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Johnson, Caroline (Heriot-Watt University–Edinburgh (*Corresponding author) | Sefat, Morteza Haghighat (email: firstname.lastname@example.org)) | Elsheikh, Ahmed H. (Heriot-Watt University–Edinburgh) | Davies, David (Heriot-Watt University–Edinburgh)
Summary In the next decades, tens of thousands of well plugging and abandonment (P&A) operations are expected to be executed worldwide. Decommissioning activities in the North Sea alone are forecasted to require 2,624 wells to be plugged and abandoned during the 10-year period starting from 2019 (Oil&Gas_UK 2019). This increase in decommissioning activity level and the associated high costs of permanent P&A operations require new, fit-for-purpose, P&A design tools and operational technologies to ensure safe and cost-effective decommissioning of hydrocarbon production wells. This paper introduces a novel modeling framework to support risk-based evaluation of well P&A designs using a fluid-flow simulation methodology combined with probabilistic estimation techniques. The developed well-centric modeling framework covers the full range of North Sea P&A well designs and allows for quantification of the long-term (thousands of years) evolution of hydrocarbon movement in the plugged and abandoned well. The framework is complemented by an in-house visualization tool for identification of the dominant hydrocarbon flow-paths. Monte Carlo methods are used to account for uncertainties in the modeling inputs, allowing for robust comparison of various P&A design options, which can be ranked on the basis of hydrocarbon leakage risks. The proposed framework is able to model transient conditions within the well P&A system, allowing for the development of new key performance indicators (e.g., time until hydrocarbons reach surface and changes in hydrocarbon saturation within the P&A well). Such key performance indicators are not commonly used, because most published work in this area relies on steady-state P&A models. The developed framework was used in the assessment of several P&A design cases. The results obtained, which are presented in this paper, demonstrate its value for supporting risk-baseddecision-making by allowing for quantitative comparison of the expected performance of multiple P&A design options for given well/reservoir conditions. The framework can be used for identifying cost-effective, fit-for-purpose P&A designs, for example by optimizing the number, location, and length of wellbore barriers and evaluating the effectiveness of annular cement sheath remedial operations. Additionally, this framework can be used as a sensitivity analysis tool to identify the critical parameters that have the greatest impact on the modeled leakage risks, to guide data acquisition plans and model refinement steps aimed at reducing the uncertainties in key model parameters.
Abdul-Majeed, Ghassan H. (University of Baghdad (Corresponding author) | Arabi, Abderraouf (email: email@example.com. Now with Al-Mashreq University)) | Soto-Cortes, Gabriel (University of Sciences and Technology Houari Boumediene)
Summary Most of the existing slug (SL) to churn (CH) or SL to pseudo-slug (PS) transition models (empirical and mechanistic) account for the effect of the SL liquid holdup (HLS). For simplicity, some of these models assume a constant value of HLS in SL/CH and SL/PS flow transitions, leading to a straightforward solution. Other models correlate HLS with different flow variables, resulting in an iterative solution for predicting these transitions. Using an experimental database collected from the open literature, two empirical correlations for prediction HLS at the SL/PS and SL/CH transitions (HLST) are proposed in this study. This database is composed of 1,029 data points collected in vertical, inclined, and horizontal configurations. The first correlation is developed for medium to high liquid viscosity two-phase flow (μL > 0.01 Pa·s), whereas the second one is developed for low liquid viscosity flow (μL ≤ 0.01 Pa·s). Both correlations are shown to be a function of superficial liquid velocity (VSL), liquid viscosity (μL), and pipe inclination angle (θ). The proposed correlations in a combination with the HLS model of Abdul-Majeed and Al-Mashat (2019) have been used to predict SL/PS and SL/CH transitions, and very satisfactory results were obtained. Furthermore, the SL/CH model of Brauner and Barnea (1986) is modified by using the proposed HLST correlations, instead of using a constant value. The modification results in a significant improvement in the prediction of SL/CH and SL/PS transitions and fixes the incorrect decrease of superficial gas velocity (VSG) with increasing VSL. The modified model follows the expected increase of VSG for high VSL, shown by the published observations. The proposed combinations are compared with the existing transition models and show superior performance among all models when tested against 357 measured data from independent studies.
Summary Two-phase flow is a common occurrence in pipes of oil and gas developments. Current predictive tools are based on the mechanistic two-fluid model, which requires the use of closure relations to predict integral flow parameters such as liquid holdup (or void fraction) and pressure gradient. However, these closure relations carry the highest uncertainties in the model. In particular, significant discrepancies have been found between experimental data and closure relations for the Taylor bubble velocity in slug flow, which has been determined to strongly affect the mechanistic model predictions (Lizarraga-García 2016). In this work, we study the behavior of Taylor bubbles in vertical and inclined pipes with upward and downward flow using a validated 3D computational fluid dynamics (CFD) approach with level set method implemented in a commercial code. A total of 56 cases are simulated, covering a wide range of fluid properties, pipe diameters, and inclination angles: Eo ∈ [10, 700]; Mo ∈ [1×10, 5×10]; ReSL ∈ [–40, 10]; θ ∈ [5°, 90°]. For bubbles in vertical upward flows, the simulated distribution parameter, C0, is successfully compared with an existing model. However, the C0 values of downward and inclined slug flows where the bubble becomes asymmetric are shown to be significantly different from their respective vertical upward flow values, and no current model exists for the fluids simulated here. The main contributions of this work are (1) the relatively large 3D numerical database generated for this type of flow, (2) the study of the asymmetric nature of inclined and some vertical downward slug flows, and (3) the analysis of its impact on the distribution parameter, C0.
Yang, Ruiyue (China University of Petroleum) | Hong, Chunyang (China University of Petroleum) | Huang, Zhongwei (China University of Petroleum) | Wen, Haitao (China University of Petroleum) | Li, Xiaojiang (Sinopec Research Institute of Petroleum Engineering) | Huang, Pengpeng (China University of Petroleum) | Liu, Wei (China University of Petroleum) | Chen, Jianxiang (China University of Petroleum)
Summary Multistage hydraulic fracturing is widely used in developing tight reservoirs. However, the economic and environmental burden of freshwater souring, transportation, treatment, and disposal in hydraulic fracturing operations has been a topic of great importance to the energy industry and public alike. Waterless fracturing is one possible method of solving these water‐related issues. Liquid nitrogen (LN2) is considered a promising alternate fracturing fluid that can create fractures by coupled hydraulic/thermal loadings and, more importantly, pose no threats to the environment. However, there are few laboratory experiments that use LN2 directly as a fracturing fluid. In this work, we examine the performance of LN2 fracturing based on a newly developed cryogenic‐fracturing system under true‐triaxial loadings. The breakdown pressure and fracture morphologies are compared with water fracturing. Moreover, fracture‐initiation behavior under cryogenic in‐situ conditions revealed by cryo‐scanning electron microscopy (cryo‐SEM) is presented, and the role of thermal stress is quantified by a coupled thermoporoelastic‐damage numerical simulation. Finally, the potential application considerations of LN2 fracturing in the field site are discussed. The results demonstrate that LN2 fracturing can lower fracture initiation and propagation pressure and generate higher conductive fractures with numerous thermally induced cracks in the vicinity of the wellbore. Thermal gradient could generate enormously high‐tensile hoop stress and bring about extensive rock damage. Fracture‐propagation direction is inclined to be influenced by the thermal stress. Furthermore, phase transition during the fracturing process and low fluid viscosity of LN2 can also facilitate the fracture propagation and network generation. The key findings obtained in this work are expected to provide a viable alternative for the sustainable development of tight‐reservoir resources in an efficient and environmentally acceptable way.
Summary In this paper, we present two new Lyapunov‐based observers for the decentralized multiphase flow measurement that are based on the interconnections between the two subsystems to precisely estimate the states of the multiphase flow at the gas refinery. Because the system is composed of two interconnected subsystems, the states of the condensate and gas subsystems were separately estimated using the differential mean value theorem (DMVT), the sliding mode observer (SMOU), and the HYSYS® simulator (Hyprotech, Ltd., Calgary, Alberta, Canada) by considering the relationship between two subsystems, designing an observer, and converting the conditions to linear matrix inequality (LMI). Using the HYSYS simulator with the real process data, we found that both the observers are capable of estimating the states with some differences in performance, and the drift flux model (DFM) is sufficient for states estimation of the multiphase flow entering the gas refinery.
Summary The objective of this work is to develop and train feedforward artificial neural networks (ANNs) on the forecasting of layer permeability in heterogeneous reservoirs. The results are validated by comparing the model outputs with permeability curves computed from production logging data. Production logs are used as targets to train the model. A flow‐profile interpretation method is used to compute continuous permeability curves free of wellbore skin effects. In addition, segmentation techniques are applied to high‐resolution ultrasonic image logs. These logs provide not only the image of the mega‐ and giga‐pore system but can also identify the permeable facies along the reservoir. The image segmentation jointly with other borehole logs provides the necessary features for the network training process. The proposed neural network focuses on delivering reliable and validated permeability curves. Its development accounts for formation skin factor, as well as nongeological noise usually found in ultrasonic image logs. The procedure is tested on both synthetic and field data sets. The estimations presented herein demonstrate the model's ability to learn nonlinear relationships between geological input variables and reservoir dynamic data even if the actual physical relationship is complex and not known a priori. Although the preprocessing stages of the procedure involve some expertise in data interpretation, the neural‐network structure can be easily coded in any programming language, requiring no assumptions on physics in advance. For the case studies presented in this work, the proposed procedure provides more accurate permeability curves than the ones obtained from conventional methods, which usually fail to predict the permeability measured on drill‐stem tests conducted in dual‐porosity reservoirs. The novelty of this work is to incorporate dynamic production‐logging (PL) data into the permeability‐estimation workflow. Correction Notice: The preprint paper was updated from its originally published version to correct Fig. 17 on page 11. An erratum detailing the change is included in the Supporting Information section below.
Summary In this study, we investigate the effect of liquid viscosity (μL) on the slug/churn transition in gas/liquid flows in vertical pipes. A total of 80 experimental churn-flow data points from two different sources are compiled as a data set, covering liquid viscosities from 17.23 to 586 mPa·s. Air was used in these studies as a gas phase with two different liquids, aqueous glycerol and a commercial synthetic mineral oil, flowing in vertical pipes of 0.0192- and 0.0508-m inner diameter (ID). The data set is used to examine the existing slug/churn-flow-transition models and provide further insights into the effect of μL on the transition. The existing models are categorized into two groups according to their response of the slug/churn transition to the increase in liquid superficial velocity (Vsl) on the Vsg/Vsl flow map. The first category exhibits a decrease in superficial gas velocity (Vsg) with the increase in Vsl at slug/churn (the transition concave to the left). The other one predicts an increase in Vsg with increasing of Vsl (the transition concave to the right). Analysis of the data set reveals that on the Vsg/Vsl flow map, the slug/churn transition moves toward lower superficial gas velocities as liquid viscosity increases and occurs approximately at a constant Vsg for low to medium Vsl. The predictions of these models were tested against the data set and poor results were shown by most models. The best performance is given by the Abdul-Majeed (1997) model. A dimensional analysis is applied in the present study to develop a new slug/churn-transition model. This analysis indicates that the transition is related to three dimensionless numbers, namely gas- and liquid-phase Froude numbers, in addition to the inverse liquid-viscosity number. An improved revision to the Abdul-Majeed model is achieved using these three dimensionless numbers. The revision enables the model to predict the transition for low, medium, and high liquid viscosity. The revised model clearly outperforms all the existing models for the present data and viscous data from independent studies. Furthermore, the revised model exhibits the expected trend against changes in pipe diameter and gas density.
Summary Capillary end effect (CEE) develops in tight gas and shale formations near hydraulic fractures during flowback of the fracturingtreatment water and extends into the natural-gas-production period. In this study, a new multiphase reservoir-flow-simulation model is used to understand the role the CEE plays on the removal of the water from the formation and on the gas production. The reservoir model has a matrix pore structure mainly consisting of a network of microfractures and cracks under stress. The model simulates highresolution water/gas flow in this network with a capillary discontinuity at the hydraulic-fracture/matrix interface. The simulation results show that the CEE causes significant formation damage during the production period by holding the water saturation near the fracture at higher levels than that using only the spontaneous imbibition of water. The effect makes water less mobile, or trapped, in the formation during the flowback, and tends to block gas flow during the production. The effect during the production is more important relative to the changing stress. We showed that the CEE cannot be removed completely but can be reduced significantly by controlling the production rate. Introduction Hydraulic fracturing is a well-stimulation technique for improved natural-gas production from tight gas and shale formations. However, the implementation of the technique brings in new formation-damage considerations. During the fracturing treatment, a large volume of water is pumped with proppants into the well. The injected water at high pressure applies the downhole force necessary for the fracture creation and growth into the formation. After the treatment, the well is flowed back. Only a small fraction of the injected water can be recovered, however, during the flowback and natural-gas production (Cheng 2012).
Iheobi, Christopher (Hi-Impact Energy Limited, Aberdeen, United Kingdom) | Daramola, Babalola (Propellio Limited, London, United Kingdom) | Alinnor, Chidubem Martins (Chevron Nigeria Limited, Lagos, Nigeria) | Okafor, Ikechukwu Stanley (Nile University of Nigeria, Abuja, Nigeria)
Abstract This paper evaluates the profitability of developing a Nigerian marginal oil field in a low oil price environment. The undeveloped asset is located offshore, and remains undeveloped due to field size and remote location. Recent seismic interpretation suggested that the field could be larger than previous estimates, and this triggered re-evaluation for development. Subsurface and economic assessments were completed to evaluate the profitability of developing the field, and the NPV, profit to investment ratio, DCFR, payback period, and breakeven oil price indicators are presented. The base case development scenario was unattractive, and additional sensitivities were completed to transform the marginal field into an attractive investment. The paper presents standard working practices used to evaluate the profitability of petroleum upstream assets. It also shows why economics is the bottom line of petroleum assets, recommends guidelines for selecting upstream investment projects and participating in petroleum licensing bid rounds, and illustrates how hydraulic fracturing has transformed low permeability oil fields in the USA into economic projects.