Properties Of Tight Reservoirs Research Articles

Influence of reservoir physical properties on guar gum fracturing fluid damage in unconventional tight reservoirs

Solid phase residue, fracturing fluid filtration, and incomplete backflow during hydraulic fracturing can easily cause damage to tight sandstone reservoir. Thus, it is necessary to explore the relationship between the physical properties of tight reservoirs and damage caused by fracturing fluids. Based on the identification of reservoir physical properties, the relationship between reservoir physical properties and fracturing fluid damage was studied by core displacement, computerized tomography, and nuclear magnetic resonance (NMR). The results show that the higher the clay mineral content is, the denser the formed core is, and the corresponding core porosity and permeability are lower. When the permeability and porosity of the rock core are relatively high, the overall radius of the pore throat in the rock core shifts to the left under the action of the gel breaking fracturing fluid, showing a decreasing trend. However, when the permeability and porosity of the rock core are relatively low, the frequency peak of the smaller size of the pore throat in the rock core under the action of the gel breaking fracturing fluid increases upwards. The corresponding core permeability decline rate of the two types of tight sandstone reservoirs is 9.91%–8.78% and 15.85%–14.74%. The porosity decline rates are 5.53%–5.84% and 10.40%–9.94%. According to NMR results, it is speculated that under the action of gel breaking fracturing fluid, the small pore throats in the rock core are blocked or even disappear, while the proportion of smaller pore throats increases and the proportion of larger pore throats decreases. The results of this study provide theoretical reference for reservoir protection during the fracturing process of tight sandstone reservoirs.

Study on the rock physical mechanical properties evaluation of tight oil reservoir in Chang 7 member, Longdong area, Ordos Basin, China

The study aims to investigate the rock mechanical properties of the Chang 7 member tight oil reservoir in the Longdong region of the Ordos Basin, China, with the goal of enhancing the efficiency of oilfield development. Despite numerous contributions in the field of rock mechanics, challenges persist in reconciling experimental results with actual geological conditions and achieving comprehensive understanding of rock mechanical properties in tight oil reservoirs. To address this, a variety of experimental methods were employed to systematically assess the mechanical properties of the target reservoir. Rock density was measured using volumetric methods, tensile strength was evaluated through the Brazilian test, uniaxial and triaxial compression tests were conducted to assess rock mechanics properties, and dynamic elastic modulus and Poisson’s ratio were obtained via sonic velocity measurements. Furthermore, differential strain analysis and imaging log analysis were employed to determine the magnitude and direction of geostress. The results revealed that fine-grained sandstone exhibited higher rock density and relatively higher tensile strength, while muddy siltstone exhibited comparatively lower values in these aspects. Analysis of the influence of confining pressure on rock mechanics properties demonstrated a strong positive correlation between compressive strength and Young’s modulus with confining pressure, while Poisson’s ratio exhibited more irregular variations. Additionally, a mathematical relationship between dynamic and static rock mechanical parameters was established. Lastly, based on the characteristics of geostress, reliable foundations for optimizing hydraulic fracturing and wellbore layout were provided. This study has enriched and complemented the investigation of rock mechanical properties in tight reservoirs, offering vital parameters and theoretical support for the development of tight oil reservoirs. This bears significant importance in enhancing petroleum extraction efficiency and optimizing engineering design.

Advances in critical temperature shift modeling of confined pure fluids using the Kihara potential function

A multitude of research works have been conducted in the past decade to better predict the change of critical properties of fluids confined in nanopores, known as critical shift, due to its great impact upon calculations of fluid properties in tight reservoirs. Modeling of this phenomenon commenced with developing equations of state (EOS) and has been continuing with correlations, all based on the two-parameter Lennard–Jones (L–J) potential function. Although these approaches have tried to present passable estimations of critical shift, sufficiently accurate predictions of critical shift are still missing in the literature. In this study, the three-parameter Kihara potential, as a more physically realistic alternative, is used to develop the van der Waal (vdW) EOS, and accordingly, a fluid-dependent expression is derived to calculate the critical temperature of confined fluids, i.e., pore critical temperature ({T}_{mathrm{cp}}). Using 50 data points of {T}_{cp} reports for normal alkanes in the literature, the average error of our model is only 2.23%, 6.4% less than that of the L–J model. Furthermore, despite simple correlations of previous works, herein the Kihara parameters are exclusively tuned for each component based on their {T}_{cp} reports, which resulted in an average error of 0.4% for normal alkanes. Finally, the pressure–volume diagrams of vdW and Peng–Robinson EOSs associated with the Kihara potential function are comprehensively discussed. The findings of this study can help researchers with more accurate predictions of the critical temperature of fluids confined in tight porous media, thereby providing more precise calculations of fluid properties and behavior at equilibrium conditions.

Upper Paleozoic total petroleum system and geological model of natural gas enrichment in Ordos Basin, NW China

Based on the analysis of Upper Paleozoic source rocks, source-reservoir-caprock assemblage, and gas accumulation characteristics in the Ordos Basin, the gas accumulation geological model of total petroleum system is determined. Then, taking the Carboniferous Benxi Formation and the Permian Taiyuan Formation and Shanxi Formation as examples, the main controlling factors of gas accumulation and enrichment are discussed, and the gas enrichment models of total petroleum system are established. The results show that the source rocks, faults and tight reservoirs and their mutual coupling relations control the distribution and enrichment of gas. Specifically, the distribution and hydrocarbon generation capacity of source rocks control the enrichment degree and distribution range of retained shale gas and tight gas in the source. The coupling between the hydrocarbon generation capacity of source rocks and the physical properties of tight reservoirs controls the distribution and sweet spot development of near-source tight gas in the basin center. The far-source tight gas in the basin margin is mainly controlled by the distribution of faults, and the distribution of inner-source, near-source and far-source gas is adjusted and reformed by faults. Generally, the Upper Paleozoic gas in the Ordos Basin is recognized in four enrichment models: inner-source coalbed gas and shale gas, inner-source tight sandstone gas, near-source tight gas, and far-source fault-transported gas. In the Ordos Basin, inner-source tight gas and near-source tight gas are the current focuses of exploration, and inner-source coalbed gas and shale gas and far-source gas will be important potential targets in the future.

Further discussion of CO2 huff-n-puff mechanisms in tight oil reservoirs based on NMR monitored fluids spatial distributions

Due to the poor physical properties of tight reservoirs, CO2 huff-n-puff (HNP) is considered a potential enhanced oil recovery (EOR) method after primary depletion. Optimization plays a critical role in the effective implementation of CO2 huff-n-puff. But the optimization requires a good understanding of the EOR mechanisms. In this work, the spatial distribution of oil saturation under different experimental conditions was analyzed by the NMR method to further discuss the HNP mechanisms. According to the variation of 1D frequency signal amplitude, we divided the core into the hardly movable area and movable area, the region with the obvious signal decline was defined as the movable area, and the hardly movable area was the region with limited signal decline. Based on that the recovery characteristics of different scenarios were evaluated. Firstly, the necessity of the soaking stage was studied, where three scenarios with different soaking times were carried out. Secondly, the injection pressure was adjusted to investigate the effect of the pressure gradient. The T2 spectra show that soaking has significantly improved the production of crude oil in small pores, and higher oil recovery in a single cycle is observed, but it is lower when the elapsed time (total operation time) is the same. 31.03% of oil can be recovered after 3 cycles HNP, which increases to 33.8% and 37.06% for the 4 cycles and 6 cycles cases. As the pressure gradient increases, more oil is removed out of the matrix, and the oil in the deep part of the reservoir can be effectively recovered. During the CO2 huff-n-puff process, the oil distributions are similar to the solution gas drive, the residual oil is distributed at the close end of the core and the range that the oil can be efficiently recovered is limited.

Analysis and Estimation of an Inclusion-Based Effective Fluid Modulus for Tight Gas-Bearing Sandstone Reservoirs

Due to the special petrophysical properties of tight reservoirs, such as poor connectivity and low porosity, conventional rock physics models show limitations. Based on an inclusion-based method, a new formula containing fluid pressure is derived without an equilibration assumption of fluid pressures in the inclusions. Then, the formula is simplified with an equivalent pore structure to yield a new fluid identification parameter, the inclusion-based effective fluid modulus (IEFM). By analysis, this fluid identification factor is quite sensitive to water saturation for different pore connectivity. A well-logging data test shows the superiority of the proposed model in identifying tight gas-bearing zones. Seismic data application also demonstrates the validity of the proposed model and the predicted results match well with the well-logging data. In fluid identification, two probabilistic estimation methods are used: Bayes posterior prediction framework is a combination of Bayes’ theory and a deterministic rock physics model; Bayes discriminant method is a statistical rock physics method. The proposed IEFM is a novel identification parameter for tight gas-bearing reservoirs, which can have many applications in the exploration of tight reservoirs.

Machine-Learning Approach Optimizes Well Spacing

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201698, “Finding a Trend Out of Chaos: A Machine-Learning Approach for Well-Spacing Optimization,” by Zheren Ma, Ehsan Davani, SPE, and Xiaodan Ma, SPE, Quantum Reservoir Impact, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Data-driven decisions powered by machine-learning (ML) methods are increasing in popularity when optimizing field development in unconventional reservoirs. However, because well performance is affected by many factors, the challenge is to uncover trends within all the noise. By leveraging basin-level knowledge captured by big data sculpting, integrating private and public data with the use of uncertainty quantification, a process the authors describe as augmented artificial intelligence (AI) can provide quick, science-based answers for well spacing and fracturing optimization and can assess the full potential of an asset in unconventional reservoirs. A case study in the Midland Basin is detailed in the complete paper. Introduction Augmented AI is a process wherein ML and human expertise are coupled to improve solutions. The augmented AI work flow (Fig. 1) starts with data sculpting, which includes information retrieval; data cleaning and standardization; and smart, deep, and systematic data quality control (QC). Feature engineering generates all relevant parameters entering the ML model. More than 50 features have been generated for this work and categorized. The final step is to perform model tuning and ensemble, evaluating model robustness and generating model explanation and uncertainty quantification. Geology The complete paper provides a detailed geological background of the Permian Basin and its Wolfcamp unconventional layer, an organic-rich shale formation with tight reservoir properties. To find a solution for the multidimensional well-spacing problem in the Permian Basin, multiple sources and types of data were gathered using publicly available sources. The detailed geological attributes, including structure, petrophysics, geochemistry, basin-level features, and cultural information (such as counties or lease boundaries) have been combined in an integrated database to extract and generate features for the ML algorithm. Most attributes are available either in a limited number of wells, mostly vertical, or through the low number of available cored wells across the basin. Therefore, a significant amount of data imputation has been processed with mapping exercises using geostatistical modeling techniques. The mapping process augmented the ML attribute-generation step because these features were distributed in both vertical and lateral dimensions. All horizontal wells within the area of interest across the Permian Basin have been resampled with the logged and mapped information. The geological features also are reengineered into multiple indices to reduce the number of labeled features to include in the ML process. This feature-reduction process also has helped in ranking and selecting the most-important parameters relevant to the well-spacing problem. Here, a key attribute called the shale-oil index was introduced, which is generated for the ML-driven process and is used in understanding the level of contribution of geological sweet spots to well-spacing optimization. In addition, the initial well, reservoir, or laboratory data, including logs, have been normalized before mapping and modeling to eliminate potential bias. This study has focused on Wolfcamp layers; however, both geological and engineering attribute generation work flows used for this practical ML methodology to find optimization solutions for common problems are highly applicable to other unconventional layers, such as Bone Spring or Spraberry.

The influence of diagenetic heterogeneity on tight-reservoir properties in the Upper Triassic Yanchang Formation, Southeastern Ordos Basin, China

ABSTRACT The Chang 7–8 sections of Yanchang Formation in the Ordos Basin are dominated by lacustrine tight sandstones but characterized by high hydrocarbon production. This setting provided an opportunity to study reservoir characteristics and diagenetic processes of tight sandstones, to facilitate future oil exploration. In this study, it was found that reservoir qualities were mainly controlled by the diagenetic heterogeneity at different parts of sandstones, based on a comprehensive analysis of thin sections, scanning electron microscopy (SEM), X-ray diffraction (XRD), pressure-controlled mercury injection, X-ray computed tomography (XCT), and well log data. Carbonate cements tend to occur at the edges of sandstone bodies. Sandstone layers with a distance less than 0.5 m from the sandstone–mudstone interface, or with a thickness of less than 1.5 m, were rich in carbonate cements (carbonate content was more than 15%). Lower porosity (less than 4%) and permeability (less than 0.01 mD) trend to distribute in sandstones that have higher content of carbonate cements. The source of carbonate cements was most likely from adjacent mudstones or from the dissolution of unstable grains. Samples collected from the center of sandstone layers have higher porosity, pore connectivity, and permeability but with low carbonate cement content. Hydrocarbon accumulation was facilitated through vertical fractures between the layers. The dissolution of feldspar and lithic fragments by organic acid associated with oil charging improved reservoir properties in the center of sandstone layers, and generated material for carbonate cement precipitation at the edge of sandstone layers. The results of this study demonstrated that the dominance of different diagenetic processes led to a reduction of reservoir quality at the edge of sandstone layers but an increase in the center of sandstone layers. This research offered a new perspective on the study of reservoir properties and the diagenesis mechanism of tight sandstones, which could be conducive to tight oil exploration and development.

Methods to determine the upper limits of petrophysical properties in tight oil reservoirs: Examples from the Ordos and Songliao Basins

In large petroliferous basins, tight and conventional reservoirs are widely distributed. These reservoirs have significant differences in formation mechanisms, enrichment rules, and development modes. Only when a reservoir petrophysical property is less than a certain upper limit can a large area of tight oil accumulation be formed. Therefore, it is necessary to scientifically define the petrophysical property boundary between tight and conventional reservoirs. In the past, the determination of petrophysical property boundaries between tight and conventional reservoirs was based mainly on the statistics of a large number of measured petrophysical property data of typical tight oil basins and lacked theoretical research. Taking the Ordos and Songliao Basins as examples, this paper studies the petrophysical upper limits of tight reservoirs, starting with the reservoir-forming mechanism and characteristics of tight and conventional reservoirs. Based on four methods—the mechanical balance method assuming that the buoyancy and capillary pressure are equal, petrophysical simulation of an oil accumulation in sandstone, analysis of the distribution characteristics of the current petrophysical properties of conventional and tight oil reservoirs, and mercury injection porosimetry tests to determine the change in reservoir porosity and permeability with displacement pressure—this research determines that basically the same upper limits of tight reservoir properties are found among these methods. Obtained synthetically, the upper limit of permeability is approximately 1 md, corresponding to the upper limit of porosity of approximately 12%. These research results provide new ideas and methods to distinguish tight oil from conventional oil accumulations in petroliferous basins in different stages of exploration.

Critical conditions of tight oil charging and determination of the lower limits of petrophysical properties for effective tight reservoirs: A case study from the Fengcheng Formation in the Fengcheng area, Junggar Basin

Studying the lower limits of petrophysical properties is important to evaluate the exploration and development potentials of tight oil reservoirs. At present, the evaluation criteria are based on a large number of cores and logging data, and rules are based on collections of empirical statistics and displacement pressure experiments. However, there have been few studies on the lower limits of the petrophysical properties of tight reservoirs based on force balance conditions for the hydrocarbon charging process. In this paper, the critical condition for hydrocarbon charging is determined using the oil expansion pressure as the main driving force, with the capillary pressure as the major resistance, via an analysis of the dynamic mechanism of tight oil reservoirs. A force-balance model for judging the lower limits of the petrophysical properties of tight reservoirs can be established by assuming that the oil expansion pressure is equal to the capillary force. This discriminant method is applied to calculate the critical pore-throat radius of the effective reservoirs of the Lower Permian Fengcheng Formation in the Fengcheng area, Junggar Basin, which are 0.310 μm, 0.248 μm, 0.208 μm, and 0.135 μm, when the buried depths are 2500–3000 m, 3000–3500 m, 3500–4000 m, and 4000–4500 m, respectively. The corresponding critical porosities are 6.15%, 4.84%, 3.81%, and 1.20%, respectively. The lower limits of the petrophysical properties of effective tight reservoirs gradually decrease with increasing burial depth. This method is of great significance for resource evaluations of tight oil reservoirs and the selection of exploration zones.

A brittleness evaluation method based on breaking energy theory for tight reservoir in Dagang Oilfield

The tight reservoirs in Dagang Oilfield are deep in burial depth and complex in lithology, and the brittleness evaluation methods commonly used at home and abroad are not accurate enough to effectively guide the design of fracturing. As a result, the fracturing in the early days was low in success rate and not ideal in effect. In this study, from the perspective of breaking energy theory, based on a large number of core experiments, the factors affecting rock failure morphology have been analysed by using the breaking energy theory, and a brittleness evaluation method more suitable for the physical properties of tight reservoirs in Dagang Oilfield has been worked out. The results show that the main parameters affecting brittleness of tight reservoirs in Dagang Oilfield are Young’s modulus, dilatancy angle and peak strain. The correlation coefficient between the brittle index from the new method based on breaking energy theory and rock failure complexity increases to 0.789 compared with 0.329 of the brittle index from Rickman’s evaluation method. The new method solves the problem that previous brittleness index models at home and abroad are not suitable for tight reservoirs in Dagang Oilfield, and provides a theoretical basis for evaluating the fracability of tight reservoirs and improving fracturing effect in Dagang Oilfield.

Characteristics and controlling factors of tight sandstone gas reservoirs in the Upper Paleozoic strata of Linxing area in the Ordos Basin, China

Due to the large resource potential of tight sandstone gas, the Upper Paleozoic strata of the Linxing area has become an important exploration target in the Ordos Basin. In this study, by analyzing the distribution characteristics of tight sandstone gas (TSG), the relations of source-reservoir assemblages were divided into three types containing interbedded with source rocks (Type I), adjacent to source rocks (Type II) and far from source rocks (Type III). Five factors were identified to control their genesis, migration, and accumulation. Firstly, the gas generation intensity of source rocks is larger than 10 × 108 m3/km2, which indicated that source rocks could provide gas to the reservoirs. The gas generation centers of source rocks control the distribution of TSG reservoirs, while the areas among the hydrocarbon generation centers were the enrichment zones for TSG. Secondly, under the condition of generally tight reservoirs, the sandstone reservoir which has good quality (high porosity, high permeability) provided the favorable accumulation condition for TSG. Thirdly, the study area experienced one stage of gas charging mainly from the late early Jurassic to late early Cretaceous, which was 178 to 100Ma. Continuous gas generation and expulsion led to the sustained accumulation of TSG. Fourthly, with the general development of overpressure in the Upper Paleozoic strata, gas expansion force as the main power drive natural gas to migrate into the reservoirs of type I and type II during the accumulation period. Finally, the development of faults and fractures provided a migration path for natural gas charging in the reservoir of type III vertically. The existence of microcracks can improve the petrophysical properties of tight reservoirs. Under the joint control of these factors, the reservoir of Type I is the most favorable exploration target.

Integrated geological and petrophysical characterization of oligocene deep marine unconventional poor to tight sandstone gas reservoir

The present study aims to evaluate, discriminate and delineate the geological and petrophysical situation of Oligocene reservoir wells at Salamat-1 and Atoll-1 in North Damietta offshore concession in the Mediterranean Sea. It deals with a combined interpretation of the core analysis (density, porosity, permeability and mercury injection capillary pressure ‘MICP’) and petrography data (thin sections, scanning electron microscope and X-ray diffraction) as well as well log (gamma ray, density, neutron, micro spherical logs ‘MSFL’, shallow and deep resistivity, and Modular Formation Dynamic Tester logs) and the subsurface geologic data, as well as some available seismic sections to clarify the geological and the petrophysical characterization of the Oligocene unconventional tight sandstone gas reservoir, Salamat structure, North Damietta offshore, Mediterranean Sea, Egypt. Petrophysically, the studied sandstone core samples can be summed up into two reservoir rock types (RRT), where poor reservoir quality is assigned to one group while the other is characterized by tight reservoir properties. These two RRTs are discriminated into four microfacies, two arenite groups and two wacke groups. Filling the pore spaces with detrital clays are the most important reservoir quality-reducing factors. The seismic data indicates that the studied area is composed of Rupelian-Chattian multi-channel system located off shore with many sand channels distributed in the area. The Lower and Upper Chattian sand channels comprise the most important reservoir bodies in Atoll-1 well to the northeast of the study are gas-bearing bodies, whereas the Rupelian sand channels to the northwest at Salamat-1 well are the most important gas-bearing channels. Integration between the available core and well log data indicated that the best storage and flow capacity are assigned to the other water-bearing sand channels rather the gas-bearing channels in both Salamat-1 and Atoll-1 wells. • The Rupelian-Chattian multi-channel sandstones are the target of this study. • Delineate the geological and petrophysical situation of Oligocene clastic reservoirs. • Petrophysically, two reservoir rock types can be assigned in the studied sequence. • Petrographically, the studied samples are discriminated into four microfacies. • Filling the pore spaces with detrital clays is the main reservoir quality-reducing factor.

Generalized Methodology for Estimating Stress-Dependent Properties in a Tight Gas Reservoir and Extension to Drill-Cuttings Data

Summary The volume of hydrocarbons contained in tight petroleum reservoirs is immense. Thus, their development is crucial to satisfy the worldwide energy demand. A critical aspect for the development of these formations is the stress dependency of rock properties. As pore pressure changes, porosity, permeability, and compressibility of both matrix and natural fractures in tight reservoirs also change, affecting the wells’ production behavior. A practical problem in the estimation of stress-dependent properties is that the amount of core data available to perform the corresponding studies in tight formations is generally scarce. Under these circumstances, drill cuttings can be used to obtain this information. These observations lead to the key objective of this paper: to develop a reliable approach for estimating stress-dependent properties through the introduction of an innovative methodology that quantifies changes in properties of tight reservoirs and how to extend this methodology in drill cuttings. The model developed is based on the relationship between the cube root of normalized permeability and the logarithm of net confining stress defined as confining pressure minus pore pressure applied on the rock. An empirical exponent α is introduced to fit the experimental data from confining tests conducted on both vertical and horizontal core samples. This exponent allows the development of an equation that works independently of the initial net confining stress, which is the main limitation of the models already available in the literature. It is our experience that, in many instances, laboratory tests are run at specific values of net confining stress that do not necessarily match the current stress of the reservoir. The correlation proposed in this paper is valuable because it provides a tool that allows correcting the laboratory results to the appropriate net confining stresses in the reservoir. A statistical analysis is performed to verify the appropriateness of the proposed model for the prediction of rock properties as a function of net confining stress. It is shown that current formulations are particular cases of the proposed model based on the results obtained for the empirical exponent α. Semilog cross-plots of the cube root of normalized permeability versus the net confining stress using core laboratory data corroborate the robustness of the proposed method. The application of the method with drill cuttings is also demonstrated. It is concluded that the proposed method provides a more accurate methodology for estimating stress-sensitive properties of rocks in tight formations, which are usually naturally fractured, such as the Nikanassin formation analyzed in this work. Porosity, permeability, and compressibility of tight formations are estimated by following the generalized methodology proposed in this study.

The dissolution characteristics of the Chang 8 tight reservoir and its quantitative influence on porosity in the Jiyuan area, Ordos Basin, China

The Chang 8 tight reservoir in the area of Jiyuan holds characteristics such as high feldspar content and common feldspar dissolution phenomenon, which are vital to improve the physical properties of tight reservoirs. This paper simulates the interaction between the Chang 8 tight reservoir rock samples and organic acid, analyzes the types and characteristics of dissolution, explains the dissolution mechanism, and quantitatively calculates the influence of dissolution on the porosity of the reservoir on the basis of identifying the fundamental characteristics of the Chang 8 tight reservoir by utilizing the simulation experiment of fluid–rock interaction with high temperature and high pressure combined with polarized microscope and scanning electron microscope (SEM) and X-ray diffraction (XRD) analysis techniques. With the purpose of making the simulation experiment closer to the actual geological conditions, 0.15 mol/L acetic acid solution with pH = 2.65 is used as the reaction fluid, wherein the simulated temperature range is set to 87–103 °C, and the simulated pressure range is set to 24.70–30.18 MPa. The result of the research shows that intergranular pores and feldspar dissolved pores are the primary pore types. The feldspar dissolved pores are more developed and accounts for 39% of the total porosity. The apparent solution ratio is 37.8%–50.0% with a moderate degree of dissolution. Additionally, carbonate minerals can also be dissolved in an acidic condition. The solution ratio of carbonate minerals generally exceeds that of feldspar. The dissolution degree is most robust at about 95 °C, and the burial depth is about 2370–2710 m by the geothermal gradient calculation, which should be the primary distribution area of the favorable tight reservoir of the Chang 8. Overall, dissolution is the main diagenesis type to improve the porosity that can result in the porosity increasing about 3.57%–3.69% in the tight reservoirs of Chang 8. Therefore, it is also the main controlling factor for the development of the "dessert" in the Chang 8 tight reservoir of western Jiyuan area.

Estimates of Stress-Dependent Properties in Tight Reservoirs: Their Use With Core and Drill-Cuttings Data

Summary The objective of this paper is to present a methodology with drill cuttings for making estimates of porosity, permeability, and compressibility as a function of confining pressures in tight formations. An easy-to-use stress-dependent permeability correlation is developed by comparing results from experimental work including hysteresis at various combinations of overburden and pore pressures in vertical and horizontal core plugs, and permeabilities determined in the laboratory from drill cuttings. On the other hand, stress-dependent porosity and compressibility correlations with respect to permeability as a function of net confining stress (NCS) are also introduced. The work is important because of the presence of stress-dependent slot and/or microfracture porosities and permeabilities in tight formations that can significantly affect reservoir performance and forecasting. Recent work has shown that drill cuttings can be used quantitatively for complete petrophysical evaluation and rock-mechanical-properties estimation (Olusola and Aguilera 2013; Ortega and Aguilera 2014). The methods have been shown to be useful in those instances in which cores and specialized well logs are scarce. Porosity and permeability values obtained from the aforementioned works are extended in this paper to quantitative evaluation of stress-dependent properties. It is concluded that drill cuttings are important direct sources of information that can be used for developing estimates of stress-dependent petrophysical properties particularly in those cases in which cores and specialized logs are scarce or not available. The methodology and stress-dependent-permeability, -porosity, and -compressibility correlations are presented in detail, as well as a practical application for the case of drill cuttings. Although the main and novel contribution is the development of easy-to-use correlations for stress-dependent tight reservoirs with drill cuttings, the correlations can obviously be used if only plug data are available.

Tight Reservoir Properties Derived by Nuclear Magnetic Resonance, Mercury Porosimetry and Computed Microtomography Laboratory Techniques. Case Study of Palaeozoic Clastic Rocks

Results of the nuclear magnetic resonance (NMR) investigations, mercury porosimetry measurements (MP) and computed microtomography (micro-CT), applied to the tight Palaeozoic rocks from the depths lower than 3000 m, were presented to estimate their reservoir potential. NMR signal analysis and interpretation were performed. Based on NMR driven models, permeability and Free Fluid Index were calculated for data sets divided into homogeneous clusters. Computerized mercury porosimetry results visualization and processing provided useful information, as the automatically determined Swanson parameter is correlated with petrophysical properties of rocks. Micro-CT enriched the image of porous space in qualitative and quantitative ways. Homogeneity of pore space structure was discussed using micro-CT approach. Integration of the results in the frame of reservoir parameters from standard laboratory methods and the modern ones resulted in the improvement of methodology for determining the old, deep-seated, hard sedimentary rocks reservoir potential.