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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Guan, Xu (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Zhu, Deyu (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Tang, Qingsong (PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Wang, Xiaojuan (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Wang, Haixia (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Zhang, Shaomin (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Deng, Qingyuan (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Yu, Peng (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Yu, Kai (Exploration and Development Research Institute of PetroChina Southwest Oil & Gasfield Company, Chengdu, China) | Huang, Xingning (Downhole service company of Xibu Drilling Engineering Company Limited, Karamay, China) | Xu, Hanbing (CNPC, International HK LTD Abu Dhabi, Abu Dhabi, UAE)
Abstract In recent years, tight sandstone gas as one of the important types of unconventional resources, has been rapid explored and developed. There are large-scale tight sandstone gas production in Sichuan Basin, Ordos Basin, Bohai Bay Basin, Songliao Basin and other basins, and it has become a key part in the area of increasing gas reserves and production in China. Due to the influence of the reservoir characteristics, tight gas reservoirs have low porosity and permeability, and the tight gas can only be effectively developed by improving the conductivity around the wellbore. Therefore, it is required to perform hydraulic fracturing after the completion of horizontal well drilling to improve the permeability of reservoir. It can be seen that hydraulic fracturing is the core technology for efficient development of tight gas resources. The implementation of hydraulic fracturing scheme directly determines the horizontal well production and EUR. This paper describes the workflow of 3D geomechanical modeling, technical application for Well YQ 3-3-H4 reservoir stimulation treatment, and carries out hydraulic fracture propagation simulation research based on 3D geomechanical model. This paper also compares the micro-seismic data with the simulation results, and the comparison results show that the propagation model is consistent with the micro-seismic monitoring data, which verifies the accuracy of the model. This paper clarifies the distribution law of hydraulic fractures in the three-dimensional space of horizontal wells in YQ 3 block, and the research results can be used to provide guidance and suggestions for the optimization of fracturing design of horizontal wells in tight gas of Sichuan Basin.
Abstract The deep shale gas reservoir are high formation temperature and pore pressure in Sichuan Basin. Due to the unclear geomechanical characteristics of the reservoir, a large number of accidents occurred during the drilling operation. At the same time, the wellbore instability and frequent adjustment trajectory cause long drilling cycle, low drilling efficiency, and high drilling operation cost. To solve the above problems, the drilling mud weight is optimized based on the three-dimensional geomechanical research and by establishing the pore pressure, collapse pressure and fracture pressure (leakage pressure) models. The key technology of reducing drilling mud weight are used to significantly reduce the drilling mud loss. Field application shows that the mud weight is reduced from 2.15 g/cm to 1.87 g/cm, the average ROP increased by 44.1% from 8.4 m/h to 12.1 m/h, the average drilling operation cycle decreased by 40.7% from 54.2 days to 32.1 days, and the drilling performance and efficiency are significantly improved. The fine 3D geomechanical modeling technology has great promotion and reference significance for the performance and efficiency improvement of the deep shale gas horizontal well drilling operation in China.
Al-Obaid, Hashem (Saudi Aramco, Dhahran, Eastern Province, Saudi Arabia) | Al-Mulhim, Bassam (Saudi Aramco, Dhahran, Eastern Province, Saudi Arabia) | Ashby, Scott (Saudi Aramco, Dhahran, Eastern Province, Saudi Arabia) | Alyousef, Abdulmuin (Completion Energy, Dhahran, Eastern Province, Saudi Arabia)
Abstract Plug and perf technique is a common method to unlock the potential of tight gas formations. The conventional method is to set millable plugs to establish zonal isolation between target stages. A new degradable frac plug has been introduced for high pressure and high temperature applications in sandstone formations plug and perf hydraulic fracturing operations. The development and deployment of the degradable frac plugs that are capable of holding 32 hours of targeted pressure to optimize the cost and time of the conventional well intervention in tight gas reservoirs in Saudi Arabia is presented in this paper. In conventional plug and perf stimulation operations each plug is milled out via coiled tubing. This process increases operational risk and cost associated with multiple downhole trips. Another challenge is wellbore accessibility post stimulation operations. Without changing the fracturing design, two degradable plugs in a three-stage well were deployed. Downhole conditions presented significant challenges including high temperatures of 285 F and pressures. By using a degradable plug, post-frac interventions can be eliminated as the entire plug will degrade in downhole conditions. This would allow the well to be brought online faster than a conventional method would allow. Operational challenges have been experienced during the first deployment of the plug. The plug has successfully held pressure for 32 hours while being exposed to wellbore fluids, which is one of the longest times achieved for a degradable frac plug. One of the main reasons of such success is that the plug is composed of high-grade material. While the plug maintained its integrity for 32 hours in high pressure, it degraded to fine particles post frac operations. Furthermore, the plug was trial tested without affecting the stimulation goals or the overall operation for such well. On this trial test, the plug has shown the ability to eliminate HPCT trips and the associated risks of HPCT intervention. To confirm dissolution of the plugs, an assessment CT run was performed and confirmed shallower plug was not dissolved after 32 hours while the deeper plug already dissolved. With the spread of plug and perf technology on a global level and the increase of horizontal multistage stimulation methods, it is important to capitalize on fit for purpose technologies versus a one-size fits all approach. To address the challenges associated with longer laterals and increasing stage counts, degradable plug technology can be used to improve well economics and reduce associated risks. The elimination of mechanical intervention is the next breakthrough in efficiency gains to increase laterals and achieve higher stage counts.
Perozo, N. (Institute of Subsurface Energy Systems, Clausthal University of Technology, Clausthal-Zellerfeld, Lower Saxony, Germany) | Amirhosseini, S. Fazel (Institute of Subsurface Energy Systems, Clausthal University of Technology, Clausthal-Zellerfeld, Lower Saxony, Germany) | Tavakoli, M. (Institut für Materialprüfung und Werkstofftechnik Dr. Neubert GmbH, Clausthal-Zellerfeld, Lower Saxony, Germany) | Holzmann, J. (Institute of Subsurface Energy Systems, Clausthal University of Technology, Clausthal-Zellerfeld, Lower Saxony, Germany) | Neubert, V. (Institut für Materialprüfung und Werkstofftechnik Dr. Neubert GmbH, Clausthal-Zellerfeld, Lower Saxony, Germany) | Jaeger, P. (Institute of Subsurface Energy Systems, Clausthal University of Technology, Clausthal-Zellerfeld, Lower Saxony, Germany)
Abstract The main objective of the presented work is to evaluate the effect of hydrogen service conditions on the mechanical properties of API steel grades used for well completions. The evaluation methodology implies a preconditioning of the steel specimens to long-term exposures under high-pressure hydrogen atmospheres and compare the results of subsequent mechanical tests with those of steels not being exposed to this gas. The aim of this research is to compare the performance of different API grades when subjected to hydrogen service. The outcomings of the study will help to evaluate long-term integrity of completion systems and materials compatibility for hydrogen storage applications. Mechanical tests like notched-tensile tests, hardness determination and impact tests were performed, in order to detect the embrittlement of the metals by comparing results between specimens not previously charged with hydrogen and specimens being subjected to a hydrogen atmosphere under high-pressure. The notch tensile specimens were pre-stressed to 80% of the nominal yield strength, in order to force and assure the hydrogen diffusion into the notch area where localized increased tensile stresses are concentrated. Furthermore, by means of carrier gas hot extraction analysis the hydrogen content in the samples was measured, to give an indication of the absorption capacity of these grades under the stated conditions. The API grades L80, P110 and Q125 have been selected to represent a wide and popular selection of ductility and yield strength. All samples were subjected to a series of mechanical tests to determine the presence of hydrogen embrittlement. The results show different behavior of the materials after being exposed to a hydrogen atmosphere, from the noticeable decrease to even a "no effect" on the mechanical properties. The results of notch tensile tests of the steels L80 and Q125 are showing some level of hydrogen embrittlement, compared to P110, being the one least affected by the presence of this gas. The measurement of hydrogen content in the samples delivers similar results for all the grades. Microscopic analysis shows the structure of the crystal lattice of the steels studied, helping to understand, together with the state of stress, how sensitive the material is to be affected by hydrogen embrittlement. There is no literature that describes the hydrogen effect on the mechanical properties of API steels used for tubings and casings in well completions, nor their sensitivity to hydrogen embrittlement. The results of this research are of great importance to give an idea of the compatibility of the steels that can be used for high-pressure hydrogen operations, such as hydrogen underground storage as well as to evaluate the potential recompletion or use of existing wells.
Abstract Nowadays, the only economic and effective way to exploit shale reservoirs is multi-stage fracturing of horizontal wells. The backflow after fracturing affects the damage degree of a fracturing fluid to a formation and fracture conductivity, and directly influences a fracturing outcome. At present, the backflow control of the fracturing fluid mostly adopts empirical methods, lacking a reliable theoretical basis. Therefore, it is of positively practical significance to reasonably optimize a flowback process and control the flowback velocity and flowback process of a fracturing fluid. On the other hand, the previous research on the productivity of multi-stage fracturing horizontal wells after fracturing is limited, and an equation derivation process has been simplified and approximated to a certain extent, so its accuracy is significantly affected. Based on previous studies, this paper established a new mathematical model. This model optimizes the flowback velocity after fracturing by dynamically adjusting a choke size and analyzes and predicts the production performance after fracturing. To maximize fracture clean-up efficiency, this work builds the model for a dynamic adjustment of choke sizes as wellhead pressure changes over time. It uses a two-phase (gas and liquid) flow model along the horizontal, slanted and vertical sections. The forces acting on proppant particles, filtration loss of water, the compressibility of a fracturing fluid, wellbore friction, a gas slippage effect, water absorption and adsorption are simultaneously considered. With the theories of mass conservation, we build a mathematical model for predicting production performance from multi-fractured horizontal wells with a dynamic two-phase model considering dual-porosity, stress-sensitivity, wellbore friction, gas adsorption and desorption. In this model, the gas production mechanisms from stimulated reservoir volume and gas and water relative permeabilities are employed. Based on shale reservoir parameters, wellhead pressure, a choke size, a gas/liquid rate, cumulative gas/liquid production, cumulative filtration loss and a flowback rate are simulated. In the simulations, the influential factors, such as shut-in soak time of the fracturing fluid, forced flowback velocity, fracturing stages and fracture half-length after fracturing, are studied. It is found by comparison that in the block studied, when a well is shut in four days after fracturing, the dynamic choke size is adjusted with wellhead pressure changing over time, the fracturing stage is 11, and the fracture half-length is 350 meters, the fracture conductivity after flowback is the largest, and the productivity of the horizontal well is the highest.
Abstract Routinely analyzing producing well performance in unconventional field is critical to maintain their profitability. In addition to continuous analysis, there is an increasing need to develop models that are scalable across entire field. Pure data-driven approaches, such as DCA, are prevalent but fail to capture essential physical elements, compounded by lack of key operational parameters such as pressures and fluid property changes across large number of wells. Traditional models such as numerical simulations face a scalability challenge to extend to large well counts with rapid pace of operations. Other widely used method is rate transient analysis (RTA), which requires identification of flow regimes and mechanistic model assumptions, making it interpretive and non-conducive to field-scale applications. The objective in this study is to build data-driven and physics-constrained reservoir models from routine data (rates and pressures) for pressure-aware production forecasting. We propose a hybrid data-driven and physics informed model based on sparse nonlinear regression (SNR) for identifying rate-pressure relationships in unconventionals. Hybrid SNR is a novel framework to discover governing equations underlying fluid flow in unconventionals, simply from production and pressure data, leveraging advances in sparsity techniques and machine learning. The method utilizes a library of data-driven functions along with information from standard flow-regime equations that form the basis for traditional RTA. However, the model is not limited to fixed known relationships of pressure and rates that are applicable only under certain assumptions (e.g. planar fractures, single-phase flowing conditions etc.). Complex, non-uniform fractures, and multi-phase flow of fluids do not follow the same diagnostics behavior but exhibits more complex behavior not explained by analytical equations. The hybrid SNR approach identifies these complexities from combination of the most relevant pressure and time features that explain the phase rates behavior for a given well, thus enables forecasting the well for different flowing pressure/operating conditions. In addition, the method allows identification of dominant flow regimes through highest contributing terms without performing typical line fitting procedure. The method has been validated against synthetic model with constant and varying bottom hole pressures. The results indicate good model accuracies to identify relevant set of features that dictate rate-pressure behavior and perform production forecasts for new bottom-hole pressure profiles. The method is robust since it can be applied to any well with different fluid types, flowing conditions and does not require any mechanistic fracture or simulation model assumptions and hence applicable to any reservoir complexity. The novelty of the method is that the hybrid SNR can resolve several modes that govern the flow process simultaneously that can provide physical insights on the prevailing multiple complex flow regimes.
Abstract Oil production via horizontal wells with multistage fracture stimulation treatment completions in the Bakken shale of North Dakota and Montana began in 2003. Since then, over 19,000 Bakken shale horizontal wells have been completed and placed into production. Oil production from horizontal Bakken shale oil wells peaked in November 2019 at 1.5 million barrels/day, and is at about 1.2 million barrels/day as of September, 2022 (EIA). There have been several shale oil EOR tests conducted over the last several years, involving the injection of water, CO2 and natural gas. This paper builds upon shale EOR modeling work described in a 2019 NETL report. In that report, a compositional simulation model of the Bakken was constructed, and a production history match on primary oil, gas and water production from a group of wells was obtained. The match model was then used to evaluate the enhanced oil recovery via cyclic injection of CO2, dry gas, and wet gas. This paper utilizes some data from that report to assess two novel, proprietary shale oil EOR processes in the Bakken, in the same area of the Williston Basin. The paper illustrates how these proprietary shale oil EOR processes may be implemented at lower BHP to mitigate interwell communication, while enabling greater oil recovery than via injection of water, CO2 or natural gas. Compositional reservoir simulation modeling of the two novel EOR processes in the modeled Bakken shale wells indicates potential incremental oil recoveries of 200% and 300% of primary EUR may be achieved. The two novel shale oil EOR methods utilize a triplex pump to inject a liquid solvent having a specific composition into the shale oil reservoir, and a method to recover the injectant at the surface, for storage and reinjection. One of the processes enables further enhanced oil recovery via cyclic fracture stimulation at the start of the EOR process. The processes are fully integrated with compositional reservoir simulation to optimize the recovery of residual oil during each injection and production cycle. The patent pending shale oil EOR processes have numerous advantages over cyclic gas injection - shorter injection time, longer production time, smaller, lower cost injection volumes, no gas containment issue - much lower risk of interwell communication, elimination of the need to buy and sell injectant during each cycle, much better economics, scalability, faster implementation, optimization via integration with compositional reservoir simulation modeling, and lower emissions. If implemented early in the well life, their application may preclude the need for artificial lift, to produce more oil sooner, resulting in a shallower decline rate and higher reserves.
Abstract The development of shale plays requires accurate forecasting of production rates and expected ultimate recoveries, which is challenging due to the complexities associated with production from hydraulically fractured horizontal wells in unconventional reservoirs. Traditional empirical models like Arps decline are inadequate in capturing these complexities, and long-term forecasting is hindered by the challenges posed by 3 phase flow. In response, a new physics-augmented, data-driven forecasting method has been proposed that efficiently captures these complexities. The proposed PI-based forecasting (PIBF) method combines data-driven techniques with the physics of propagation of dynamic drainage volume under transient flow conditions observed by unconventional wells for a prolonged period. The model requires only routinely measured inputs such as production rates and wellhead pressure, and efficiently captures the trend shift in gas-to-oil ratio caused by free gas liberation in the near-wellbore region. By using material balance and productivity index models, the proposed approach can forecast well performance and handle changing operational conditions during the well's lifecycle. Compared to existing empirical or analytical methods like Arps decline and RTA, the proposed method yields more accurate forecasting results, while still using easily available inputs. Empirical methods like Arps decline have low input requirements but lack physical insights, leading to inaccuracies and inability to handle changing operational conditions. Pure physics-based methods like RTA and reservoir simulation require more input properties that are often difficult to obtain, resulting in a low range of applicability. Overall, the proposed method offers a promising alternative to existing methods, effectively combining data-driven techniques with physics-based insights to accurately forecast well performance and handle changing operational conditions in unconventional reservoirs.
Fadairo, Adesina Samson (University of North Dakota, United States) | Egenhoff, Sven (University of North Dakota, United States) | Adeyemi, Gbadegesin Abiodun (University of North Dakota, United States) | Ling, Kegang (University of North Dakota, United States) | Tomomewo, Olusegun Stanley (University of North Dakota, United States) | Oladepo, Adebowale David (Circular One Resources, United States) | Oni, Opeyemi (University of North Dakota, United States) | Nwaokwu, Richmond Nduka (Litewell Completions Services Limited, Nigeria)
Abstract Multi-fractured horizontal wells have been an admirable completion technique for unconventional resources such as in Tuscaloosa Marine shale (TMS) and Eagle Ford Shale (EFS) plays located in the United States. Studies have shown that the productivity of multi-fractured wells of these two shale plays are majorly based on the fracture conductivity, which may be dependent on the type of the geometrical shape of the fractures connecting the fluid to the well. A reliable model is desirable to the operator to accurately capture the productivity of multi-fractured shale wells. Several mathematical models have been adopted with various assumptions that include simple slot geometry for fracture shape in the derivation of production rate models. These assumptions significantly simplify the existing model's applications but limit the efficiency of the models to accurately predict the fluid production rate. Failure to utilize an elliptical fracture shape and a correct drive mechanism-based model for analyzing flow rate have been considered as a vital reason for the disparity between the calculated results by the past investigators and the exact values obtained from TMS and EFS field measurements. In this study, an elliptical model based on the fracture geometry has been derived to analyze the productivity of multi-fractured shale wells considering the accurate drive mechanism for the shale play. The model validation has been achieved using field data from the Tuscaloosa Marine shale (TMS) and the Eagle Ford Shale (EFS) plays. The results generated from the newly improved model resulted in more accurate outcomes when compared with results presented by Yang and Guo (2019) and Guo and Schechter (1997); all these authors assumed the cross-sectional area of the induced fractures as being a slot showed nonconformity using real life values from the Tuscaloosa Marine shale (TMS) and the Eagle Ford Shale (EFS) plays as benchmarks. The newly improved model reduces the prediction percentage error to 0.55% and 0.43% compared to the percentage error reported by Yang and Guo (2019) as 9.1% and 3.5% and by Guo and Schechter (1997) respectively as 29.7% and 47.2 % using the actual oilfield results as their benchmark. The accurate prediction of the long-term productivity of multi-fractured oil shale depends on the ability to determine fracture geometry and the drive mechanisms that dominantly control flow in the shale play considered. Sample calculations of flow rate of the two fields considered and the controllable parameters influencing the flow rate have also been identified. The study would serve as a tool for accurate assessment of flow rate in multi-fractured wells of shale plays and analyzes its performance.
Vo, Hai (Chevron Technical Center) | Flodin, Eric (Chevron Southern Africa Strategic Business unit) | Hui, Robin (Chevron Technical Center) | Earnest, Evan (Chevron Technical Center) | Trindade, Marcia (Chevron Southern Africa Strategic Business unit)
Abstract Coning is the mechanism describing movement of water from an aquifer and/or gas from gas-cap into the perforations of a producing well. The interface between the fluid phases deforms into a cone shape if the reservoirs are relatively homogeneous. In fractured reservoirs, water/gas incursions can take the form of discrete channels through fractures that connect the water/gas zone to the wellbore. Coning/channeling tends to increase the cost of production operations and influences the overall recovery efficiency of oil reservoirs. The coning/channeling processes constitute one of the most complex problems pertaining to oil production. This study investigates coning/channeling in an Atlantic margin pre-salt fractured carbonate reservoir using Embedded Discrete Fracture Modeling (EDFM) to gain a better understanding of the processes in fractured reservoirs. This study focused on a sector Discrete Fracture Network (DFN) that was used to create a full-field Dual Porosity-Dual Permeability (DPDK) model. The DFN was used to generate end member models that capture the range of connectivity, geometry, and heterogeneity of fracture systems thought to exist in the field based on well log and core analysis. The sector area of interest also included existing producers and injectors and future infill wells. The coning/channeling phenomena were modeled using the EDFM method. The models were flow simulated using representative initialization, field management logic, and well producing rules, based on the history-matched full-field DPDK model. Mitigation methods to reduce coning impacts were also investigated. EDFM, which represents the fracture network explicitly, provides insight on gas and water coning/channeling processes in a fractured carbonate reservoir. We find that fractures can lead to local channeling and coning. The degree of channeling and coning is a function of flow rates, fracture properties, and matrix-fracture exchange which in turn depends on rock property contrast between matrix and fractures. If matrix permeability is sufficiently high, matrix-fracture exchange is significant and fractures can act like leaky pipes. The effect of local gas coning/channeling is stronger in cases of isolated fractures surrounded by lower permeability rock. Water and gas coning can occur at the same time and interact with each other. Mitigation methods such as reducing well rates and use of selective completions can be applied to manage the gas and water coning/channeling.