Typical Tight Oil Reservoirs Research Articles

The Characterization and Application of Flow Units in Tight Reservoirs Considering Stimulation Treatments

Block W is a typical tight oil reservoir, generally requiring artificial fracturing to achieve productivity. Consequently, conventional reservoir flow unit studies cannot objectively characterize the properties of tight oil reservoirs after fracturing. This paper integrates both the geological features and dynamic development characteristics of Block W, using Grey Relational Analysis (GRA) to select permeability, sand body thickness, mud content, and porosity as the key static parameters for defining flow units in tight oil reservoirs. The fluid injection intensity is selected as a critical artificial fracturing parameter. Based on these static and artificial fracturing parameters, a comprehensive characterization approach, the entropy weight–AHM method, is proposed to analyze flow units in tight oil reservoirs. The reliability of this method is validated through both production dynamics and geological features. Applied to Block W, this methodology establishes an evaluation standard for the compatibility of fracturing measures with reservoir characteristics and provides directions for adjusting stimulation treatments based on the compatibility levels. The findings deepen the understanding of the geological characteristics of the Block W tight oil reservoir and offer practical guidance for subsequent development adjustments. Additionally, this study serves as a valuable reference for characterizing flow units in tight reservoirs.

Experimental Study on Porosity & Permeability Characteristics of Typical Tight Oil Reservoirs

Experimental Study on Porosity & Permeability Characteristics of Typical Tight Oil Reservoirs

Numerical Simulation of Fracture Propagation of Multi-Cluster Perforation and Fracturing in Horizontal Wells: A Case Study of Mahu Oilfield

Mahu oilfield is a typical tight gravel oil reservoir. At present, long-stage multi-cluster fracturing is widely used for reservoir stimulation, and multiple-clusters treatment is realized through cluster perforation. Field monitoring indicates that not all perforation clusters produce hydraulic fractures in the fracturing process, and each cluster of hydraulic fractures in the section will expand unevenly. The unbalanced expansion of multiple clusters of fractures in the section seriously affects the effect of reservoir reconstruction of horizontal wells. Aiming at the long-stage multi-cluster fracturing of horizontal wells, a multi-fracture propagation calculation model considering wellbore flow, performance friction, different fracture criteria at the tip, and the interaction stress among multiple fractures is established in this paper. In order to improve the calculation efficiency, an explicit Runge Kutta Legendre algorithm is proposed to solve the structural mesh, and the solution program is compiled, which provides a basis for the theoretical analysis and rapid solution of the mechanism of multiple fracture growth. Finally, taking Mahu oil field as an example, we calculate the multi fracture propagation and flow distribution under different geological conditions, perforation conditions, and construction parameters. The research results will help to improve the fracturing efficiency of long-stage multi-cluster fractures.

Identification of Diagenetic Facies Logging of Tight Oil Reservoirs Based on Deep Learning—A Case Study in the Permian Lucaogou Formation of the Jimsar Sag, Junggar Basin

As a typical tight oil reservoir in a lake basin, the Permian Lucaogou Formation of the Jimsar Sag in the Junggar Basin has great potential for exploration and development. However, at present, there are few studies on the identification of the diagenetic facies of tight oil reservoir logging in the study area, and the control effect of diagenesis on tight oil reservoirs is not clear. The present work investigates the diagenesis and diagenetic facies logging of the study area, making full use of core data, thin sections, and logs, among other data, in order to understand the reservoir characteristics of the Permian Lucaogou Formation in the Jimsar Sag. The results show that the Lucaogou Formation has undergone diagenetic activity such as compaction, carbonate cementation, quartz cementation, and clay mineral infilling and dissolution. The diagenetic facies are classified according to mineral and diagenetic type, namely, tightly compacted facies, carbonate-cemented facies, clay mineral-filling facies, quartz-cemented facies, and dissolution facies. The GR, RT, AC, DEN, and CNL logging curves were selected, among others, and the convolutional neural network was introduced to construct a diagenetic facies logging recognition model. The diagenetic facies of a single well was divided and identified, and the predicted diagenetic facies types were compared with thin sections and SEM images of the corresponding depths. Prediction results had a high coincidence rate, which indicates that the model is of a certain significance to accurately identify the diagenetic facies of tight oil reservoirs. Assessing the physical properties of the studied reservoirs, dissolution facies are the dominant diagenetic facies in the study area and are also the preferred sequence for exploration—to find dominant reservoirs in the following stage.

Data-driven physics-informed interpolation evolution combining historical-predicted knowledge for remaining oil distribution prediction

The remaining oil distribution plays an important role in enhanced oil recovery (EOR), which directly guides the development of an oil reservoir in the middle and later stages. However, it is still challenging to accurately and efficiently characterize the distribution of remaining oil due to the complex reservoir geology. We propose a data-driven physics-informed interpolation evolution algorithm combining historical-predicted knowledge (DPIE-HPK) for the prediction of remaining oil distribution totally based on reservoir monitoring data. As a key step towards the remaining oil distribution, the production rates can be predicted as well. A physics-informed data supplement (PIDS) process is also presented to assist the DPIE-HPK algorithm. Both historical physics information and future information are used in the DPIE-HPK framework. The historical physical information is preprocessed by the PIDS, and future information is predicted by Long Short-Term Memory (LSTM) deep learning models. As a crucial interpolation evolution method, the Kriging method is also integrated into the framework to evolve the unknown spatial information. We test the DPIE-HPK framework for the prediction of the remaining oil distribution of a typical tight carbonate oil reservoir located in the Middle East. It is concluded that the DPIE-HPK framework is a fast, accurate and efficient intelligence tool for predicting the remaining oil distribution.

Pore-throat structure characteristics of tight reservoirs of the Middle Permian Lucaogou formation in the Jimsar Sag, Junggar Basin, northwest China

The Middle Permian Lucaogou Formation in the Junggar Basin, China is a typical tight oil reservoir. Thin sections, helium porosity and permeability, X-ray diffraction, X-ray computed tomography, and focused ion beam scanning electron microscopy were used to analyze 11 core samples with different oiliness from the Lucaogou Formation. Muddy siltstone, tuffaceous siltstone, dolomitic siltstone, and sandy dolarenite are the primary rock types in the Lucaogou tight oil reservoirs with different oil saturations. The dolomite content of the Lucaogou tight reservoir is positively correlated with porosity and permeability, suggesting that dolomite has an important influence on reservoir quality. Sandy dolarenite and dolomitic siltstone are characterized by a high dolomite content with the largest pore and throat radii and have a higher pore-throat network connection ratio with higher permeability and better oiliness. Thus, the quality of the Lucaogou tight reservoir is primarily controlled by the dolomite content.

Identification of fractures in tight-oil reservoirs: a case study of the Da'anzhai member in the central Sichuan Basin, SW China

The Da'anzhai Member of the Jurassic Ziliujing formation in central Sichuan is a typical tight-oil reservoir with porosity and permeability less than 2% and 0.1 × 10–3 μm2, respectively. Fractures in this formation are well developed in micro- and nano-scale. However, the factors that control the fracture distribution are unclear. Additionally, the uncomprehensive and ineffective identification and evaluation of fractures in the early stage of tight-oil development makes it difficult to meet the requirements of tight-oil development. In our work, we used cores, thin sections, and a scanning electron microscope (SEM) to study the influence of the microscopic rock composition, including the shelly grains, calcite grains, and clastic grains, on the fracture development. We found that the microscopic composition of shelly grains and calcite grains separately control the development of inter-shelly fractures and shelly fractures, and intergranular fractures, and tectonic fractures. Except for a small number of dissolution fractures found in mudstone, the fractures are not well developed in the formations with clastic grains. According to the characteristics of the development degree of fracture and the resolution of the well-logs, the fractures are divided into large scale, small scale, and micro-scale. By a newly established level-by-level constraints method, we systematically identified the scale, occurrence, filling characteristics, and development degree of fractures in the Da'anzhai member by well-logs. Moreover, a quantitative model is also proposed for identifying the angles and development degree of fractures. The results show that the scale of fractures can be effectively identified by the shapes and values of resistivity logs; the occurrence, development, and filling characteristics of fractures can be semi-quantitatively evaluated by the relative amplitude difference between the matrix resistivity (Rb) and formation resistivity (RT). The results are consistent with the interpretation results by formation micro-resistivity imaging (FMI) log, which further demonstrates that the level-by-level constraint method by conventional well-logs can be used to systematically and effectively predict the fracture characteristics in tight-oil reservoirs.

Ethanol Blending to Improve Reverse Micelle Dispersity in Supercritical CO2: A Molecular Dynamics Study

Despite a great promise in the enhanced oil recovery in tight formations, CO2 flooding with surfactants is hindered due to the low surfactant solubility in supercritical CO2 (scCO2). Alcohol blending can increase the sodium bis(2-ethylhexyl) sulfosuccinate (AOT) solubility in scCO2. While this finding offers a promising solution to CO2 flooding in tight oil reservoirs, to the best of our knowledge, their working mechanism still remains elusive. Herein, we report a molecular dynamics simulation study to explore the working mechanism of alcohols in reverse micelle (RM) dispersity ("solubility") increment. The spontaneous aggregation process in two systems (System A consisting of AOT and scCO2; System B consisting of AOT, scCO2, and 10 wt % ethanol) are conducted under a typical tight oil reservoir condition (333 K and 200 bar). After 600 ns runs, the AOT molecules aggregate together and form rod-like RMs in System A, while form several small sphere-like RMs in System B. We observe that the aggregation process in System A occurs when two clusters approach each other end-to-end. More CO2 molecules are around the Na+ ion at the end of the clusters, which can be readily replaced by AOT molecules. On the other hand, the ethanol molecules can better solvate and surround Na+ ions, preventing the further aggregation of AOT clusters in System B. The potential of mean force calculations also reveal that while two small clusters formed by four AOT molecules attract each other in System A, they repel each other in System B. Our work should provide important insights into the design of scCO2-soluble surfactant formulas.

Novel method for determining the lower producing limits of pore-throat radius and permeability in tight oil reservoirs

Determination of the lower limit of flowing porosity for oil recovery from tight oil reservoirs is the key to promoting scientific and economic development of tight oil reservoirs. This study performed a comprehensive analysis based on pore-throat radius distribution measurements, low-temperature nitrogen adsorption measurements, and centrifugation and nuclear magnetic resonance measurements to establish a method for calculating the bound water film thickness and, in turn, the lower limits of pore-throat radius and permeability. The method was applied on rock samples from typical tight oil reservoirs in the Daqing and Changqing oil regions in China. The results indicated that for a given reservoir, bound water film thickness tends to be constant. With decreasing permeability, bound water film thickness showed an L-shaped distribution curve due to the changes in the pore-throat structure and the impact of molecular forces. The flat segment of the distribution curve corresponded to the lower limit of pore-throat radius, while the curve inflection point corresponded to the lower limit of permeability. The pore-throat radius and permeability limits were 22 nm and 0.08 mD for the Daqing tight oil reservoir and 18 nm and 0.03 mD for the Changqing tight oil reservoir, respectively.

Differential diagenetic evolution and hydrocarbon charging of the tight limestone reservoir of the Da’anzhai Member in the central Sichuan Basin, China

The tight lacustrine carbonate reservoir of the Da’anzhai Member, Lower Jurassic Ziliujing Formation, in the central Sichuan Basin is a typical tight oil reservoir, and it is one of the crucial petroleum exploration targets in the Sichuan Basin. The porosity of the limestone ranges from 0.5% to 2%, and the permeability ranges from 0.001 to 1 mD. The Da’anzhai limestone experienced multiple diageneses, including compaction, cementation, dissolution, and recrystallization. Different diageneses occurred in the burial process due to the various fabrics and depositional environments, eventually forming distinct rock types; therefore, the pore evolution and hydrocarbon charging characteristics are inconsistent. In our research, there are two stages of major maturation and hydrocarbon expulsion in the source rocks of the Da’anzhai Member. The first large-scale expulsion of hydrocarbon is oil-based and gas-supplemented, whereas the second expulsion is dominated by gas. Hydrocarbon-filling characteristics are different in different types of reservoir rocks. Compared with the bioclastic grainstone and crystalline limestone, we have considered that the argillaceous shell packstone and bioclastic packstone deposited in the shallow and semideep lake environment still contain residual intergranular pores, which have not become fully compacted and are partly filled with hydrocarbons. The presence of hydrocarbon fluid hindered the secondary porosity reduction and was helpful for reserve space preservation.

Characteristics of micro- and nano-pores in shale oil reservoirs

Porosity is the most common form of reservoirs, and its size, shape, and connectivity directly affect the capacity of oil and gas storage and production. To study the micro–nano-pore structure characteristics of shale oil reservoirs and quantitatively characterize its heterogeneity, this work uses high-precision high-pressure mercury intrusion (HPMI) experimental techniques to study the micro–nano-pore structure characteristics of shale oil, and based on the experimental data, fractal theory is used to quantitatively characterize its heterogeneity. The results of the study show that the micro–nano-pores in the shale oil reservoir are concentrated and continuous, and the pore radius is mainly distributed among the range of 30–500 nm, nanoscale pores are an important part of the pores of the shale oil reservoir. The fractal dimension of the shale oil reservoir is larger than the fractal dimension of typical tight oil reservoirs, indicating that the heterogeneity of shale oil reservoir is stronger. The research results have some theoretical and practical significance for the production of inter-salt shale oil reservoirs.

OVERALL PSD AND FRACTAL CHARACTERISTICS OF TIGHT OIL RESERVOIRS: A CASE STUDY OF LUCAOGOU FORMATION IN JUNGGAR BASIN, CHINA

Lucaogou tight oil reservoir, located in the Junggar Basin, Northwest of China, is one of the typical tight oil reservoirs. Complex lithology leads to a wide pore size distribution (PSD), ranging from several nanometers to hundreds of micrometers. To better understand PSD and fractal features of Lucaogou tight oil reservoir, the experiment methods including scanning electron microscope (SEM), rate-controlled mercury injection (RMI) and pressure-controlled mercury injection (PMI) were performed on the six samples with different lithology. The results indicate that four types of pores exist in Lucaogou tight oil reservoir, including dissolution pores, clay dominated pores, microfractures and inter-granular pores. A combination of PMI and RMI was proposed to calculate the overall PSD of tight oil reservoirs, the overall pore radius of Lucaogou tight oil reservoir ranges from 3.6[Formula: see text]nm to 500[Formula: see text][Formula: see text]m. The fractal analysis was carried out based on the PMI data. Fractal dimension (Fd) values varied between 2.843 and 2.913 with a mean value of 2.88. Fd increases with a decrease of quartz content and an increase of clay mineral content. Samples from tight oil reservoirs with smaller average pore radius have stronger complexity of pore structure. Fractal dimension shows negative correlations with porosity and permeability. In addition, fractal characteristics of different tight reservoirs were compared and analyzed.

A study of a pressure analysis model for SRV fractured vertical wells in tight oil reservoir

Tight matrix blocks and fractures normally have high stress-sensitivity. In addition, due to the tightness, unsteady cross-flow (UCF) often occurs between matrix and fractures. Those two factors can affect the shapes and characteristics of bottom hole pressure (BHP) and thereby the reliability of well test interpretation. In this study, a physical model of a fractured vertical well with stimulated reservoir volume (SRV) was developed for the purpose of pressure propagation simulation, based on micro-seismic data monitored at SRV fractured vertical wells in different typical tight oil reservoirs. Then a mathematical model was presented to describe BHP of SRV fractured vertical wells by considering stress sensitivity and UCF. Later, the proposed BHP analysis model was applied to a typical SRV fractured vertical well. The results reveal that compared to models without stress sensitivity and UCF, the proposed model can provide more accurate estimates of the inner fractured zone's radius and other relevant reservoir parameters. [Received: March 15, 2017; Accepted: July 17, 2017]

Pore Structure Characterization and the Controlling Factors of the Bakken Formation

The Bakken Formation is a typical tight oil reservoir and oil production formation in the world. Pore structure is one of the key factors that determine the accumulation and production of the hydrocarbon. In order to study the pore structures and main controlling factors of the Bakken Formation, 12 samples were selected from the Bakken Formation and conducted on a set of experiments including X-ray diffraction mineral analysis (XRD), total organic carbon (TOC), vitrinite reflectance (Ro), and low-temperature nitrogen adsorption experiments. Results showed that the average TOC and Ro of Upper and Lower Bakken shale is 10.72 wt% and 0.86%, respectively. The Bakken Formation develops micropores, mesopores, and macropores. However, the Upper and Lower Bakken shale are dominated by micropores, while the Middle Bakken tight reservoir is dominated by mesopores. The total pore volume and specific surface area of the Middle Bakken are significantly higher than those of the Upper and Lower Bakken, indicating that Middle Bakken is more conducive to the storage of oil and gas. Through analysis, the main controlling factors for the pore structure of the Upper and Lower Bakken shale are TOC and maturity, while those for Middle Bakken are clay and quartz contents.

Characterization and Consecutive Prediction of Pore Structures in Tight Oil Reservoirs

The Lucaogou Formation in Jimuaser Sag of Junggar Basin, China is a typical tight oil reservoir with upper and lower sweet spots. However, the pore structure of this formation has not been studied thoroughly due to limited core analysis data. In this paper, the pore structures of the Lucaogou Formation were characterized, and a new method applicable to oil-wet rocks was verified and used to consecutively predict pore structures by nuclear magnetic resonance (NMR) logs. To do so, a set of experiments including X-ray diffraction (XRD), mercury intrusion capillary pressure (MICP), scanning electron microscopy (SEM) and NMR measurements were conducted. First, SEM images showed that pore types are mainly intragranular dissolution, intergranular dissolution, micro fractures and clay pores. Then, capillary pressure curves were divided into three types (I, II and III). The pores associated with type I and III are mainly dissolution and clay pores, respectively. Next, the new method was verified by “as received” and water-saturated condition T2 distributions of two samples. Finally, consecutive prediction in fourteen wells demonstrated that the pores of this formation are dominated by nano-scale pores and the pore structure of the lower sweet spot reservoir is more complicated than that in upper sweet spot reservoir.

Diagenetic controls on the quality of the Middle Permian Lucaogou Formation tight reservoir, southeastern Junggar Basin, northwestern China

The Middle Permian Lucaogou Formation, in the southeastern part of the Junggar Basin in China, is a typical tight oil reservoir with low to medium porosity (average 11.2%) and ultra-low permeability (average 0.01 mD). Here, we investigate Lucaogu Formation reservoir diagenesis and its impact on reservoir quality to effectively explore, appraise, and develop this complex tight oil reservoir. Core and thin section analyses, scanning electron microscopy, X-ray diffraction (XRD), electron probe analyses, fluid inclusions, isotopic analysis, pressure-controlled mercury injection, rate-controlled mercury injection, and micro-nanometer X-ray computer tomography (CT) imaging were performed on core samples from the Lucaogou tight reservoir. The sweet spots in the Lucaogu Formation are composed of siltstone, tuffaceous siltstone, and silty dolomite, which underwent two stages of carbonate cementation (primarily calcite, dolomite, and ankerite), clay mineral alteration and dissolution, and one stage of quartz cementation. The major authigenic mineral cements (derived from the original formation water, clay mineral alteration, dissolution of acid-soluble components, and the compaction and drainage of the interbedded mudstone) are also a probable source of ions. It is likely that oil emplacement occurred after quartz cementation and the first stage of carbonate cementation and feldspar dissolution, but before the second stage of calcite cementation and feldspar dissolution. Organic acids produced during hydrocarbon generation contributed to the dissolution of the feldspar and tuffaceous components, locally preventing a decrease in porosity by concurrent cementation and compaction. Carbonate cementation decreased the porosity and permeability of the silty dolomite substantially; in the siltstone, decreased permeability is largely attributed to cementation of clay minerals. The pore structure of the sweet spot is controlled not only by the various cementation events, but also by other geological factors, such as heterogeneous dissolution of the tuffaceous component.

Diagenetic heterogeneity, pore throats characteristic and their effects on reservoir quality of the Upper Triassic tight sandstones of Yanchang Formation in Ordos Basin, China

Abstract Upper Triassic tight sandstones in Ordos Basin are typical tight oil reservoirs in China. Using a combination of thin sections, SEM, BSE, EDS and mercury injection, 48 sandstone core samples from 17 wells in the study area were collected to investigate the diagenetic heterogeneity, pore-throat characteristics and their correlations with reservoir quality. Five diagenetic types were identified according to their specific diagenetic evolution pathways. Type A sandstones are characterized by abundant authigenic chlorite rims, rare quartz cement and high porosity. Type B sandstones underwent moderate compaction, moderate dissolution and moderate cementation. Samples from Type C are characterized by intense dissolution and large amounts of carbonate cements, they can be subdivided into two categories according to if pore throats in larger size were still reserved (Type C2) or not (Type C1) after late-stage cementation. Type D sandstones underwent intense compaction, moderate dissolution and minor carbonate cementation. Type E sandstones are characterized by the most intense compaction. Depending on the pore-throat size distributions from MICP analysis, three sandstone types with their own specific pore-throat characteristics were identified. Type Ⅰ sandstones generally contain a certain amount of mesopores (including a few macropores) and pore spaces are dominant intergranular pores, intragranular pores and even oversized pores. These sandstones generally correspond to Type A, B, C2 and D sandstones and thus represent good-quality reservoir. Type Ⅱ sandstones usually contain dominant transitional pores (77% in average) and their pore systems mianly consist of clay intercrystal microporosity and a few isolated intergranular or intragranular pores. Type Ⅲ sandstones are representative by relatively abundant micropores (17.7% in average) and pore spaces are dominant clay intercrystal microporosity. Type Ⅱ and Type Ⅲ pore structures generally correspond to Type C1 and E and thus represent poor-quality reservoir. This study gives insights into the link between different diagenetic features, pore structures and their impact on reservoir quality and this will be helpful for reservoir prediction.

Boundary retention layer influence on permeability of tight reservoir

The permeability of typical tight oil reservoir cores is measured using difference fluid medium (nitrogen, formation water, kerosene), and a capillary permeability model considering boundary retention layers is build. The computed values of the model are compared with experimental values of cores. The difference of permeability using different fluid medium is discussed concerning boundary retention layer thickness, movable fluid pore space and clay contents. The experiment results showed that targeted reservoir cores klinkenberg permeability K∞ was 66.86% of conventional gas permeability Kg, and water permeability KW was 11.66% of Kg, and oil permeability KO was 2.46% of Kg. KW and KO could characterize reservoir water injection and development difficulty better than Kg. Kh/K (ratio between permeability of capillary model considering and not considering boundary retention layer), is perfectly consistent with K∞/Kg, which indicates that capillary permeability model considering boundary retention layer has good consistency with seepage characteristics of actual reservoir. The tight cores have smaller effective pore-throat space for flowing, and get larger effect of boundary retention layers. The smaller the permeability core have, the closer between Kh/K and K∞/Kg. Boundary layer thickness are increased by Clay swelling, and flow channel are blocked by clay off and migration, that the main reason of KW smaller than K∞. The lower Kg cores have, the more KW/K∞ decrease magnitude. KO is much lower than K∞ and KW because of increased oil seepage resistance by two-phase seepage and boundary retention layer.

Impact of sequence stratigraphy, depositional facies, diagenesis and CO2 charge on reservoir quality of the lower cretaceous Quantou Formation, Southern Songliao Basin, China

Abstract The fourth member of the Lower Cretaceous Quantou Formation in Southern Fuxin Uplift zone of the Southern Songliao Basin is typical tight oil reservoir which has recently been explored and produced. For effective exploration and development, the evaluation and control factors of the reservoir quality of the K1q4 sandstones should be thoroughly studied. The study focused on the control of the combination of sequence stratigraphy, depositional facies and diagenesis on the reservoir quality, and identified the impact of CO2 charging, based on the core and thin section observation, XRD, SEM, fluid inclusion and isotope testing and analysis. The fourth member of the Lower Cretaceous Quantou Formation consists of lowstand system tracts (LST), transgressive system tracts (TST) and highstand system tracts (HST). The K1q4 sandstones were mostly deposited in distributary channels and crevasse splays of a delta plain within the LST and TST, and underwater distributary channels and sheet sands of a delta front within the HST. The K1q4 sandstones, mostly silt to medium grained, medium to well sorted, and are mostly lithic arkoses and feldspathic litharenites, have undergone significantly diagenetic alterations, such as compaction, quartz cementation, unstable grains (feldspar and volcanic fragments) dissolution, carbonate cementation and clay minerals cementation. The reservoir quality of the K1q4 sandstones are poor with low porosity and permeability, showing variations among the different system tracts and depositional facies, and are influenced by the charging of CO2 and controlled by the combination of sequence stratigraphy, depositional facies and diagenesis. The sandstones with high reservoir quality are mostly deposited in high energy environments, including the (underwater) distributary channel sandstones, especially the LST distributary channel sandstones with the best reservoir quality among the LST, TST and HST sandstones, which can be ascribed to larger grain size and better sorting resulting in larger intergranular pore space after compaction, and less content of carbonate cements, illite and mixed-layer I/S, and more pore-lining chlorite and more effectively dissolution. The poor reservoir quality of sandstones from crevasse splay and sheet sand is due to the small grain size and bad sorting which resulted in extensive compaction and the resulting weak dissolution. The charging of CO2 has dual impact on the reservoir quality of the K1q4 sandstones. The CO2 charging can induce the dissolution of unstable detrital grains and the precipitation of dawsonite. The former create new secondary pore space, while the latter occupy the intergranular pore space. The CO2 charging is harmful to the reservoir quality when the dawsonite content exceeds a threshold of 5%.

Well test mathematical model for fractures network in tight oil reservoirs

Well test, especially build-up test, has been applied widely in the development of tight oil reservoirs, since it is the only available low cost way to directly quantify flow ability and formation heterogeneity parameters. However, because of the fractures network near wellbore, generated from artificial fracturing linking up natural factures, traditional infinite and finite conductivity fracture models usually result in significantly deviation in field application. In this work, considering the random distribution of natural fractures, physical model of fractures network is proposed, and it shows a composite model feature in the large scale. Consequently, a nonhomogeneous composite mathematical model is established with threshold pressure gradient. To solve this model semi-analytically, we proposed a solution approach including Laplace transform and virtual argument Bessel function, and this method is verified by comparing with existing analytical solution. The matching data of typical type curves generated from semi-analytical solution indicates that the proposed physical and mathematical model can describe the type curves characteristic in typical tight oil reservoirs, which have up warping in late-term rather than parallel lines with slope 1/2 or 1/4. It means the composite model could be used into pressure interpretation of artificial fracturing wells in tight oil reservoir.