Unconventional 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.

Diagenetic impact on unconventional tight carbonate reservoir of AR-F Member from the Abu Gharadig Field, north Western Desert, Egypt: insights from integrated combined sedimentological, petrographic, and petrophysical dataset

Diagenetic impact on unconventional tight carbonate reservoir of AR-F Member from the Abu Gharadig Field, north Western Desert, Egypt: insights from integrated combined sedimentological, petrographic, and petrophysical dataset

Geological characteristics of unconventional tight oil reservoir (109 t): A case study of Upper Cretaceous Qingshankou Formation, northern Songliao Basin, NE China

The Daqing exploration area in the northern Songliao Basin has great potential for unconventional oil and gas resources, among which the total resources of tight oil alone exceed 109 t and is regarded as an important resource base of Daqing oilfield. After years of exploration in the Qijia area, Songliao Basin, NE China, tight oil has been found in the Upper Cretaceous Qingshankou Formation. To work out tight oil’s geological characteristics, taking tight oil in Gaotaizi oil layers of the Upper Cretaceous Qingshankou Formation in northern Songliao Basin as an example, this paper systematically analyzed the geological characteristics of unconventional tight oil in Gao3 and Gao4 layers of the Qijia area, based on the data of the geological survey, well drilling journey, well logging, and test. It is that three sets of hydrocarbon source rocks (K2qn1, K2qn2+3, and K2n1) develop in the examined area, and exhibit excellent type I and II kerogens, high organic matter abundance, and moderate maturity. The reservoir is generally composed of thin-bedded mudstone, siltstone, and sandstone, and presents poor porosity (average 8.5 vol.%) and air permeability (average 4 mD). The main reservoir space primarily includes intergranular pores, secondary soluble pores, and intergranular soluble pores. Three types of orifice throats were identified, namely fine throat, extra-fine throat, and micro-fine throat. The siltstone is generally oil-bearing, the reservoirs with slime and calcium become worse oil-bearing, and the mudstone has no obvious oil-bearing characteristics. The brittleness indices of the sandstone in the tight oil reservoir range from 40% to 60%, and those of the mudstone range from 40% to 45%, indicating a better brittleness of the tight oil reservoir. Based on the study of typical core hole data, this paper gives a comprehensive evaluation of the properties of the tight oil and establishes a tight oil single well composite bar chart as well as the initial evaluation system with the core of properties in the tight oil reservoir. This study has theoretical guiding significance and practical application value for tight oil exploration and evaluation in the Qijia area.©2024 China Geology Editorial Office.

Research on key technology of packer rubber barrel for integrated fracturing and completion of gas well

The staged and layered fracturing technology plays an important role in unconventional tight reservoirs. And the gas well fracturing and completion integration is the core component to realize the fracturing and completion integration process, which can realize the integration of acid fracturing and later drainage production so as to reduce the secondary pollution to the reservoir. The packer rubber barrel’s performance directly affects the long-term effective sealing reliability itself in high temperature and high pressure environment. In this paper, the constitutive model of rubber tested from high temperature and high pressure curing kettle to simulate the high-temperature and highly corrosive environment of the formation. On this basis, the structure of the packer’s shoulder and the protective ring of the rubber barrels are optimized through Abaqus to reduce its stress failure under high pressure, and its corrosion resistance is improved by improving the rubber material. The sealing performance of the packer rubber cylinder under the field underground requirements is tested through laboratory evaluation test and field test. The results show that the protective ring and rubber tube shoulder at 30° angle are a reasonable result of optimization, and the optimized packer can meet the requirements of 154 °C temperature resistance, 79 MPa pressure bearing and long-term effective sealing. The successful development of packer rubber and the integrated analysis process can lay a solid foundation for the realization of integrated fracturing and completion process for exploration and development of deep volcanic or carbonate reservoirs.

Evaluation of Flow Units and Capillary Pressures of the Giant Chicontepec Tight Oil Paleochannel in Mexico and a Fresh Look at Drilling and Completions

Summary The Chicontepec Paleochannel in Mexico is a giant shaly sandstone reservoir with volumes of original oil in place (OOIP) ranging between 137 and 59 billion STB (Guzmán 2022). However, the oil recoveries are very small, ranging between 0.32% and 0.75% of the OOIP. Under these conditions, consistent interpretation of flow units and mercury injection capillary pressures up to 55,000 psi provide useful information that helps in deciphering the rock quality and pore sizes at levels that might not be reached by thin-section petrography. This is important because the Chicontepec Paleochannel (Misantla-Tampico Basin) has been recently equated to the Permian Basin in the United States and has been termed by Guzman (2022) “a premier super basin in waiting.” The current cumulative oil production of Chicontepec is 440 million STB. Although it is a significant volume, it represents a very small percentage of recovery from the reservoir (0.32–0.75% of the OOIP). To help improve recovery, a method is developed for characterizing the tight Chicontepec Paleochannel using flow units and capillary pressures. Like in the case of many tight unconventional reservoirs, the capillary pressures can go to very high values, reaching 55,000 psi in the Chicontepec case. Therefore, a special procedure is developed to generate a consistent interpretation of all the available capillary pressure curves for the entire range of pressures. The results highlight the important oil recovery potential. The assessment is supported by quantitative formation evaluation work performed by Gutierrez Oseguera and Aguilera (2023). Although natural fractures are present, most wells must be hydraulically fractured to achieve commercial success. Process or delivery speed (the ratio of permeability and porosity) for the Chicontepec samples used in the capillary pressure experimental work range between 159.1 md and 0.17 md (porosity in the denominator is a fraction). Flow units show pore throat radii (rp35) range from less than 0.1 µm to about 4.5 µm. These values and flow units compare well with data available for prolific unconventional reservoirs such as the Cardium sandstone in Canada and the giant Permian Basin in the United States. The radius rp35 refers to the pore throat radius at 35% cumulative pore volume (PV) of injected mercury. This is different from rp also discussed in this paper, which is the pore throat radius at any water saturation (for example, at 40% water saturation). Thus, in the case where water saturation is 65%, rp is equal to rp35. The novelty of this study is the development of a consistent procedure for interpreting the entire range of pressures measured during mercury injection capillary pressures. Such pressures go up to 55,000 psi for the core samples considered in this study. The integration with flow units and formation evaluation suggests that the potential of the Chicontepec unconventional reservoirs can rival successful results obtained in the Cardium sandstone and the Permian Basin. The key ideas discussed in this paper for improving Chicontepec oil recovery include specialized petrophysical evaluation, determination of flow units and capillary pressures, improved drilling and completion methods, and geological support.

Promising combination of CO2 enhanced oil recovery and CO2 sequestration in calcite nanoslits: Insights from molecular dynamics simulations

CO2-Enhanced recovery has attracted extensive attention, meanwhile reducing greenhouse gas emissions via CO2 geological sequestration is causing global concern in recent years, combining CO2-EOR and CO2 sequestration has been recognized as one of the CCUS approach with high potential, and tight reservoirs such as shale oil are the most promising resource in this respect, which has become one of the hot topics unsurprisingly. The understanding about the microscopic molecular behaviors and interaction mechanisms between CO2, shale oil, and reservoirs is critical for the development of the techniques, while still incomplete, which makes it challenging for efficient large-scale application in the world. In this paper, molecular dynamics (MD) simulations are used to investigate the displacement and miscible behaviors of CO2/octane in calcite nanoslits under reservoir conditions, the effects of temperature, pressure and slit apertures on the molecular behaviors have been studied comprehensively. The interaction energy between CO2 and octane molecules and calcite surface were calculated to quantitatively analyze the mechanisms in the process of CO2 flooding. The significant strong interactions between calcite surface and CO2 on one hand benefit the displacement of octane by CO2 increasing the miscible flooding efficiency, on the other hand ensure the high adsorption capacity of CO2 inside the calcite nanoslits, thereby plenty of CO2 can be stored inside the calcite nanoslits after the flooding. It could be concluded that the carbonate reservoir could be the most promising field combining CO2-EOR and CO2 sequestration. This work provides theoretical guidance for both the optimization of the CO2-enhanced oil recovery and effective CO2 sequestration in unconventional tight reservoirs, especially carbonate reservoir.

Long-term production forecast in tight and shale reservoirs: Adapting probability density functions for decline curve analysis

Decline curve analysis (DCA) is a popular method for predicting the production of oil and gas wells over time. It involves using historical data to match a mathematical function with the production data, which can then be used to forecast future production. However, DCA in unconventional tight and shale reservoirs poses unique challenges. Unlike conventional reservoirs, these unconventional reservoirs exhibit a production decline that is both faster and more erratic. This behavior, combined with the inherent complexities of the reservoir properties and fluid flow mechanisms, makes it challenging for traditional DCA models to provide accurate predictions of future production.This study proposes a new approach for forecasting long-term production in tight and shale reservoirs, using probability density functions (PDFs) that have been adapted and evaluated for this purpose. The PDF-based DCA models were tested against traditional DCA models using data from over 80 wells in different unconventional basins across North America.Results show that the PDF-based models outperformed the traditional models, with the Dagum and Beta prime models achieving the highest performance scores on various statistical measures, especially in wells with limited production history for model training. To ensure accuracy, appropriate statistical tests should be used to validate the PDF-based decline curve analysis, such as calculating the mean absolute error (MAE) or other relevant metrics.Our research introduces a novel method of adapting PDFs for decline curve analysis, specifically tailored for tight and shale reservoirs. This adaptation offers a more accurate and comprehensive prediction of future production by effectively capturing the inherent uncertainty and variability seen in unconventional reservoirs. One of the standout features of our proposed PDF-based approach is its versatility. Unlike traditional models that may struggle with erratic data, our models can seamlessly fit production data, whether it possesses peaks or not. This approach could be valuable for producers and investors who want to make informed decisions about drilling and production in unconventional reservoirs.

The non-plane initiation and propagation mechanism of multiple hydraulic fractures in tight reservoirs considering stress shadow effects

Multi-cluster fracturing in horizontal wells is an important stimulation technology for unconventional tight reservoirs. The interference among multiple simultaneously growing hydraulic fractures results in a non-uniform fluid distribution into fractures and non-planar fracture geometries. In this paper, the competition mechanism between perforations under the stress shadow, the formation mechanism of complex non-plane fractures near the wellbore, and the initiation and propagation mechanism of multiple hydraulic fractures are investigated by using the 3D lattice method. Also, the effects of fracture geometry, fracture spacing and rock mechanics parameters on the stress interaction among fractures are analyzed by the dislocation theory. The results showed the complexity of fracture initiation near the wellbore and the low efficiency of the perforation initiation in the case of spiral perforation, due to a strong interaction between perforations. However, these initial micro-cracks will eventually coalesce to be a macroscopical fracture which perpendicular to the direction of minimum principal stress. The study indicated that stress interaction and fracture propagation is significantly affected by inclined well orientation. The hydraulic fracture is more likely to deflect and propagate non-uniformly with the increasing width of hydraulic fracture, the decreasing spacing between perforation clusters and the increasing rock modulus. When the horizontal principal stress difference is small, it is obvious to cause a large deflection angle and sometimes furcation of fractures. This study can provide a theoretical basis and technical guidance for hydraulic fracturing design in tight reservoirs.

Study on Oil Composition Variation and Its Influencing Factors during CO2 Huff-n-Puff in Tight Oil Reservoirs

With immense potential to enhance oil recovery, CO2 has been extensively used in the exploitation of unconventional tight oil reservoirs. Significant variations are observed to occur in the oil’s composition as well as in its physical properties after interacting with CO2. To explore the impacts of oil properties on CO2 extraction efficiency, two different types of crude oil (light oil and heavy oil) are used in CO2 huff-n-puff experiments. Moreover, numerical simulation is implemented to quantitatively inspect the impacts of different influencing factors including production time, reservoir pressure and reservoir temperature on physical properties as well as on the oil composition variation of the crude oil. The findings of the experiments demonstrate that, whether for the light oil sample or for the heavy oil sample, hydrocarbon distribution becomes lighter after interacting with CO2 compared with the original state. In addition, it is also discovered that the hydrocarbon distribution variation is more significant for the light oil sample. The findings of the numerical simulation suggest that production time, reservoir pressure and reservoir temperature have significant impacts on the produced oil composition and properties. The hydrocarbon distribution of the oil becomes lighter with the increasing of production time and formation pressure, while it becomes heavier with the increasing of reservoir temperature. At the very beginning of the oil production, the properties of the produced oil are worsened. Compared with the original state, the oil density and viscosity are 25.7% and 200% higher, respectively. It is suggested that viscosity reducers are added into the well to improve the oil properties in this period. With the continuing of the oil production, the oil properties are continuously promoted. At the end of the simulation time, the oil density and viscosity are 3.5% and 15.1% lower compared with the original oil, respectively. This paper has great significance for the implementation of CO2 huff-n-puff in tight oil reservoirs.

Research on Microscopic Pore Structure Characteristics and Producibility of the Chang 9 Reservoir in the Wucangpu Block

The pore structure can affect the storage and flow properties of rock, which is an important research content in the study of unconventional tight reservoirs. This research hopes to clarify the reservoir characteristics and fluid seepage mechanism of the Chang 9 reservoir in the Wucangpu block and provide technical support for the development of horizontal wells with staged fracturing in this block. In this paper, the microscopic pore structure characteristics and producibility of the reservoir in the study area are analyzed in detail by means of constant-rate mercury intrusion and nuclear magnetic resonance. The research results show that the reservoir with permeability less than 0.076 mD is mainly composed of microthroat, the reservoir with permeability of 0.208-0.633 mD has a larger proportion of microthin throat, and the reservoir with permeability of 2.722-3.998 mD has a larger proportion of fine-middle throats. The results show that the oil/gas in the rock sample reservoirs with permeability greater than 1.0 mD is easy to produce.

Investigating the effect of preformed particle gel on conformance control of naturally fractured tight sandstone reservoirs: An experimental study using pressure transfer test method

The recovery of oil and gas resources is limited by the high water production from wells in unconventional reservoirs. While water intrusion prevention measures have been extensively investigated in highly permeable reservoirs, there has been limited research in tight unconventional reservoirs. In this study, a Pressure Transfer Test (PTT) method was used to evaluate the effect of preformed particle gel (PPG) on the conformance control of naturally fractured tight sandstone reservoirs. The study analyzed and compared four types of naturally fractured cores, and performed experiments on the PPG plugging effect under different natural fracture types, injection pressures, and salinities using a PTT device. The results showed that among the four fracture types, vertical and oblique penetrations had the highest plugging effect, with a 12% higher rate than fractures without effective channels. The injection pressure also had a significant impact on the plugging efficiency, with a 99.13% blocking rate at 12.5 MPa, which was almost completely plugged. Meanwhile, the salinity of the injected fluid had a decreasing effect on the PPG plugging efficiency, with the lower salinity of 1 wt% improving the plugging efficiency by 15% compared to high salinity. The experimental results and analysis were used to propose the plugging mechanism of PPG in different types of naturally fractured tight reservoirs. This study provides valuable experimental and theoretical references for the field application and further studies of PPG in naturally fractured tight reservoirs.

A novel production data analysis method for multi-fractured horizontal wells with infill well-caused fracture interference

Tightening the well spacing for unconventional tight reservoirs is an efficient technique to enhance oil and gas recoveries. Infill well-caused fracture connection between wells is widely reported in the field with small well spacing. This will make it difficult to make formation evaluation and fracture characterization between wells compared to single well cases. In this paper, a novel production data analysis (PDA) method is proposed for fracture characterization with the consideration of interwell fracture connections after the hydraulic fracturing of the infill. The PDA method is based on a semianalytical model, in which the small-scaled fractures are treated with the concept of stimulated reservoir volume (SRV). Thus, the fracture connections between wells are classified into three types, including SRV, fractures, and both SRV and fractures. The physical model is discretized into several linear flow regions, so the mathematical model can be solved semianalytically. An integrated workflow is proposed to analyze the production data for the wellpad, and three steps are mainly included in the workflow, including PDA for the parent well before infill, PDA for the parent well after infill, and PDA for the infill well. In each step, the production performance in the early linear and bilinear flow regimes are analyzed with approximate solutions in the square and fourth root-of-time plots. Because only the relationship between unknown model parameters can be obtained with the approximate solutions, history matching to the production data in log-log plots is further used to determine each unknown parameter. The PDA method is benchmarked with a synthetic case generated by the numerical simulator tNavigator and a field case from Southwestern China. The results show that both good matches and precise parameters can be obtained with the proposed PDA method. The connected fracture number will not be sensitive in PDA when the wells are connected with high-conductive dSRV. The innovation of this paper is that a practical method is provided for PDA analysis of well groups with fracture connection, and it will be a good technique for fracture characterization and well-interference analysis for tight formations.

A Method for Determination of Rock Fabric Number from Well Logs in Unconventional Tight Oil Carbonates

Summary This paper develops a method for estimation of rock fabric number (RFN) from well logs in unconventional tight oil carbonates with permeability less than 0.1 md. The objective is to investigate the oil potential of a Middle Cretaceous tight carbonate in Mexico. The development of a method for these conditions is challenging as the current approach developed by Lucia (1983) has been explained for carbonates with permeability more than 0.1 md. Core data and drill cuttings available for this study are limited but provide important insights for the log interpretation and for identifying the presence of grainstone, packstone, and wackstone rocks in the unconventional tight carbonate under consideration. A crossplot of RFN vs. rp35 (pore throat radius at 35% cumulative pore volume) permits delimiting intervals with good production potential that are supported by well testing data. Information for the analysis of the Mexican carbonate comes from well logs of nine wells and two re-entry wells, four buildup tests, and a limited amount of core and drill cuttings information. All data were provided by a petroleum company and have been used, for transparency, without any modifications. An unconventional tight carbonate as defined in this paper has a permeability smaller than 0.1 md. The unconventional tight oil carbonate reservoir considered in this study includes 95% of data with permeabilities smaller than 0.1 md and only 5% with permeabilities larger than 0.1 md. The method introduced by Lucia (1983) and Jennings and Lucia (2003) for determining RFN is powerful, but they explained it only for permeabilities larger than 0.1 md, thus the need for a methodology that allows estimating from well logs the presence of grainstone, packstone, and/or wackstone in unconventional tight carbonate reservoirs with permeabilities smaller than 0.1 md. Results indicate that the RFN provides a useful approach for distinguishing grainstone, packstone, and wackstone rocks in unconventional tight carbonate reservoirs. Furthermore, rock fabric can be linked with Pickett plots to provide an integrated quantitative evaluation of RFN, porosity, water saturation, permeability, pore throat radius, and capillary pressure. This integration indicates that there is good oil potential in the Middle Cretaceous unconventional tight carbonate in Mexico.

IN-DEPTH ANALYSES OF POSTHYDRAULIC FRACTURING PROCESSES IN UNCONVENTIONAL TIGHT RESERVOIRS

Hydraulic fracturing is the most widely used approach for unconventional tight or shale oil production. An appropriate postfracturing process usually refers to a certain shut-in period, which could be of critical importance to enhance ultimate oil recoveries. The shut-in period comprises processes of fluid filtration and spontaneous imbibition. In this study, the pressure decay characteristics during the fluid filtration process after hydraulic fracturing were studied. First, a pore-scale imbibition model with forced pressure was constructed on the basis of capillary model and fractal theory. Then, in addition to the theoretical model, coreflooding tests were performed in the core samples for optimizing the injection pressure difference with the assistance of low-field nuclear magnetic resonance (LF-NMR). Furthermore, the fluid filtration process was modeled and evaluated through another coreflooding test, which was conducted with declining injection pressure. It was found from the theoretical model and experiments that the synergistic effect of the displacement and capillary pressure was maximized for improving oil recovery with an optimized pressure difference of 5 MPa. Moreover, the pressure decay process was divided into fast-declining, transitional, and steady periods. The lab-scale shut-in time was determined to be 30 hours, which was exactly the time when the pressure decay reached the stable stage. This study will support the foundation of more general applications pertaining to hydraulic fracturing, especially fluid filtration processes in unconventional tight or shale oil reservoirs.

考虑压裂液渗吸的压后压裂液返排的数值模拟

Fracturing fluid flowback is a key step in the process of hydraulic fracturing, and the imbibition of fracturing fluid in unconventional tight reservoirs cannot be ignored. Based on the oil-water two-phase seepage theory, Bernoulli equation and the continuity equation, we establish a numerical simulation model of post-fracturing flowback by considering the effect of fracturing fluid imbibition and obtain the pressure and flowback rate during the flowback process through programmed numerical calculation. The critical flow rate of fracturing fluid when the proppant starts to reflux is calculated according to the proppant backflow model. Then an optimization design method of flowback working system is formed based on the principle of controlling proppant backflow and rapid fluid flowback. The numerical simulation results are compared with the actual flowback data of LX3 well, and the flowback working strategy of M87 well is designed, and the effects of formation fluid viscosity and initial formation pressure on fracturing fluid flowback are analyzed. The results show that a phenomenon of formation fluid seepage to fractures is observed during the flowback, and the change of original formation pressure has a significant impact on fracturing fluid flowback, but the formation produced fluid has minor effects. The numerical results of flowrate and wellhead pressure of LX3 well are consistent with the field monitor data, with average errors of 13.8% and 15.5% respectively. It is verified that the flowback numerical model has high accuracy and can be used to guide the on-site fracturing flowback construction design in oilfield.

Exploring hydraulic fracture behavior in glutenite formation with strong heterogeneity and variable lithology based on DEM simulation

Glutenite is an important unconventional tight oil and gas reservoir. Due to the glutenite formation with strong heterogeneity and variable lithology which contains a large number of gravels with different sizes, shapes and mineral compositions, the mechanical characteristics of glutenite are more complicated, resulting in more complex fracture morphology. In this paper, a mathematical method for the generation of irregular polygonal gravels is proposed, and the hydraulic fracturing model of glutenite with different gravel characteristics is established based on 2D particle discrete element method. The internal mechanical mechanism of interaction between hydraulic fractures and gravels is first revealed, and the results show that the interaction is mainly affected by the non-uniformly distributed stress field caused by the coordination of deformation of glutenite. The influence of geologic and engineering factors on hydraulic fracture propagation in glutenite is studied. The results show that fracture morpgology in glutenite is mainly affected by injection rate, fracturing fluid viscosity, gravel strength and gravel spatial distribution. High gravel size, low gravel strength, high stress difference, high injection rate and high fracturing fluid viscosity are conducive to the occurrence of gravel penetration. The micro-mechanism of interaction between hydraulic fractures and gravels is mainly affected by the non-uniformly distributed stress field caused by the coordination of deformation of glutenite. This study can provide key technical support and theoretical guidance for oil and gas development in tight glutenite reservoir.

Unsupervised machine learning technique for classifying production zones in unconventional reservoirs

Significant amounts of information are rapidly increasing in bulk as a consequence of the rapid development of unconventional tight reservoirs. The geomechanical and petrophysical characteristics of the wellbore rocks influence the sweet and non-sweet areas of tight unconventional reservoirs. Using standard approaches, such as data from cores and commercial software, it is difficult and costly to locate productive zones. Furthermore, it is difficult to apply these techniques to wells that do not have cores. This study presents a less costly way for the systematic and objective detection of productive and non-productive zones via well-log data using clustering unsupervised and supervised machine learning algorithms. The method of cluster analysis has been used in order to classify the productive and non-productive reservoir rock groups in the tight reservoir. This was accomplished by assessing the variability of the reservoir characteristics data that are forecasted by looking at the dimensions of the well logs. The Support vector machine as a supervised machine learning algorithm is then used to evaluate the classification accuracy of the unsupervised algorithms based on the clustering labels. The application made use of approximately ten different variables of rock characteristics including zonal depth, effective porosity, permeability, shale volume, water saturation, total organic carbon, young's modulus, Poisson's ratio, brittleness index, and pore size. The findings show that both clustering techniques identified the sweet areas with high accuracy and were less time-consuming.

Linking biomarkers with elemental geochemistry to reveal controls on organic richness in Devonian-Mississippian mudrocks of Oklahoma

Paleoproductivity and depositional redox conditions play critical roles in the development of organic-rich mudrocks. Devonian and Mississippian mudrocks within the central region of Oklahoma, USA were assessed for their depositional redox conditions, paleoproductivity and the effects of these factors on organic matter enrichment using a combination of elemental and organic geochemical proxies.A number of lithofacies with a shallowing upward trend have been defined within Devonian and Mississippian formations. Kerogens in the examined samples are dominantly type II, with organic richness in Mississippian samples exhibiting cyclic fluctuations, whereas organic richness in Woodford samples exhibits a downward-increasing trend. Mississippian sections contained at least three beds of organic-rich mudrocks, with total organic carbon (TOC) ranging from 2 to 6% by weight, indicating good petroleum generation potential. Elemental redox proxies, along with biomarker proxies of photic-zone euxinia, show a strong anoxic signature within the middle Woodford member, while the Mississippian section exhibits signatures consistent with suboxic depositional conditions. Paleoproductivity in the Mississippian section suggests a cyclic trend, with a higher paleoproductivity signature than that preserved in the Woodford Shale. Examined geochemical parameters highlight the different processes that are critical for organic matter enrichment and preservation. Mississippian mudrock organics appear to be enriched because of variations in paleoproductivity, while Woodford Shale organics are likely preserved due to changes in environmental redox conditions. Our findings reflect the variability observed within unconventional tight reservoirs of liquid hydrocarbons and the utility of combining organic and inorganic geochemical approaches in identifying productive sweet spots.

Characteristics and Formation Mechanism of Multiscale Storage Spaces in Ancient Deep Tight Reservoirs: Examples from the Cambrian Yurtus Formation in the Northern Tarim Basin, China

AbstractUnder the background of complicated diagenetic fluids, high-temperature pressure in superimposed basin, the pore-forming and pore-preserving effects of deep tight reservoirs are complex, and the formation mechanism of high-quality reservoirs has always been the core issue. With the discovery of oil and gas in ultradeep drilling in Tarim Basin, the most unconventional tight reservoir of Lower Cambrian Yuertus Formation in Tabei area began to receive attention. Based on the research of typical field outcrops in Tabei area, the lithofacies, reservoir space differences, and reservoir formation mechanism are systematically analyzed. (1) The stratum has undergone complex multistage diagenetic fluid transformation, and the rock types are diverse with great differences; siliceous rock and dolomite are the main rock types, often in thin-medium layered distribution. (2) After long-term deep burial transformation, siliceous rock and dolomite can still retain a large number of effective storage spaces; hydrothermal dissolution pores, organic acid dissolution pores, atmospheric freshwater dissolution pores, and intercrystalline pores are the main pore types, which provide main storage spaces. Multiscale pores are developed in siliceous rock and dolomite, with good connectivity and good pore structure. (3) The large-scale storage spaces mainly come from the effective maintenance of primary pores, organic matter, and hydrothermal dissolution. The siliceous minerals and dolomite have stable properties and strong resistance to compaction and can effectively maintain the early pores. (4) The large-scale reservoir space was formed in the early diagenetic stage; the pressure-solution and cementation are the two most important diagenetic processes for reducing storage spaces; however, under the pore-forming and pore-preserving effects of early silicification and dolomitization, various types of dissolution, and oil charging, the tight lithology can still maintain effective storage spaces. The related research has important theoretical and practical significance for studying the formation mechanism of tight reservoirs in deep ancient strata and predicting high-quality reservoirs.

Geochemical, mineralogical and petrographical characteristics of the domanik formation from north samara region in the volga-ural basin, Russia: Implication for unconventional tight oil reservoir potential

This paper comprehensively analyzes the geochemical, mineralogical and petrographical properties combined with bulk kinetics modeling of the Domanik organic-rich carbonate from various depth intervals in Kuzminovsky oilfield (well № 26 R), Volga-Ural Basin, Russia. The results show that, the Domanik carbonate-rich samples are characterized by high content of the total organic matter (TOC) up to 13.31 wt %, and contain mainly Type II kerogen with a slight II/III kerogen type, reaching very good to excellent oil generation potential. Moreover, the studied samples contain hydrogen-rich kerogen, which expected to generate paraffin, naphthene and aromatic (P–N-A) oil with low wax content as demonstrated by the Py-GC Pyrolysis combined with the abundance of fluorescent alginite, amorphous organic matter, and bituminite as established from investigations via microscope. The maturity indicators demonstrated that, most of the examined Domanik carbonate-rich samples, with a burial depth between 1726.5 m and 1784.9 m, have generally reached low thermal maturity stages; thus, defining an immature to moderate-mature of oil generation window. The results of the kinetic models suggested that, Domanik carbonate-rich rocks with vitrinite reflectance (VRo) values in the range of 0.60–0.71%, have reached relatively low kerogen transformation ratio in the range of 10–20%, indicating low probability oil generation. These finding are confirmed by the presence of low oil saturation index of less than 100 mg HC/g rock (19.64–69.97). In addition, the results of thin section, scanning electron microscopy (SEM) and micro-computed tomography (micro-CT) showed that the studied samples are characterized by low porosity (up to 3.29%) with a wide pores size range, including interparticle, cavities, cracks and organic matter pores. The development of these pore types and their quality in the studied samples is mainly controlled by high mineralogical brittleness (i.e., carbonate and quartz) together with the high organic matter inputs. Therefore, according to the obtained results, characteristics and observations, the Domanik Formation has a high potential for commercial oil production, which typically requires hydraulic fracturing followed by an in-situ retort, mainly by thermal methods such as steam injection and in situ combustion process.