ORCID Profile
0000-0002-0776-3364
Current Organisation
University of Adelaide
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Publisher: Elsevier BV
Date: 10-2017
Publisher: Elsevier BV
Date: 11-2023
Publisher: Elsevier BV
Date: 06-2017
Publisher: SPE
Date: 25-10-2019
DOI: 10.2118/196528-MS
Abstract: Artificial lift methods typically drive Coal Seam Gas (CSG) wells, and Progressive Cavity Pump (PCP) is the preferred method of lift with Australian CSG operators. CSG wells in Australia are typically equipped with necessary instrumentation and automation systems to provide real-time data gathering for monitoring and control purposes. Real-time data gathered from CSG wells presents an opportunity to better understand PCP performance by identifying anomalous pump behavior. However, before undertaking any real-time analytics exercise, it is pertinent to carry out Exploratory Data Analytics (EDA) to understand time series data behavior and extract relevant features and this exercise is particularly important with multi-variate data sets. Obtaining significant data features from multivariate time series data can help define which analytics and machine learning methods could be exploited to analyze PCP performance in near real time. This paper will discuss EDA methodologies that can help streamline time-series data normalization and feature extraction techniques. A three (3) year time-series dataset, gathered from forty-two (42) CSG wells, will be used to showcase EDA methodologies utilized as part of this research. All EDA activities covered in this paper are based on the Python programming language and its supporting libraries.
Publisher: SPE
Date: 09-11-2015
DOI: 10.2118/176886-MS
Abstract: Brittleness indices (BI) commonly used in the petroleum industry are based on elastic modulus or mineralogy that can be calculated from well logs. However, they both ignore the effect of confining pressure. Shale is usually distributed at different depth under different confining pressure. Models without considering the influence of confining pressure will directly lead to inaccuracy in BI calculation, thus resulting in the failure of hydraulic fracturing. In this work, we compared confining pressure with rock mechanics parameters and the microcrack quantity of a core, introduced "fracture toughness" to explain how confining pressure influences BI, and finally developed a new model to correct the effect of confining pressure in BI calculation. Fracture toughness is an important parameter that characterizing a rock’s resistance to a fracture. It increases with confining pressure, since an increase of confining pressure may close preexisting cracks and restrict the crack propagation. The results show that BI is usually larger at low confining pressure than at high pressure. Also, higher content in brittle mineral does not necessarily mean brittler. The results calculated by the new model, which considers the influence of Young’s modulus, Poisson’s ratio, tensile strength, confining pressure and fracture toughness in BI calculation, match well with experimental results.
Publisher: SPE
Date: 09-11-2015
DOI: 10.2118/176826-MS
Abstract: Tight oil resources have become increasingly important as massive hydraulic fracturing techniques breakthrough. Water flooding is generally applied to tight oil reservoirs however, the oil recovery achieved by water flooding is quite low. A CO2 miscible flooding process is regarded as a primary enhanced oil recovery (EOR) technique for conventional oil reservoirs as CO2 can extract oil even at a high water cut. Furthermore, many CO2 field trials in low permeability reservoirs have been recorded as successful. As CO2 utilization efficiency drops when formation permeability goes down, CO2 injection in a miscible condition for tight oil exploitation may not be as profitable as that in conventional oil reservoirs. In tight formations, there exist small pore throats, even at nanoscale. As the confined space in nanopores may shift a phase envelop and lower CO2 minimum miscible pressure (MMP), operating a well in a near-miscible region where pressure is slightly less than MMP as measured in the lab may result in a good chance of miscibility for some parts of a tight oil reservoir. In this paper, equations of state (EOS) calculations are conducted in order to see the effects of confinement on a CO2 injection process in tight oil reservoirs. On the basis of Cardium reservoir properties, numerical reservoir simulations are run to investigate the effects of confinement caused by a small pore throat size in 50 nm and 10nm on the CO2 injection process. Comparisons of CO2 near-miscible and miscible processes are made with various pore throat sizes. Results show that confinement effects in tight formations help to lower the bubble point pressure and boost an oil rate during CO2 injection. However, CO2 EOR efficiency goes down as formation pressure approaches MMP as mearsured in the lab. It is not necessary for CO2 injection to operate in an above MMP condition in tight formations, where a nanopore size is present. In this way, the volume of CO2 injected can be reduced. For tight oil reservoirs with a small pore throat size, a CO2 near-miscible process is more suitable than miscible flooding.
Publisher: SPE
Date: 09-11-2015
DOI: 10.2118/177010-MS
Abstract: Brittleness indices (BI) commonly used in the petroleum industry are based on elastic modulus or mineralogy that can be calculated from well logs. However, they ignore the weights of these two factors. Also, it is imprecise to calculate BI by considering quartz (or dolomite) as the only brittle mineral in mineralogy-based BI prediction. Shale gas reservoirs like Eagle Ford are rich in carbonate minerals. If the carbonate minerals are ignored in those reservoirs, the value of BI will be greatly underestimated. On the other hand, brittle minerals like quartz, dolomite and calcite play different roles in BI calculation. If we equally treat them without weighting in BI prediction, the BI being calculated will be inaccurate as well. This paper analyzes the influence of calcite on rock mechanics parameters and BI comparing with quartz and clay. Then new models of BI prediction are built to characterize the weight of each brittle mineral and rock mechanics parameter. Based on the least squares method, optimal values of weight coefficients will be obtained by iteration. The results show that calcite improves rock brittleness and should be considered as a brittle mineral in BI prediction. However, the weight of calcite is less than quartz. From the statistics results, quartz & dolomite & calcite & clay occurs in improving BI. The results also show that Young's modulus plays a more important role in BI prediction than Poisson's ratio.
Publisher: Elsevier BV
Date: 09-2023
Publisher: SPE
Date: 23-09-2019
DOI: 10.2118/195905-MS
Abstract: Progressive Cavity Pumps (PCPs) are the predominant form of artificial lift method deployed by Australian operators in Coal Seam Gas (CSG) wells. With over five thousand CSG wells [1] operating in Queensland's Bowen and Surat Basins, managing and maintaining PCP supported production becomes a significant challenge for operators. Especially when these pumps face regular failures due to the production of coal fines. It is possible to gauge the holistic production performance of PCPs with the aid of real-time data, as this allows for pro-active and informed management of artificially lifted CSG wells. Based on data obtained from two (2) CSG operators, this paper will discuss in detail how features extracted from time series data can be converted to images, which can then aid in autonomously detecting abnormal PCP behavior.
Publisher: European Association of Geoscientists & Engineers
Date: 2019
Publisher: SPE
Date: 17-10-2017
DOI: 10.2118/186433-MS
Abstract: Explored in 1964 and first oil production launched in late 1984, Mereenie oil and gas field is the largest onshore oil field in mainland Australia. Although the production within the Eastern region has been in decline, an appraisal and development drilling project is expected to extend the life of the field. Therefore, a good understanding of dynamic compartmentalization through validation of material balance modeling would address current production planning and monitoring focused in the current oil production formation, Pacoota 3. This study could be the foundation for future development of the western part of the field. Over 30 years of production and an enhanced oil recovery scheme which involved periodic injection from abundant gas within the upper formation, Pacoota 1 the producing oil formation has yet had any in-depth study of a dynamic compartment within the production time scale. The main objective of this study is to provide an analytical framework for dynamic compartmentalization. This framework was developed to capture the complexity in completions strategy and in the injection period. In total, six compartments across the Eastern Pacoota 3 formation were successfully identified and confirmed through modeling. However, uncertainties in structure and limited data at the West have contributed to production simulation's shortcomings. It was found that compartmentalization in Mereenie is a combination of variables those are a natural baffle, fault sealing, injection rate, and drainage radius while structural faults have a primary role in decreasing the permeability and mobility of oil, causing discontinuity throughout the formation.
Publisher: Elsevier BV
Date: 02-2018
Publisher: Springer Science and Business Media LLC
Date: 16-03-2021
Publisher: MDPI AG
Date: 28-04-2022
Abstract: Water-based fracturing fluids are among the most common fluid types used in hydraulic fracturing operations. However, these fluids tend to cause damage in water-sensitive formations. Foam comprises a small amount of base fluid, and compressible gas such as carbon dioxide and nitrogen has emerged as a more ecologically friendly option to fracture such formations. Foam is an attractive option since it has a low density and high viscosity. The applicability of foamed frac fluid is characterized by foam stability and rheology, encompassing the viscosity and proppant carrying ability. The foam quality, pressure and temperature affect the foam rheology. Generally, foam viscosity and stability increase with pressure but decrease when the temperature increases. Hence, it is essential to preserve foam stability in high pressure and high temperature (HPHT) reservoir conditions. The addition of nanoparticles could increase the thermal stability of the foam. This article provides the basis of foam-based fracturing fluid characterization for an optimal application in HPHT reservoir conditions. Then, focusing on improving thermal stability, it reviews the research progress on the use of nanoparticles as foam stabilizing agent. This paper also sheds light on the literature gaps that should be addressed by future research.
Publisher: SPE
Date: 09-11-2015
DOI: 10.2118/176873-MS
Abstract: The success of hydraulic fracturing stimulation is highly reliant on the flow area and permeability of the induced fractures. The flow area can be significantly affected by proppant distribution while fracture permeability is mainly governed by proppant sizes. To create a fracture with a large flow area, small proppants are essential to maintain a minimum proppant settling velocity on the other hand, large proppant sizes provide higher proppant pack permeability (i.e., fracture permeability). Therefore, it is critical to study the effect of proppant on the efficiency of hydraulic fracturing stimulation. In this paper, a 3-D numerical simulator is developed to simulate proppant distribution profile, calculate fracture geometry based on the proppant distribution and forecast productivity through each fracture. More specifically, finite difference method is applied to calculate proppant distribution profile during the hydraulic fracturing and flow back processes for different settings such as proppant size and relative density. Both single-proppant and multi-proppant size combination are investigated and their after-stimulation productivities are compared. Proppant slippage velocity is considered over a wide range of fracturing fluid viscosity and density. Fracture geometry is firstly determined through the hydraulic fracturing operating parameters and then recalculated based on simulated proppant concentration profile. The adjusted fracture geometry is then used to simulate fluid flow from reservoir matrix to the fracture with non-uniform proppant distribution and non-Darcy flow of compressible fluid. Results show that, among all parameters, reservoir permeability mostly affects proppant size selection and pumping scheduling in order to achieve an optimum fracturing performance. Multi-proppant size combination simulation results indicate that properly designed multi-proppant combination treatment can increase after-stimulation productivity and improve fracture performance. There exists an optimum combination of proppants size and their volume portion exists for a specific reservoir. The approach presented here can help further understand proppant transport and settling, fracture geometry variation and fracture production performance.
Publisher: Unconventional Resources Technology Conference
Date: 2019
Publisher: Elsevier BV
Date: 07-2023
Publisher: CSIRO Publishing
Date: 2018
DOI: 10.1071/AJ17047
Abstract: The focus of this paper is an experimental study at room temperature and pressure of free drainage and proppant suspension of four types of designed foams: A, 0.1 wt% regular anionic surfactant mixture B. Foam A + 0.8% SiO2 nanoparticle C, Foam A + 0.36% carboxymethyl hydroxypropyl guar and D. Foam A + 7% NaCl. The results show that SiO2 nanoparticles with surfactant significantly improve the foam stability. In addition, we concluded that better proppant suspension can be achieved by higher viscosity and higher foam stability.
No related grants have been discovered for Maria E Gonzalez Perdomo.