southern Ordos Basin (in China) were evaluated by integrating scanning electron microscopy (SEM), thin sections, mercury injection porosimetry (MIP), nuclear magnetic resonance (NMR) and gas (N2, He) porosity and permeability measurements. Three pore-throat combinations were identified which represent the full-range distribution of pores: MP (micropores-dominanted pore-throat combination), IAP (intragranular pores-dominanted pore-throat combination) and IEP (intergranular pores-dominanted pore-throat combinations). The type and intensity of diagenesis and sediment properties (grain size and ductile component content) were found to result in differences in pore throat size and the distribution of pore throat combinations. Sandstones with coarser grain-size and lower concentrations of ductile components have experienced weak compaction, thick chlorite rim and minor kaolinite/carbonate cementation, were found to retain large IEP pore space and wide strip shaped throat, formed the intergranular pore - throat (Inter-T) and intergranular pore - intragranular pore - throat (Inter-Intra-T). The Intra-Intst-T (intragranular pore – group of interstitial cement pores - throat) sandstones were characterized by intense dissolution and kaolinite cementation which resulted in small IEP pore space and large MP/IAP pore space. The Intst-T (group of interstitial cement pores - throat) sandstones were characterized by intense compaction and kaolinite/carbonate cementation. Compaction and cements destroyed IEP pore space and formed MP pore space. Effectively connected pore space (volume of IEP) and throat radius were positively correlated to porosity and permeability. Four pore structures are distinguished according to the proportion of effectively connected pore space and the radii of strip shaped throats, the macroscopic behaviors and the geological genesis of the four pore structures are investigated.

A lithology identification method for continental shale oil reservoir based on BP neural network

The Dongying Depression and Jiyang Depression of the Bohai Bay Basin consist of continental sedimentary facies with a variable sedimentary environment and the shale layer system has a variety of lithologies and strong heterogeneity. It is difficult to accurately identify the lithologies with traditional lithology identification methods. The back propagation (BP) neural network was used to predict the lithology of continental shale oil reservoirs. Based on the rock slice identification, x-ray diffraction bulk rock mineral analysis, scanning electron microscope analysis, and the data of well logging and logging, the lithology was divided with carbonate, clay and felsic as end-member minerals. According to the core-electrical relationship, the frequency histogram was then used to calculate the logging response range of each lithology. The lithology-sensitive curves selected from 23 logging curves (GR, AC, CNL, DEN, etc) were chosen as the input variables. Finally, the BP neural network training model was established to predict the lithology. The lithology in the study area can be divided into four types: mudstone, lime mudstone, lime oil-mudstone, and lime argillaceous oil-shale. The logging responses of lithology were complicated and characterized by the low values of four indicators and medium values of two indicators. By comparing the number of hidden nodes and the number of training times, we found that the number of 15 hidden nodes and 1000 times of training yielded the best training results. The optimal neural network training model was established based on the above results. The lithology prediction results of BP neural network of well XX-1 showed that the accuracy rate was over 80%, indicating that the method was suitable for lithology identification of continental shale stratigraphy. The study provided the basis for the reservoir quality and oily evaluation of continental shale reservoirs and was of great significance to shale oil and gas exploration.

Initial porosity and compaction of consolidated sandstone in Hangjin Qi, North Ordos Basin

Compaction is an important part of diagenesis affecting porosity in conjunction with burial depth and time. However, the relation between initial porosity and sandstone compaction remains unclear. This paper aims to clarify the effect of initial porosity on the compaction of consolidated sandstone in the microdeformation stage via experiments, mathematical modeling, and statistical analyses. According to the physical experiments in the Ordos Basin, sandstone porosity decreases with increasing overburden load, and the porosity-decrease trends of two similar samples with different initial porosities converge gradually. Based on the Bingham visco-elasto-plastic stress–strain model, a theoretical model for the vertical uniaxial compaction of consolidated porous rocks was constructed. The equivalent viscosity coefficient (EVC) of consolidated sandstones was approximately estimated by a contrastive analysis and an iterative computation on the basis of the geologic statistical model proposed in this study. The results in Hangjin Qi show that the Young’s modulus and the EVC of low-porosity compaction trend (LPCT) are exponential and power-law functions of the corresponding porosity, respectively. The derivation of theoretical model indicates that the compressibility and the initial porosity of porous sandstone during microdeformation are positively correlated, in accordance with simulation experiments. The initial porosity affects the elastic modulus and the viscosity coefficient and consequently, the sandstone compaction during microdeformation stage. Such an effect can contribute to the improvements of both the compaction degree analyses of different burial processes in sandstone porosity evolution and reservoir quality evaluation.

Pore throat characteristics of tight sandstone of Yanchang Formation in eastern Gansu, Ordos Basin

An important factor to evaluate reservoir quality is the pore-throat size. However, the strong heterogeneity makes it difficult to characterize the pore-throat distribution in tight reservoirs. The field emission scanning electron microscope (FESEM), high pressure mercury injection and rate-controlled mercury injection are used to investigate the pore-throat size distribution in tight sandstone reservoirs of Member 7 of the Yanchang Formation in eastern Gansu, Ordos Basin, and studies of the pore throat size controlling on physical property of the tight sandstone reservoirs are also carried out. The result shows that the pore type is mainly dominated by the residual intergranular pore, dissolution pore, micropore and a few micro-fractures; the high-pressure mercury injection experiment indicates that the pore-throat size ranges from 0.0148 μm to 40 μm, the pore throat more than 1 μm is less; the rate-controlled mercury injection experiment reveals that for samples with different physical properties, the pore radius mainly varies from 80 μm to 350 μm; the throat radius exhibits the strong heterogeneity, and is from 0.12 μm to 30 μm; the pore-throat size can be effectively characterized by combination of high-pressure and rate-controlled mercury injections, and it varies from 0.0148 μm to 350 μm. The permeability is mainly controlled by the large pore throat (>R50) which accounts for a small proportion; in the tight sandstone with the permeability greater than 0.1 mD, the permeability is mainly controlled by the micropore and mesopore; in the tight sandstone with the permeability smaller than 0.1 mD, the permeability is mainly controlled by the nanopore and micropore; the proportion of small pore throat increases with reduction of permeability, it is important that the small pore throat influences the reservoir storage property though its effect on permeability are small.

Reservoir quality and burial model evaluation by kinetic quartz and illite cementation modeling: Case study of Rotliegendes, north Germany

Silicate reaction kinetics provide a complementary means to other established paleothermal indicators such as organic maturation for evaluating thermal reconstructions. In this study we combine the use of an organic maturation model with kinetic models for quartz and illite cementation to evaluate burial history scenarios for five subsalt wells in lithologically and structurally complex Rotliegendes reservoirs. Models for organic maturation are most sensitive to maximum temperature and provide no direct evidence for the time of peak temperature or the overall duration of high temperatures. By contrast, the kinetics of quartz cementation are much more strongly influenced by the duration of exposure to high temperatures compared with organic indicators. Kinetic models for fibrous illite formation similarly are sensitive to time and temperature and provide predictions for the time of illite formation that can be compared with radiometric dates. Used collectively, these organic and inorganic paleothermal indicators provide improved constraints on thermal evolution compared with conventional approaches. In this study we use these indicators to evaluate two alternative burial history scenarios. Scenario 1 incorporates a hypothesized Jurassic heat flow peak together with significant Late Jurassic deposition and subsequent erosion. Scenario 2 omits the Jurassic heat flow peak and omits the deposition and erosion of the Upper Jurassic. Although both of these scenarios are consistent with organic maturation data, scenario 2 leads to a far better match with quartz cement volumes and fibrous illite K-Ar dates.

Fuzzy Logic in Carbonate Reservoir Quality Assessment: A Case Study from Tarim Basin, China

Introduction: To address reservoir quality assessment in highly complex and heterogeneous carbonate reservoirs, a methodology utilizing fuzzy logic is developed and presented in this paper. Based on carbonate reservoir characteristics, three parameters reflecting the macroscopic and microscopic of storage abundance, permeability, and median of pore throat radius were selected to establish the factor set and the evaluation criteria. After analysis of core and test data, a membership function is constructed by semi-drop trapezoid method and the weight formula is also determined by reservoir factor sub-index. The developed method then is used to evaluate a carbonate reservoir in the Tarim Basin in China. Based on the result of single well evaluation, the plane classification map of the carbonate reservoir quality is constructed. Results obtained from reservoir quality assessment in the K32 well show that I-level, II-level, and III-level reservoir qualities account for 58%, 37%, 5% of the reservoir, respectively. The results are consistent with the actual production data demonstrating reliability of the proposed method for reservoir quality assessment practices in usually very complex and heterogeneous carbonate reservoirs. Background: Carbonate reservoirs are complex and heterogeneous and this makes their evaluation a difficult task. Objective: To overcome the uncertainties associated with evaluation of complex carbonate reservoirs a reliable method to accurately evaluate carbonate reservoirs is presented. Methods: Fuzzy logic is used to evaluate a carbonate reservoir from Tarim Basin in China. Based on carbonate reservoir characteristics, three parameters reflecting the macroscopic and microscopic of storage abundance, permeability, and median of pore throat radius are selected to establish the factor set and to evaluate the criteria of carbonate reservoir. After the analysis of core and test data, a membership function is reasonably constructed by semi-drop trapezoid method and the weight formula is also determined by reservoir factor sub-index. Results: An effective methodology for the evaluation of reservoir quality in carbonate reservoirs is established by using fuzzy logic. In addition, an example reservoir from China is used to demonstrate the applicability of the developed method. Conclusion: Based on the result of single well evaluation, the plane classification map of the carbonate reservoir is constructed. Favorable zones in the reservoir are also delineated. Evaluation results are consistent with the actual production data of gas and oil which proves that the proposed method is instrumental in reservoir quality assessment.

High-resolution sequence stratigraphy, sedimentology and reservoir quality evaluation of the Yaojia Formation in the Longxi area of the Western Slope, Songliao Basin, China

Delta-front sand bodies with large remaining hydrocarbon reserves are widespread in the Upper Cretaceous Yaojia Formation in the Longxi area of the Western Slope, Songliao Basin, China. High-resolution sequence stratigraphy and sedimentology are performed based on core observations, well logs, and seismic profile interpretations. An evaluation of the reservoir quality of the Yaojia Formation is critical for further petroleum exploration and development. The Yaojia Formation is interpreted as a third-order sequence, comprising a transgressive systems tract (TST) and a regressive systems tract (RST), which spans 4.5 Myr during the Late Cretaceous. Within this third-order sequence, nine fourth-order sequences (FS9–FS1) are recognized. The average duration of a fourth-order sequence is approximately 0.5 Myr. The TST (FS9–FS5) mostly comprises subaqueous distributary channel fills, mouth bars, and distal bars, which pass upward into shallow-lake facies of the TST top (FS5). The RST (FS4–FS1) mainly contains subaqueous distributary-channel and interdistributary-bay deposits. Based on thin-sections, X-ray diffraction (XRD), scanning electron microscope (SEM) and high-pressure mercury-intrusion (HPMI) analyses, a petrographic study is conducted to explore the impact of the sedimentary cyclicity and facies changes on reservoir quality. The Yaojia sandstones are mainly composed of lithic arkoses and feldspathic litharenites. The sandstone cements mostly include calcite, illite, chlorite, and secondary quartz, occurring as grain coating or filling pores. The Yaojia sandstones have average core plug porosity of 18.55% and permeability of 100.77 × 10−3 μm2, which results from abundant intergranular pores and dissolved pores with good connectivity. Due to the relatively coarser sediments and abundant dissolved pores in the feldspars, the FS4–FS1 sandstones have better reservoir quality than the FS9–FS5 sandstones, developing relatively higher porosity and permeability, especially the FS1 and FS2 sandstones. The source–reservoir–cap-rock assemblages were formed with the adjoining semi-deep lake mudstones that were developed in the Nenjiang and Qingshankou Formations. This study reveals the deposition and distribution of the delta-front sand bodies of the Yaojia Formation within a sequence stratigraphic framework as well as the factors controlling the Yaojia sandstones reservoir quality. The research is of great significance for the further exploration of the Yaojia Formation in the Longxi area, as well as in other similar lacustrine contexts.

Controls on reservoir quality in exhumed basins – an example from the Ordovician sandstone, Illizi Basin, Algeria

Petroleum exploration in many North African intracratonic basins targets Early Paleozoic sandstones as the primary reservoir objective. These sandstones are often characterized by highly variable reservoir quality (0.0001–1000 mD), and the ability to predict and selectively target areas of enhanced porosity and permeability is crucial to unlock the hydrocarbon potential. The objective of this study is to characterize the primary controls on reservoir quality in an Ordovician field in the Illizi Basin of Algeria through detailed core and petrographic analysis, and establish if variations in thermal history across the field have a material impact on reservoir quality. The best reservoir quality is observed in facies where primary intergranular porosity has been preserved in fine to coarse grained quartzarenites with less than 1% fibrous illite. These lithologies are most commonly found within the high-energy, tidally reworked, post-glacial facies sandstones of the uppermost Ordovician succession. Observed differences in quartz cement volume within compositionally and texturally similar samples from the southern and northern parts of the field are interpreted to reflect variations in thermal exposure due to deeper burial. This interpretation is supported by field-wide numerical modelling of sandstone diagenesis. This study indicates that subtle variations in thermal history can have a material impact on the spatial trends in reservoir permeability. Thermal history, therefore, is an important consideration in reservoir quality studies in exhumed basins where variations in present-day burial depth will be a poor guide for evaluating reservoir quality risk across a basin or play.

Digital Rocks: Emerging Technology to Business-Proven Capability

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170752, “Digital Rocks: Developing an Emerging Technology Through to a Proven Capability Deployed in the Business,” by J.T. Fredrich, D.L. Lakshtanov, N.M. Lane, E.B. Liu, C.S. Natarajan, D.M. Ni, and J.J. Toms, BP, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed. This paper describes the development of “digital-rocks” technology, in which high-resolution 3D image data are used in conjunction with advanced modeling and simulation methods to measure petrophysical rock properties. This technology has developed into a proven capability sanctioned for use in the operating assets of a large multinational oil company. Digital-rocks technology can improve evaluation of reservoir quality and quantification of hydrocarbons in place, and it can help inform the development of improved-recovery methods. Introduction The premise of the technology is to apply state-of-the-art high-resolution 3D imaging technologies to derive digital descriptions of reservoir rocks, typically at a resolution of approximately 1–5 Μm, or even lower for complex rocks with significant microporosity less than 1 Μm in dimension. These digital descriptions can be thought of as a numerical grid or mesh and, in conjunction with the appropriate models and numerical algorithms, can be used to perform massively parallel simulations of pore-scale processes of interest. These simulations can then be interpreted to derive macroscopic static and dynamic rock properties. Because the geometrically and topologically complex pore-scale architecture of the rock is captured in the 3D image and faithfully represented in the computational mesh, the numerical solution of the underlying physics is not compromised as long as the image is acquired with the requisite fidelity, and at a suitable resolution and over a representative elementary volume. In the field of computational physics, this general approach is known as direct numerical simulation (DNS). While DNS is often used to describe a solution method for problems in computational fluid dynamics, there exists an underlying generality and the same concept can be applied to other partial-differential equations (PDEs) of interest, thereby expanding application to various rock properties in addition to intrinsic permeability.

Onshore Sandstone Facies Characteristics and Reservoir Quality of Nyalau Formation, Sarawak, East Malaysia: An Analogue to Subsurface Reservoir Quality Evaluation

Shallow marine sandstones are substantial hydrocarbon reservoirs located around the globe and in Southeast Asia. Understanding the internal characteristics, distribution, geometry and lateral extent of these sandstones are essential parts of successful exploration and production strategy. This study presents the first detailed work on reservoir sandstone facies including textural characteristics of shallow marine sandstones (well-exposed outcrops) of the Nyalau Formation (Oligocene–Middle Miocene), Bintulu area, Sarawak, East Malaysia. This formation is the onshore equivalent of the offshore cycles II and III. We examined five different major types of sandstone facies on the basis of sedimentological characteristics, grain size distribution, porosity (ϕ) and permeability (k). The analyzed sandstone facies are: (1) hummocky cross-stratified sandstones (ϕ = 32.07 %, k = 20.78 md; thickness from 1 to 2 m); (2) herringbone cross-bedded sandstones (ϕ = 31.31 %, k = 7.7 m; thickness from 1 to 10 m); (3) trough cross-bedded sandstones (ϕ = 35.80 %, k = 5.97 md; thickness from 0.5 to 1 m); (4) wavy- to flaser-bedded sandstones (ϕ = 19.84 %, k = 2.31 md; thickness from 0.5 to 3.5 m); and (5) bioturbated sandstones (ϕ = 8.21 %, k = 3.46 md; thickness from 1 to 2 m). By integrating these parameters, we observed that the best reservoir quality sandstones are hummocky cross-stratified sandstone and herringbone cross-bedded sandstone, because they have better porosity–permeability than that of other sandstone facies, despite having similar grain distribution with probability curves having steep trends and almost same grain size, roundness and sorting. Upon comparing the different facies, inferences can be made that porosity–permeability is distributed randomly. We conclude that there exist heterogeneities within different sandstone facies which may apply to the reservoir properties in the subsurface.

Characterization of organic matter fractions in an unconventional tight gas siltstone reservoir

This paper on core samples collected from the Triassic Montney Formation tight gas reservoir in the Western Canadian Sedimentary Basin (WCSB) illustrates that operationally-defined S1 and S2 hydrocarbon peaks from conventional Rock–Eval analysis may not adequately characterize the organic constituents of unconventional reservoir rocks. Modification of the thermal recipe for Rock–Eval analysis in conjunction with manual peak integration provides important information with significance for the evaluation of reservoir quality. An adapted method of the analysis, herein called the extended slow heating (ESH) cycle, was developed in which the heating rate was slowed to 10°C per minute over an extended temperature range (from 150 to 650°C). For Montney core samples within the wet gas window, this method provided quantitative distinctions between major organic matter (OM) components of the rock. We show that the traditional S1 and S2 peaks can now be quantitatively divided into three components: (S1ESH) free light oil (S2aESH) fluid-like hydrocarbon residue (FHR), and (S2bESH+residual carbon) solid bitumen (more refractory, consolidated bitumen/pyrobitumen).The majority of the total organic carbon (TOC) in the studied Montney core samples consists of solid bitumen that represents a former liquid oil phase which migrated into the larger paleo-intergranular pore spaces. Physicochemical changes to the oil led to the precipitation of asphaltene aggregates. Subsequent diagenetic and thermal cracking processes further consolidated these asphaltene aggregates into “lumps” of solid bitumen (or pyrobitumen at higher thermal maturity). Solid bitumen obstructs porosity and hinders fluid flow, and thus shows strong negative correlations with reservoir qualities such as porosity and pore throat size.Although the FHR fraction constitutes a small portion of the total rock mass and volume in Montney samples it has important implications for reservoir quality. This fraction represents a thin film of condensed, heavy molecular hydrocarbon residue covering surfaces of the present-time pore spaces and may represent the lighter component of the paleo-oil that migrated into tight interstices in the Montney reservoir. The FHR fraction potentially plays an important role in wettability alteration by creating hydrophobic matrix pore networks in portions of the reservoir that were not already filled with solid bitumen.