The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Khan, Mohammad Rasheed (SLB) | Kalam, Shams (King Fahd University of Petroleum & Minerals) | Asad, Abdul (SPRINT Oil & Gas services) | A. Abu-khamsin, Sidqi (King Fahd University of Petroleum & Minerals)
Abstract Unconventional reservoirs like shale oil/gas are expected to play a major role in many unexplored regions, globally. Shale resource evaluation involves the estimation of Total Organic Carbon (TOC) which correlates to the prospective capability of generating and containing hydrocarbons. Direct measurement of TOC through geochemical analysis is often not feasible, and hence researchers have focused on indirect methods to estimate TOC using analytical and statistical techniques. Accordingly, this work proposes the application of artificial intelligence (AI) techniques to leverage routinely available well logs for the prediction of TOC. Multiple algorithms are developed and compared to rank the most optimum solution based on efficiency analysis. Support Vector Regression (SVR), Random Forest (RF), and XGBoost algorithms are utilized to analyze the well-log data and develop intelligent models for shale TOC. A process-based approach is followed starting with systematic data analysis, which includes the selection of the most relevant input parameters, data cleaning, filtering, and data-dressing, to ensure optimized inputs into the AI models. The data utilized in this work is from major shale basins in Asia and North America. The AI models are then used to develop TOC predictor as a function of fundamental open-hole logs including sonic, gamma-ray, resistivity, and density. Furthermore, to strengthen AI input-output correlation mapping, a k-fold cross-validation methodology integrating with the exhaustive-grid search approach is adopted. This ensures the optimized hyperparameters of the intelligent algorithms developed in this work are selected. Finally, developed models are compared to geochemically derived TOC using a comprehensive error analysis schema. The proposed models are teted for veracity by applying them on blind dataset. An error metrics schema composed of root-mean-squared-error, and coefficient of determination, is developed. This analysis ranks the respective AI models based on the highest performance efficiency and lowest prediction error. Consequently, it is concluded that the XGBoost and SVR-based TOC predictions are inaccurate yielding high deviations from the actual measured values in predictive mode. On the other hand, Random Forest TOC predictor optimized using k-fold validation produces high R values of more than 0.85 and reasonably low errors when compared to true values. The RF method overpowers other models by mapping complex non-linear interactions between TOC and various well logs.
Samarkin, Yevgeniy (King Fahd University of Petroleum and Minerals) | Amao, Abduljamiu Olalekan (King Fahd University of Petroleum and Minerals) | Aljawad, Murtada Saleh (King Fahd University of Petroleum and Minerals) | Sølling, Theis Ivan (King Fahd University of Petroleum and Minerals) | AlTammar, Murtadha J. (Saudi Aramco) | Alruwaili, Khalid M. (Saudi Aramco)
Abstract Fractured carbonate formations composed of chalk and limestone rock lithologies develop several issues over time, reducing fractures’ conductivity. One such issue is the embedment of the proppant that happens due to the soft nature of the carbonate rocks. Reduction of fractures’ conductivity results in the need for refracturing operations that require pumping tremendous amounts of water. The refracturing operations can be avoided if the fractures are maintained conductive for a longer time. This research targets reducing the severity of proppant embedment issues in carbonate formations through rock hardening by diammonium hydrogen phosphate (DAP) treatment. The chalk and limestone rock samples were treated with a DAP solution of 0.8M concentration at three temperatures, namely 30°C (ambient), 50°C, and 80°C. The samples were treated by immersion in solution, in which rocks were kept reacting for 72 hours. The treated samples were analyzed using the SEM-EDX technique to identify new minerals and changes in the morphology of the rock samples. Moreover, the changes in the hardness of the samples were analyzed by the impulse hammering technique. In addition, the proppant embedment scenario was mimicked in the rocks by utilizing Brinell hardness measurements before and after their treatment. The SEM analysis demonstrated that the treatment of carbonate rocks with a DAP solution results in the formation of hydroxyapatite (HAP) minerals. In addition, it was observed that the temperature of the treatment affects the crystallization patterns of the HAP minerals. Further results demonstrated that DAP treatment at elevated temperatures significantly improves the hardness of the samples. Young’s modulus of the rock samples increased by up to 60 - 80% after the treatment. In addition, studies have shown the improvement of rocks’ resistance to indentations. The sizes of the dents created by the Brinell hardness device were smaller than before the treatment. Overall, it was demonstrated that the Brinell hardness of the rock samples improved by more than 100%. This research demonstrated that treating carbonate rocks with DAP solution results in their hardening and improved samples’ resistance to indentation. Moreover, the treatment of rock samples at temperatures similar to reservoir conditions even further improves the mechanical properties of the carbonate rocks. Upscaling laboratory DAP treatment techniques for reservoir applications will introduce new practical methods for maintaining the long-term conductivity of propped fractures. Such a procedure will help avoid refracturing operations, resulting in better and more sustainable management of water resources.
Abstract Hydraulic fracturing has long been an established well stimulation technique in the oil & gas industry, unlocking hydrocarbon reserves in tight and unconventional reservoirs. The two types of hydraulic fracturing are proppant fracturing and acid fracturing. Recently, a new of hydraulic fracturing is emerging which is delivering yet more enhanced production/injection results. This paper conducts a critical review of the emerging fracturing techniques using Thermochemical fluids. The main purpose of hydraulic fracturing is to break up the reservoir and create fractures enhancing the fluid flow from the reservoir matrix to the wellbore. This is historically achieved through either proppant fracturing or acid fracturing. In proppant fracturing, the reservoir is fractured through a mixture of water, chemicals and proppant (e.g. sand). The high-pressure water mixture breaks the reservoir, and the proppant particles enter in the fractures to keep it open and allow hydrocarbon flow to the wellbore. As for acid fracturing, the fractures are kept open through etching of the fracture face by acid such as Hydrochloric Acid (HCl). An emerging technique of hydraulic fracturing is through utilization of thermochemical solutions. These environmentally friendly and cost-efficient are not reactive as surface conditions, and only react in the reservoir at designated conditions through reservoir temperature or pH-controlled activation techniques. Upon reaction, the thermochemical solutions undergo an exothermic reaction generating in-situ foam/gases resulting in creating up to 20,000 psi in-situ pressure and temperature of up to 700 degrees Fahrenheit. Other reported advantages from thermochemical fracturing include the condensate bank removal (due to the exothermic reaction temperature) and capillary pressure reduction.
Dong, Xiaohu (China University of Petroleum-Beijing) | Zhang, Hao (China University of Petroleum-Beijing) | Lu, Ning (China University of Petroleum-Beijing) | Xiao, Zhan (China University of Petroleum-Beijing) | Lyu, Xiaocong (China University of Petroleum-Beijing) | Liu, Huiqing (China University of Petroleum-Beijing) | Chen, Zhangxin (University of Calgary)
Abstract Steam injection process is usually the primary extraction method for heavy oil reservoirs. But, in recent decades, with the steam injection operation continues, most of the steamed heavy oil reservoirs have achieved a depleted status (residual oil zone). Meanwhile, for most post steamed heavy oil reservoirs, the average formation temperature can reach above 150℃. It indicates that they can be considered as a potential artificial geothermal energy source. In this work, those post steamed heavy oil reservoirs are proposed as a source of artificial geothermal energy, and the extraction potential is evaluated. A heavy oil reservoir simulation model is firstly constructed based on a geological model which involves a five-spot well pattern of steam flooding operation in Shengli oilfield, Sinopec. This model can be used to represent a depleted status of a steamed heavy oil reservoir. Subsequently, based on this five-spot well pattern of steam flooding, a geothermal heat extraction model is developed. In order to accurately evaluate the extraction potential of this artificial geothermal energy, the wellbore heat loss is also considered by using a discretized wellbore model. Thus, two different extraction methods of water injection and CO2 injection are simulated. Then, based on the simulation model, the factors that control the heat extraction rate in high temperature depleted heavy oil reservoirs are also discussed. Results show that a post steamed heavy oil reservoir can be a potential source of geothermal energy. By using the existing steam flooding well pattern, the initial investment is reduced, thus, a high-efficient development can be achieved. From the simulation results, it is found that the method of geothermal energy extraction in high temperature depleted heavy oil reservoir (165 ℃, 2 MPa) using CO2 can achieve a high-speed geothermal energy extraction process in the early stage (<1.5 years). In comparison, a method of water injection process performs better within a longer time period (>1.5 years). Simultaneously, it is found that the bottom-hole pressure, heat extraction time and CO2 injection rate can have the biggest impact on the heat extraction rate. Because of the high temperature condition, the post steamed heavy oil reservoirs can have a huge potential of heat mining. The technology of geothermal energy extraction can further enhance their development value and prolong the working life.
Abstract Oil and gas will be the main part of our future energy sources, despite of emerging and expanding of renewable energies. Enhanced Oil Recovery (EOR) plays an important role in the future oil and gas industry as the conventional oil reserves will shrink. Heavy oil reservoirs will be the main target of EOR methods because of the high number of existing heavy oil reservoirs. Surfactants are the most efficient chemical EOR method for many unconventional reservoirs as previous studies suggest. The problem with this EOR method is that these projects have high costs and raised environmental concerns. Ionic liquids (ILs) are introduced as an alternative material to surfactants, however, the cost of their synthesis and purification processes are high. Besides, some of them are toxic and have non-biodegradable properties which limit their commercial usage. Recently, a new form of ILs produced and called Deep Eutectic Solvents (DESs). The discovered material is more affordable and environmentally friendly and hence, it is considered to be an alternative material for existing conventional ILs. DESs are cheap, easy to produce, non-toxic, reusable, bio-degradable, and environmentally friendly. These materials consist of two or more cheap and safe components which will form a eutectic mixture. The melting point of the final mixture is lower than its components. In this study, the effectiveness of DESs in the EOR is analysed and evaluated to consider it as a new injection material for chemical EOR. This material has specific properties which improve the efficiency of EOR processes. Some of the favourable properties are stable emulsion between phases, interfacial tension (IFT) reduction, wettability change, recovery enhancement, and avoiding formation damage which is discussed and analysed in this paper. Moreover, the cost of the process is hugely reduced compared with other chemical injection methods. As the result, the main factor for the recovery enhancement is wettability alteration and the chance of viscosity. Besides, only malonic and acid-based DESs formed emulsions with oil, and the other types of DESs did not show emulsification properties. The IFT value increased for heavy oil reservoirs, while for reservoirs with light/medium oil IFT was reduced. Furthermore, DESs did not show formation damage which is a bonus point for this method. As the final result, Choline Chloride Glycerol showed the best recovery with an extra 30% to the original production.
Li, Yu (China university of petroleum, Beijing) | Liu, Huiqing (China university of petroleum, Beijing) | Luo, Chen (China university of petroleum, Beijing) | Dong, Xiaohu (China university of petroleum, Beijing) | Wang, Qing (China university of petroleum, Beijing) | Liu, Chuan (China university of petroleum, Beijing) | Wang, Zhipeng (China university of petroleum, Beijing)
Abstract Hybrid steam-CO2 flooding, mature technology to enhance oil recovery, promotes the deposition of asphaltene from heavy oil and the CO2-brine-silica interaction to change the wettability of silica surface. The asphaltene deposition can promote lipophilicity of the silica surface while the CO2-brine-silica interaction can enhance its hydrophilicity. Therefore, aiming to study the wettability alteration during hybrid steam-CO2 flooding, we explore the interaction characteristics of CO2 with oil and brine on the silica surface. In this work, a series of experiments are conducted to reveal the wettability alteration of silica by the interaction of CO2 with different fluids under different conditions. The CO2-brine-silica interaction experiments and the CO2-oil-silica experiments are carried out in the temperature and pressure-resistant vessel to comprehensively acquire the silica under the influence of various fluids in the static process. In addition, based on the core flooding experiments, computerized tomography (CT) technology is applied to realistically and automatically extract the dynamic contact angle in the dynamic process. The result of contact angle from CO2-brine-silica interaction experiments shows the interaction between CO2 and brine evidently enhances the hydrophilicity of the silica surface under high temperature, and the ability of CO2 and brine to promote the increase of hydrophilicity is much greater than that in the absence of CO2. Moreover, the result of contact angle from CO2-oil-silica experiments indicates the increase of temperature and CO2 pressure makes the silica surface covered by heavy oil present the tendency of hydrophobia. The micro-CT images from core displacement experiments are automatically processed by an intelligent algorithm to extract the remaining oil distribution and display the data of dynamic contact angle. Under the influence of steam, the remaining oil mainly performs the form of membrane oil attached to the silica surface. Furthermore, the edges of the remaining oil take on an irregular shape and the contact angle reflecting hydrophobicity reach 45.2% after steam flooding. After the stage of CO2 flooding, the obvious reduction in membrane oil thickness occurs and the number of contact angles reflecting hydrophobicity decreases to 35.3%. Moreover, the oil film gradually transforms into many oil droplets on the surface under the steam and CO2, which may be conducive to the migration of heavy oil in a porous medium. Taking static and dynamic characteristics of contact angle into account under different environments, the conditions and mechanism of wettability alteration can serve as a perspective for CO2 application in pore-scale displacement.
Abstract This paper presents the results of numerical simulations of hydraulic fracturing in the immediate vicinity of the wellbore. This research aims to identify the primary mechanisms underlying the complexities in both the fracture morphology and propagation of longitudinal fractures. The study shows that the perforation attributes and characteristics, the cement quality, and the reservoir heterogeneity have a significant impact on the resulting morphology and the trajectory of the propagating hydraulic fracture. The study is based on properties and conditions associated with a field study conducted in the Austin Chalk formation, and concludes that the pattern and the dimensions of the perforations are essential factors controlling the fracture initiation pressure and morphology. The results of the simulation studies provide insights into the principles and mechanisms controlling fracture branching and the initiation of longitudinal fractures in the near-wellbore region and can lead to improved operational designs for more effective fracturing treatments.
de Oliveira, Josias Pereira (University of Campinas) | Santos, Susana Margarida da Graça (University of Campinas) | dos Santos, Antônio Alberto Souza (University of Campinas) | Schiozer, Denis José (University of Campinas)
Abstract Many projects in the Brazilian pre-salt assume the use of water alternating gas (WAG-CO2) injection as an ecologically safe carbon storage strategy, with improved hydrocarbon recovery. However, studies that compare these advantages with a simpler management plan are not common. The objective of this work is to compare WAG-CO2 injection with continuous injection of water and gas (CIWG) rich in CO2 in separate wells for the development and management of a light-oil fractured carbonate reservoir subject to full gas recycling. We employed the UNISIM-II benchmark model, a naturally fractured carbonate reservoir with Brazilian pre-salt characteristics, which enables an application in controlled environment where the reference response is known (UNISIM-II-R). We used a model-based decision analysis for production strategy selection, hierarchical optimization of the decision variables and algorithms to maximize the objective function. Representative models (RM) are selected from the ensemble of models and used to incorporate the effects of geological, reservoir, and operational uncertainties into the optimization process. The net present value is the objective function during the nominal optimization of candidate strategies of each RM and the expected monetary value and risk analysis are considered to select the final production strategy considering uncertainties. The risk analysis was quantified based on downside risk and upside potential relation to a benchmark return. We optimized two alternative development plans (one considering WAG-CO2 injection and the other continuous injection of water and gas in separate wells) and compared their performance indicators and decision variables, including design variables (number, type and placement of well, and size of production facilities) and life-cycle control rules (management of equipment over time). We then applied a cross-simulation, where the best strategy optimized for one recovery method was applied to the other and the injection strategy was optimized again. We were therefore able to assess the need to pre-define the recovery method before defining design variables to validate the flexibility of each strategy for possible future changes in the recovery mechanism. Finally, we repeated the study for different reservoir scenarios to compare the alternatives considering typical uncertainties of the Brazilian pre-salt and validated the final strategies in the reference model to quantify the real value in decision making. The strategies reached a full gas recycling in both recovery methods and allowed a comparison of their advantages and disadvantages. The operations of WAG-CO2 injection can be more complex and the equipment more expensive. The novelty of this work is the consideration of continuous injection of water and gas in separate wells as a simpler alternative to the development and management of pre-salt oil fields, since this method may also meet operators’ and environmental demands, bearing simpler operating challenges and promoting good recovery and profitability.
Abstract Many geo-energy related applications involve predicting the behavior of fluid flow in fractured subsurface reservoirs. Naturally fractured carbonate reservoirs are particularly important for being a major source of the world's hydrocarbon production. These reservoirs are also currently being considered as potential CO2 storage sites that will support net zero emissions goal. Simulation of flow in fractured reservoirs is a challenging task that typically involves upscaling the effective permeability of the fracture network and matrix into continuum models that consider the reservoir scale. The most accurate way to obtain such upscaled permeability for fracture networks is to perform single-phase flow simulations in statistical realizations of the fracture network using three-dimensional unstructured grids and explicit modelling of fractures. This step can be computationally challenging for highly dense fracture networks due to the difficulty in meshing the fractures and the rock matrix. Here, we present a method to reduce the complexity of the fracture network while still preserving the behavior of its effective permeability. Our approach involves a fracture merging algorithm that reduces the number of fractures allowing for faster meshing and upscaling. The fracture merging algorithm uses three different similarity metrics: fracture orientation, fracture area and distance between fractures. These metrics are used to identify similar fractures that can be merged into one single fracture with increased permeability. The upscaling algorithm to obtain the effective permeability of a grid cell containing a fracture network relies on flow simulations in three-dimensional unstructured meshes. We applied our method to different sub-networks extracted from a stochastically generated fracture network of a Brazilian Pre-Salt carbonate reservoir. We found that the average permeability of all fractures of the resulting fracture network increases with merging intensity, i.e., with decreasing the number of fractures, while the resulting upscaled effective permeability for the network remains in the same order of magnitude. This shows that the flow-based upscaling workflow including the merging algorithm leads to a significant reduction of complexity of fracture networks and consequently their 3D unstructured meshes while maintaining the structural and topological features that account for the fracture network effective permeability. Our proposed method is simple to implement and relies only on geometrical properties of the fractures. Other machine-learning based models have been proposed to achieve similar simplification of fracture networks, however, they are not easily incorporated into existing reservoir simulation tools and codes like the method presented in this work. Moreover, such previously published approaches do not consider flow in matrix and thus haven't been tested in scenarios where the matrix also contributes to flow.
Liang, Guangyue (Research Institute of Petroleum Exploration and Development, CNPC) | Xie, Qian (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Yang (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Shangqi (Research Institute of Petroleum Exploration and Development, CNPC) | Xia, Zhaohui (Research Institute of Petroleum Exploration and Development, CNPC) | Bao, Yu (Research Institute of Petroleum Exploration and Development, CNPC) | Zhou, Jiuning (Research Institute of Petroleum Exploration and Development, CNPC)
Abstract It is very difficult to realize good economy returns using conventional SAGD process in many oil sands projects due to large CPF investment, massive steam injection, expensive surface diluent adding and increasing carbon emission tax. By contrast, warm solvent assisted gravity drainage process (WSAGD) is a promising low-carbon technology to deal with these SAGD challenges. This paper conducted feasibility evaluation by combined with Nsolv Best pilot analysis and a series of physical simulations. From 2014 to 2017, WSAGD pilot was successfully carried out by injecting butane at 60℃ in Suncor Dover oil sands. Its reservoir geological characteristics, physical properties, development technology policy and production performance were systematically analyzed. Combined with 4D seismic interpretation, RST and observation well data, the size and growth rate of solvent chamber were monitored and analyzed. Considering great uncertainty in numerical simulations influenced by many factors including grid size, solvent diffusion coefficient, interfacial tension and capillary force, a series of experimental tests and physical simulations were conducted. The behavior of viscosity reduction, interfacial tension reduction and microscopic oil displacement related to different solvents were systematically tested including propane, butane, pentane and hexane. Particularly, the performance of SAGD and WSAGD process were evaluated by 2D and 3D visual physical simulations. In Nsolv Best pilot, the target reservoir is low pressure, thin and shallow buried. The oil rate reached 250-300 barrels per day under 300 m horizontal section, and API degree of produced oil was upgraded to 13-16 from original 8. After 3 years of tests, the width of solvent chamber is 40-60m, lateral and vertical 1.56 m and 0.96 m per month, and horizontal conformance is 67%. The experiments results show that viscosity reduction trend will flatten out when the solvent concentration exceeds 10 vol% due to partial asphaltene precipitation. Both sweep efficiency and displacement efficiency of hot water, steam, gaseous and liquid hexane are increasing with temperature increase. Compared with other medium, sweep efficiency and displacement efficiency of gaseous hexane are higher due to greater dissolving ability and speed in bitumen. Both 2D and 3D experimental results indicate that WSAGD process achieves faster vertical solvent chamber and higher recovery factor than conventional SAGD process. Besides, gaseous pentane has significant upgrading effect considering substantial reduction of asphaltene and resin in the produced oil, which is not available in conventional SAGD process. This paper first systematically compares the mechanisms and performance of warm solvent assisted gravity drainage (WSAGD) process with SAGD process by physical simulations. It presents a promising low-carbon technology to enhance oil recovery, partially upgrade the produced oil and reduce carbon dioxide emissions in developing super-heavy oil or oil sands project.