Low Reservoir Research Articles

Study on CO2 Injection Enhanced Oil Recovery Method and Buried Mechanism in Low Permeability Gas Reservoir

Study on CO2 Injection Enhanced Oil Recovery Method and Buried Mechanism in Low Permeability Gas Reservoir

Data Science Enables Management of Stealth Asphaltene Flow-Assurance Risk

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216216, “Managing Stealth Asphaltene Flow-Assurance Potential Risk in Gas-Injection Field Based on Data Science Using Over 20-Year Accumulated Data Set,” by Hideharu Yonebayashi, SPE, and Takeshi Hiraiwa, SPE, Japan Oil Development, and Khuloud T. Al Khlaifi, SPE, ADNOC, et al. The paper has not been peer reviewed. _ Gas injection is recognized generally not only to improve oil recovery but also to increase the risk of asphaltene destabilization. The recent discovery of asphaltene deposits in a subject field motivated the operator to launch an immediate investigation to evaluate what critical risks might exist and consider appropriate mitigation. It was found that precipitated but invisible asphaltenes still can be flowable. This stealth asphaltene behavior could explain a possible mechanism of the first asphaltene observation in the upper reservoir. Introduction The subject giant offshore field in the Arabian Gulf has not experienced asphaltene-induced production deterioration during long-term lean hydrocarbon gas injection. The gas has been injected into the crestal area of two reservoirs (upper and lower) with peripheral powered seawater injection. Both reservoir fluids contain a small amount of asphaltenes (0.1–1.5 wt%) distributed at higher concentration at deeper locations. In May 2022, the first discovery of asphaltene deposits from the historical no-issued area in the upper reservoir motivated an immediate investigation for risk assessment and mitigation. A resulting study captured stealth asphaltenes, which were detected by a laser-light-scattering technique while high-pressure microscopy detected no visible asphaltene solid particles. Historical Asphaltene Data Accumulation The permeability range and pore-throat size of the subject field are relatively low in the lower reservoir compared with the upper. Both reservoirs are under highly unstable asphaltene-stability conditions. The reservoir pressure-maintenance scheme, consisting of dump-floodwater injection followed by peripheral powered seawater injection and crestal gas injection, however, has maintained asphaltene-free production except for the gas-injection pilot (GIP) during 2005–2009. No asphaltenes have been observed in the crestal gas-injection area; however, asphaltene deposits were observed in the GIP area in 2007. The injected gas was enriched gradually by a vaporizing gas-drive process. The previous studies involving numerical modeling analysis and laboratory experiments reported that enriched hydrocarbon gas can more easily allow asphaltene precipitation compared with lean hydrocarbon gas. GIP Asphaltene Risk Analysis (Upper Reservoir). In 2009, an asphaltene flow-assurance risk evaluation was conducted using the single-phase bottomhole sample collected from Well 6, which is 90 ft shallower that the GIP area and far from the crestal gas-injection area. Therefore, the Well 6 reservoir fluid was not affected by injection gas. The bottomhole condition of the GIP production well was entered into the asphaltene precipitation envelope (APE) that was expanded by injection-gas enrichment but never covered by the APE without an enrichment process. Latest Laboratory Analysis (Lower Reservoir). In 2022, an asphaltene flow-assurance risk evaluation was conducted. After the location was narrowed to a depth range, Well 1 was selected by taking an asphaltene gradient into account.

Analysis of the reservoir properties of rocks of the Lower Kura depression (Azerbaijan)

The article analyzes the features characterizing the Lower Kura depression (LKD). A number of hydrocarbon deposits have been discovered in this oil and gas region. The Kalmas underground gas storage facility, which has the largest volume in Azerbaijan, is also located in this area. In the LKD, all PS formations can be traced throughout the entire well section. The reservoir properties of the rocks were considered to study the features of the area. In order to study the reservoir properties in the well section, the field applies data obtained by using a complex of well logging (WL) methods (laterolog, spontaneous potential logging, induction logging, gamma logging, neutron logging, acoustic logging) and analyses of rock samples. The graphs were constructed to evaluate the relationship between petrophysical parameters (porosity, permeability, etc.) determined in the rocks involved in the well sections of the object of research. In the article, maps of porosity distribution, permeability and permeability of sandy siltstone rocks and fractions greater than 0.1 of the Productive Series of the South-Eastern Gobustan and Baku Archipelago, which are part of the Low Kura Depression, are plotted and analysed. Plots showing the porosity distribution of the Low Kura Depression by depth were also constructed and some results were obtained. Based on reservoir properties, the region is divided into 6 groups, and in each group intermediate values of the porosity and permeability coefficient are determined. In general, the porosity coefficient ranges within 5-25%, permeability – 1-250 mD. The reservoir properties of rocks vary over area from worse to better. The capacitance-filtration properties of rocks were studied. The rock samples analysed identified rocks with good and low reservoir characteristics. To study the variation in the determining factors, maps of the distribution of reservoir properties indicators (fractions greater than 0.1 mm; porosity and permeability in sand-siltstone-containing rocks) were compiled by area and their causes were determined by comparison with other oil and gas fields. It was found that with distance from the mouth of the Kura River (towards the right and left banks), the reservoir properties of the rocks deteriorate. This is due to an increase in the amount of clay in rocks. It is also clarified that the change in porosity coefficient does not depend on depth. The content of sand-siltstone composition in the rocks along the section is 20-50%.

Inversion Model for Permeability Coefficient Based on Random Forest–Secretary Bird Optimization Algorithm: Case Study of Lower Reservoir of C-Pumped Storage Power Station

The geological complexity of the karst regions presents significant challenges, with the permeability coefficient being a critical parameter for accurately analyzing seepage behavior in hydraulic engineering projects. To overcome the limitations of traditional inversion methods, which often exhibit low computational efficiency, poor accuracy, and instability, this study utilizes a finite-element forward model and orthogonal experimental design to establish a sample set for permeability-coefficient inversion. A surrogate model for seepage calculation based on the Random Forest (RF) algorithm is subsequently developed. Furthermore, the Secretary Bird Optimization Algorithm (SBOA) is incorporated to propose an intelligent RF–SBOA inversion method for permeability-coefficient estimation, which is validated through a case study of the C-pumped storage power station. The results demonstrate that the RF model’s predictions for water levels at four boreholes closely align with the measured data, outperforming models such as CART, BP, and SVR. The SBOA effectively identifies the optimal geological permeability coefficient, with the borehole water-level inversion achieving a maximum relative error of only 0.128%, which meets the accuracy requirements for engineering applications. Additionally, the computed distribution of the natural seepage field is consistent with the typical distribution patterns observed in mountain seepage systems. During the normal water-storage phase, both the calculated seepage flow and gradient comply with engineering standards, while the seepage-field distribution aligns with empirical observations. This inversion model provides a rapid and accurate method for estimating the permeability coefficient of strata in the project area, with potential applicability to permeability inversion in other engineering geology contexts, thus demonstrating considerable practical value for engineering applications.

Influence of reservoir water saturation on coalbed methane development: Based on multi-field coupling numerical simulation

Water in coal reservoirs serves as both the driving force of reservoir fluid and the resistance to coalbed methane (CBM) migration. However, the impact and control mechanism of water saturation on CBM development in the field have not been revealed yet. The evolution of reservoir dynamics and gas production rate under various initial water saturation conditions is simulated based on the COMSOL multiphysics numerical simulation software. The simulation results show that the reduction of initial water saturation can significantly enhance the effective permeability of the reservoir gas phase, which can be increased by up to 4764%. This increases the rate of gas production, which is the main mechanism for controlling production by water saturation in the reservoir. For high water saturation reservoirs, the positive effect of inter-well interference should be reasonably utilized, and high well network density should be used to rapidly increase gas-effective permeability. For low water saturation reservoirs, the negative effect of inter-well interference should be avoided, and low well network density should be used to increase the control of single well reserves.

A new integrated modelling and control of ternary pumped storage hydro power generation for small signal stability studies

Pumped storage hydro power generation (PSHPG), a reliable renewable energy source with an energy storage feature, can impart efficient damping torque to power system oscillations to improve small signal stability with appropriate modelling and additional compensation through the governor. But ternary PSHPG (T-PSHPG) has the unique feature of hydraulic short circuit (HSC) mode, where both pumping and generating modes operate simultaneously. This study presents a novel fourth-order modified Heffron Phillips (MHP) model of T-PSHPG in coordination with a multi-band Power system stabilizer (MB-PSS) employing 2-way penstock, where primary penstock circulates water from the upper reservoir to the lower reservoir through the turbine and secondary penstock divides primary penstock, thereby creating short-circuit path through the pump. Also, this model includes additional reactive power droop control to maintain the voltage profile. A new state space matrix has been developed for coordinating T-PSHPG in HSC mode with MB-PSS. The control parameters of the proposed coordinated model are set by a new multi-objective differential evolution-improved particle swam optimization (DE-IPSO) algorithm. With variable load, random solar and wind source penetrations, it has been found that the proposed model can provide adequate damping actions. The sensitivity of the proposed model has been observed by varying critical model parameters by ±50 %. For all conditions, the settling time of speed variation is within 2.672 s to 5.951 s and the minimum damping ratio lies within 0.105 to 0.455. The minimum damping ratio is 0.32 and the settling time is found to be 3.1 s for system response subject to sudden solar power variation, which has been observed by shifting system eigenvalues toward the left half of the complex plane. Time and frequency domain parameters with sensitivity analysis predict system oscillations being damped effectively with consistency for the proposed modelling and control strategy. The results are verified in real-time with OPAL-RT real-time digital simulator. It has been justified by the present study that appropriate modelling of T-PSHPG along with coordinated control action provided by MB-PSS can handle critical power system oscillations efficiently and effective damping torque can be imparted in HSC mode.

აზოტის გამოყენება ნავთობისა და გაზის ოპერაციებში

The article discusses several options for nitrogen application in the oil and gas industry. Nitrogen gas is useful in maintaining formation pressure in oil fields, expelling gas from the gas cap, stimulating steeply inclined formations, cyclic exploitation of gas condensate deposits, Completion of wells, Cleaning of wells with Coiled Tubing, Circulatimg low pressure reservoir wells with foam.Described experience of local oil and gas companies in Georgia utilizing nitrogen pumping in welltesting and stimulation.

Implementation of Controlled Floods for Sediment Management on the Colorado River in Grand Canyon Under Aridification

ABSTRACTIn addition to supplying water for agriculture, cities, and industry, the Colorado River traverses the Colorado Plateau, including several of the most unique and valued National Parks and Recreation Areas in the United States. Although the water needs of these landscapes were not considered at the time water allocations were first negotiated, these needs were recognized in subsequent legislation and policy. Management goals address a range of aquatic and riparian resources, including fine sediment (sand, silt, and clay) which, in Grand Canyon, is important for ecological, cultural, and recreational resources. Over ~30 years, stakeholders, resource managers, and scientists collectively developed operational strategies for sediment management to meet goals outlined by an adaptive management program. However, prolonged drought, or “aridification,” resulting in declining runoff and the lowest reservoir storage elevations in decades has challenged those strategies. The paradigm for sustainable sediment management relies on (1) sand accumulation on the bed of the Colorado River during periods of sediment‐rich tributary floods from summer/fall thunderstorms, and (2) dam‐released controlled (artificial) floods, referred to as High‐Flow Experiments (HFEs), to redistribute the accumulated sand to rebuild eroded bar and floodplain deposits. The management protocol, which specifies narrowly defined sand accumulation periods and HFE implementation windows, is based on implementing HFEs in late fall during the period of greatest sediment enrichment, before higher winter releases for hydropower erode the accumulated sand from the riverbed. Low dam releases associated with drought, however, have changed the pattern of sand accumulation and low reservoir elevations have prevented HFE implementation in the defined window. An alternative strategy for HFE planning and implementation was tested opportunistically in April 2023 following lower‐than‐normal winter dam releases. We present findings from this HFE indicating that sand enrichment and sandbar building equaled or exceeded that of HFEs conducted under the established management protocol. These findings show that management goals for sediment under conditions of prolonged drought may be achievable but will likely require substantial changes in dam management strategies.

Optimization of The Development Plan for Ultra-low Permeability And Weak Volatility Reservoir

Abstract Block F1 of F oil field belongs to ultra-low permeability volatility reservoir. Compared with similar reservoirs at home and abroad, the reservoir property of this block is poor and the permeability is only 1.4 mD. There is no development experience for reference. It is urgent to explore the effective utilization technology of volatility reserves in F oil field. In view of the problems that the preliminary research results of F1 block cannot meet the development needs, the reservoir research is not deep, and the development rules are not clear, Through fine structural interpretation and reservoir prediction, the geological characteristics of the oil reservoir have been clarified; We used multiple indicators to evaluate the initial production capacity of the block, And clarified the initial development rules of the weak volatility reservoir. Perfect the dynamic analysis and production capacity evaluation technology of weak volatility reservoir. By using the reservoir engineering method, we optimized the reasonable working system and the development plan. So we expanded the potential of block development, adjustment and external expansion and optimized the development plan, then we constructed the rational well network deployment technology of weak volatility reservoirs which can provide guidance for the effective development of the F1 block. The results can provide reference for the development of other ultra- low permeability weak volatility reservoirs.

Mechanism of Water Control and Gas Augmentation by Fracturing Interface Modifier in Water-bearing Gas Reservoir

Abstract With the development of oil and gas reservoirs, water containing gas reservoirs have gradually received attention. However, problems such as water production during the production process have reduced gas permeability, leading to a decrease in gas well productivity underground. Phase permeability regulators improve productivity by changing the wettability of rocks and enhancing gas permeability. This article tests the interface performance of a phase permeability regulator and evaluates its temperature resistance, formation water salt resistance, and erosion resistance. The pore bound water saturation of the core before and after modification with the phase permeability regulator, as well as the relative permeability of gas and water phases, are tested. The experimental results show that the phase permeation regulator can reduce the surface tension of water to 22.2 mN/m, and the rock contact angle before and after soaking increases from 26.63 ° to 97.69 °, achieving the transition of rock from hydrophilic to hydrophobic. The surface tension of the phase permeation regulator changes significantly before and after aging at 80-120 °C, and its high-temperature resistance is poor. After mixing with formation water with a salinity of 60000 to 100000, the surface tension increases, and at a salinity of 60000, it increases by 5.1 mN/m. The use of phase permeability regulators for matrix core displacement resulted in a slight increase in displacement pressure, while the formation water remained unchanged after approximately 140 hours of erosion. After modification with phase permeability regulators, the irreducible water saturation of the core decreases by about 25%, and the relative permeability of the gas phase increases, resulting in a significant hydrophobic and gas conducting effect. Phase permeability regulators achieve hydrophobic gas conductivity by changing the wettability of rocks, which can alleviate the problem of water production in shallow and low salinity reservoirs.

Experimental Evaluation of Energy Enhancement and Fracturing Fluid Flowback Effect for CO2 Pre-Fracturing in Shale Reservoirs

Abstract Liquid CO2 pre-fracturing is a promising reservoir stimulation technology due to its advantages of increasing reservoir energy, low reservoir damage, and high fracturing fluid flowback rate. The on-site flowback scheme currently relies mainly on experience and requires further optimization of the energy enhancement effect and the flowback system. This paper presented a study on the changing law of liquid CO2 pre-fracturing energy-enhancing effect and fracturing fluid flowback rate in shale reservoirs was carried out by applying the experiments of drive-off and pressure-reducing flowback. The results indicate that, the injection of CO2 followed by linear gel fracturing fluid increased the energy (pressure) of the core system by approximately 322.8% compared to the injection mode of CO2 fracturing alone, and increased the energy (pressure) of the core system by approximately 24.1% compared to the injection mode of linear gel fracturing fluid. The energizing effect of the core system showed a trend of increasing and then decreasing with the increase of CO2 injection, and the best effect was achieved when the injection ratio of linear gel fracturing fluid to CO2 was 1:1. The flowback rate of the fracturing fluid and oil recovery both increased as the flowback differential pressure increased. Extending the soak time can increase the oil recovery, but the increase gradually decreases with the extension of the soak time. Additionally, the increase in soak time can improve the flowback rate of the core with relatively high permeability, but it has little effect on the flowback rate of the core with very low permeability.

Performance characteristics of a contra-rotating pump-turbine in turbine and pump modes under cavitating flow conditions

Recent studies have indicated the potential of a contra-rotating pump-turbine (CRPT) as a low-head design that enables pumped hydro storage in regions with flat topography. However, the effects of cavitation have scarcely been investigated for the CRPT. The current paper utilises computational fluid dynamics simulations to study a model scale CRPT subjected to cavitating flow conditions to determine how cavitation affects the machine’s operating performance in both pump and turbine modes. In total, eight operating conditions have been evaluated for each mode. The inlet flow rate is considered fixed at 0.27 m3/s, while the outlet pressure is gradually changed to induce cavitating conditions. The study demonstrates that the pump mode operation of the CRPT is more sensitive to cavitation compared to the turbine mode. The pump mode operation shows a steady decline in efficiency with decreasing inlet pressure, whereas in turbine mode the efficiency settles at a lower level. The 3% head drop occurs at la Thoma number of 1.0 in pump mode and at 0.6 in turbine mode. At the 3% head drop, a large cavitating region is already present at the runner blades’ suction side of the runner closest to the lower reservoir in both modes. The large cavitating region causes the flow to separate from the runner blade surfaces, which explains the reduced operating performance. To ensure an almost cavitating-free operating condition and unaffected performance, the Thoma number needs to be above 1.0 in turbine mode and at least 1.5 in pump mode. A frequency analysis reveals that the presence of cavitation affects the dominant pressure pulsations in the system. A dynamic mode decomposition analysis is carried out, demonstrating that the non-trivial pressure pulsations are connected to the support struts.

The effect of hydrocarbon prices and CO2 emission taxes on drainage strategies

Secondary recovery methods, such as water and gas injection, are effective and cost-efficient techniques for enhancing hydrocarbon recovery; however, they are highly energy-intensive, leading to a large environmental footprint. This study provides insights into the challenge of balancing high hydrocarbon demand with the imperative to reduce CO2 emissions from production by estimating how drainage strategies change under varying economic parameters and CO2 tax levels. An operator’s choice of drainage strategy is assumed to be the drainage strategy yielding the highest net present value (NPV). This paper simulates the drainage strategy of an under-saturated oil reservoir, utilizing reservoir simulations and incorporating a mathematical model that represents the production processing plant. This yields hydrocarbon production, the energy required, and the resulting CO2 emissions, all incorporated into an NPV based on hydrocarbon prices and CO2 emission taxes. The drainage strategy is then optimized to maximize NPV for various hydrocarbon prices and several levels of CO2 tax on associated emissions. The findings of this study indicate that increasing gas prices favor reducing reservoir pressure below the bubble point pressure, thereby releasing solution gas and leaving oil in the reservoir. Although lower reservoir pressure reduces the energy required for injection, the resulting increase in gas production necessitates more energy for gas compression, ultimately leading to higher emissions when gas prices rise relative to oil prices. Additionally, this study reveals that for facilities well designed for the present injection and production volumes (greenfield scenarios), the impact of CO2 tax is limited, leading to a single optimal drainage strategy. In contrast, less energy-efficient facilities (brownfield scenarios) exhibit a more pronounced need to optimize drainage strategies in response to variation in CO2 tax, and oil and gas prices. This study indicates that for fields with efficient production facilities, the ratio of gas to oil prices is more important for the drainage strategy than CO2 tax levels, as income from production tends to dominate emission taxes. This implies that hydrocarbon prices are more important for CO2 intensity than CO2 taxes, e.g., a gas price increase relative to oil price promotes higher CO2 intensity due to a shift towards more energy-intensive gas production whereas realistic tax levels for CO2 emissions have only a minor impact. Thus, increasing CO2 tax levels is mainly a measure impacting emissions from fields with inefficient production facilities.

Reservoir characterization of GABO field in the niger delta basin using facies and petrophysical analyses

This study investigates the GABO field in the onshore Niger Delta Basin using well logs and core samples, with a focus on rock type distribution, reservoir continuity, and petrophysical properties to enhance hydrocarbon exploration accuracy. The research involved detailed analysis of core descriptions and images from GABO-20, along with petrophysical data from wells GABO-4, GABO-12, GABO-13, GABO-20, and GABO-51, aiming to identify rock types, evaluate reservoir quality, and determine the spatial distribution of petrophysical properties. The methodology included rigorous well log quality checks, data correlation between wells, petrophysical property evaluation, and lithofacies description. The analysis revealed thirty-five hydrocarbon-bearing zones, with GABO-20 showing average shale fraction values between 0.111 and 0.335, total porosity ranging from 0.242 to 0.329, and hydrocarbon saturation from 0.667 to 0.923, indicating substantial porosity and hydrocarbon saturation conducive to extraction. Well correlations demonstrated excellent sand-shale continuity within the reservoir intervals. Lithofacies analysis of the GABO-20 core identified eight distinct facies, including shale poles, liquid-rich shales, and sandstone poles, revealing a complex distribution of reservoir qualities with significant variations in potential. Cores 1 and 2 exhibited favourable conditions for hydrocarbon production, while Core 3 showed lower reservoir quality due to increased clay content. The depositional settings of the GABO field, particularly in the lower delta plain and delta front zones, showed well-developed reservoir bodies with moderate potential in the tidal zone and little potential in the shaly prodelta environment. This distribution highlights the complexity of the deltaic system and its implications for reservoir modeling and utilization. Reservoir zones associated with High-Quality Reservoir Facies exhibited strong petrophysical properties, suggesting excellent hydrocarbon production potential. The study underscores the importance of detailed reservoir characterization to optimize recovery strategies, offering valuable insights into the distribution and quality of reservoir sands, reducing subsurface uncertainty, and emphasizing the integration of facies and petrophysical approaches for a better understanding of reservoir characteristics in the GABO field.

High-Order Models for Gas Transport in Multiscale Coal Rock.

The coal reservoirs exhibit great heterogeneity and strong anisotropy in multiscale pore/fracture structures. Developing highly accurate multiscale models for real-time prediction of microgaseous flow in complicated porous media with pronounced contrast in transport coefficients is crucial but not yet available, which is time-consuming, expensive, and even computationally impossible. In this study, a multiscale approximate solution of the gas flow and pressure field is derived in this paper for predicting coalbed methane (CBM) transport in macro-microscopic two-scale porous media of typical coal rocks in Guizhou Province, China, and the detailed finite element algorithm is established. The multiscale approximate solutions are constructed from the first- and second-order auxiliary cell functions and low- or high-order derivatives of the homogenized pressure field, which can accurately approximate the solution of the original problem to a certain extent. The numerical accuracy and validity of the multiscale approximate solutions under various working conditions are analyzed in detail by comparing and verifying the results with the direct numerical simulation results of fine-mesh high-precision finite elements. The results show that the homogenized approximate solution can only roughly capture the characteristics of the macroscopic pressure evolution, the first-order approximate solution can partially reproduce the macro-microscopic pressure oscillation phenomenon, and the second-order approximate solution can accurately predict the pressure profile and its evolution law with time in porous media with macro-micro configuration under various complex conditions. The second- and high-order two-scale approximate solutions constructed in this paper exhibit high numerical accuracy and excellent computational efficiency. We also develop multiscale approximate solutions for predicting microgaseous flow at a low reservoir pressure where the slippage effects are very pronounced. Potential applications of our high-order models to the coal reservoirs with a hierarchical matrix and fractures are discussed. The developed multiscale models exhibit excellent applicability to investigating the crossflow effects and coupling mechanisms between the matrix and cleats or fractures with multiple configurations in the CBM and shale gas reservoirs, which is crucial for the effective implementation of hydraulic fracturing technology. This study provides a fundamental understanding of gas transport in multiscale matrix-fracture networks, which helps to improve the optimization design of hydraulic fracturing in tight reservoirs.

Improving Sub-daily Runoff Forecast Based on the Multi-objective Optimized Extreme Learning Machine for Reservoir Operation

Data-driven models have shown remarkable achievements in runoff prediction, but their simulation results can be overly homogenized due to the distillation of all simulation aspects into the loss function. This can make the models unreliable for predicting extreme events, leading to issues subsequent reservoir operations. This paper proposes a novel data-driven hybrid machine-learning model called the multi-objective optimized extreme learning machine (MOELM) to provide an accurate runoff forecasting for reservoirs. The objective is to minimize simulation error, with an additional focus on flood deviation. The results show that: (1) MOELM can improve flood events prediction, reducing the root mean square error (RMSE) for flood series by 5.27% without increasing the overall prediction error at Longtan reservoir. Compared to hydrological models, MOELM can reduce operational risk with lower reservoir maximum outflow and water level during typical flood events, and it can potentially increase hydropower generation at Longtan reservoir by 130 million kW·h. (2) MOELM can be transferred to other cross-sections with excellent performances, demonstrating hydrological transferability from fluctuation to flatness in regime. (3) Partial mutual information is introduced for input variable selection, with discharge at lag times t-4, t-1, t-8, and t-2 being vital to the prediction model. Our model is practical, requiring no additional input, fitting the hydrological runoff holistically, and capable of providing accurate flood forecasts.

Identification of the low resistivity-low contrast (LRLC) gas-bearing pay zones in Shaly sand reservoirs using acoustic data: a case study from the Messinian Abu Madi formation, onshore Nile Delta, Egypt

AbstractDetection of the low resistivity-low contrast (LRLC) reservoirs is among the main challenges in the oil industry. In this concern, the LRLC pay zones of the Upper Messinian Abu Madi clastic reservoirs in the onshore Nile Delta Gas fields became a main challenge for significant exploration. This type of reservoirs, including low resistivity-low contrast zones and thin-bedded intervals, are often overlooked using the conventional petrophysical evaluation techniques, especially in the wildcat exploratory wells or highly agitated shoreline depositional environments like the Nile Delta of Egypt. These hidden low contrast reservoirs are generally challenging due to the presence of many shale intercalations/laminations and/or due to increasing the shale volume represented in the form of dispersed distribution, and the dominance of conductive clay minerals. Therefore, in this study, the expected high resistivity values of the gas-bearing reservoir intervals of the Abu Madi Formation in the onshore Begonia gas Field, as a typical case study of the LRLC reservoirs, are masked due to the relatively high shale conductivity, particularly when the thickness of these intervals is less than the vertical resolution of the utilized conventional resistivity log. To verify the LRLC phenomena of the Begonia gas Field, the obtained data was compared to the South Abu El Naga gas Field as a normal case study with a relatively high resistivity gas-bearing pay zone. To overcome the impact of the conductive clay mineral content and identify these hidden low resistivity reservoir intervals, it is necessary to integrate the conventional logging data (gamma-ray, shallow and deep resistivity, density, and neutron) with the acoustic log data including shear and compressional sonic data. In this way, a useful relationship can be established enabling the detection of these hidden LRLC reservoir intervals. This integration is based on the principle that shear waves are not influenced by the fluids types, whereas the compressional sonic waves are influenced by the reservoir fluids. However, to effectively investigate these concealed LRLC reservoir intervals, which can boost production and increase the potential reserves, it is essential to have a low water cut value. The present study represents introduces an efficient workflow, which can be extended to other similar LRLC pay zones in the Nile Delta and northeast Africa. It is also extendible to the LRLC reservoirs in similar deltaic systems having conductive minerals-bearing reservoirs or thin beds.

Study on organic carbon in medium-low mature shale oil reservoirs rich in type II kerogen: Oxidation behavior, thermal effect, and kinetics

In-situ combustion technology (ISC) was a potential technology for efficient development of medium–low maturity shale oil reservoirs. Clarifying the exothermic behavior of organic carbon oxidation will be beneficial for better control of ISC processes. In this work, the organic carbon composition, type II kerogen and residual oil, were separated and extracted from the shale samples of typical medium–low maturity shale oil reservoirs in the Ordos Basin, China. The synchronous thermal analyzer and mass spectrometry (STA-MS), Fourier transform infrared spectroscopy (FTIR), and ROCK-EVAL VI were used to study the products, heat release, and functional group changes of type II kerogen, residual oil, and shale during the oxidation process. The results indicated that the oxidation heat release of shale mainly came from the oxidation reaction between its residual oil and type II kerogen, but the oxidation heat release range of shale was relatively lagging compared to the single residual oil or type II kerogen affected by rock debris. Secondly, under atmospheric pressure, the type II kerogen experiences obviously higher heat release than residual oil and heavy oil, indicating its superior potential of in-situ heat release. In addition, the major productions that CO, H2O, SO2, and CO2 were quantitatively characterized, with CO2 having the highest production of 882.25 mg/g. Furthermore, combined with the molecular weight, an oxidation reaction equation of type II kerogen was constructed. Finally, the oxidation kinetics parameters of type II kerogen, residual oil, and shale were determined using Friedman and Ozawa-Flynn-Wall (OFW) models. It was found that the activation energy of shale was higher than II kerogen and residual in low temperature oxidation (LTO) and fuel deposition (FD) stages. This may be due to the joint reaction between kerogen and residual oil, thus exacerbating the challenge of shale in-situ ignition. However, due to the catalytic effect of rock debris, the activation energy of shale was lower than LTO in high temperature oxidation (HTO) stage, indicating that once fuel deposition was completed, organic carbon will undergo stable combustion. This study has theoretical guidance for the numerical simulation research of ISC development technology of maturity-low shale oil reservoirs.

Enhanced Oil Recovery Techniques in Low Permeability Unconventional Shale Reservoirs

Enhanced Oil Recovery Techniques in Low Permeability Unconventional Shale Reservoirs

Characteristics, main controlling factors and densification mechanisms of unconventional tight reservoirs in Triassic Yanchang Formation in southern Ordos Basin, China

The key factors controlling the densification of unconventional reservoirs (e.g., tight oil and gas reservoirs) remain poorly understood and directly affect the distribution of exploitable resources. Here, systematically explored reservoir characteristics, depositional microfacies, and the main factors controlling densification of the tight oil reservoir in the Chang 8 Member (Yanchang Formation, Middle Triassic) in the Zhenjing area of the southern Ordos Basin by thin section analysis, scanning electron microscopy, physical property measurement, X-ray diffraction, and mercury injection. Our results confirm the Chang 8 reservoir as an extremely low permeability tight sandstone reservoir mainly comprising lithic feldspathic sandstone with various primary and secondary pores and fine pore channels. The highest quality reservoir is mainly restricted to the middle and lower parts of subaqueous distributary channel microfacies. Dissolution partly contributed to reservoir formation, but the persistence of early, non-compressed storage space was more important. The compression of plastic rock debris removed a significant amount of porosity, and calcite and kaolinite both fill pores and contribute to the structural strength of pore space. We identified three densification processes: the persistent densification of highly plastic rocks, calcite cementation, and feldspar dissolution and subsequent kaolinite precipitation. After their compaction, the Chang 8 Member reservoirs were charged with hydrocarbons. We applied clustering analysis to eight reservoir characteristics (porosity, permeability, median pore-throat radius, maximum pore-throat radius, median capillary pressure, pore discharge pressure, chlorite content, kaolinite content) to quantitatively classify the Chang 8 reservoir into three categories. Type-I reservoirs have the best conditions for hosting tight oil reservoirs, with ∼12% porosity, permeabilities of ∼0.2 × 10−3 μm2, trial oil production rates of >5 m3/d, and, indeed, occur in subaqueous distributary channel microfacies. Type-II reservoirs ∼10% porosity, permeabilities of ∼0.1 × 10−3 μm2, and trial oil production rates of 1–5 m3/d. Type-III reservoirs have ∼5% porosity, permeabilities of ∼0.05 × 10−3 μm2, and trial oil production rates <1 m3/d. These results provide an important basis for predicting the distribution of exploitable zones in the Chang 8 sandstone and other adjacent tight sandstones.