bluuebunny/crossref_metadata_2025_split huggingface dataset:
Quantifying Geological Uncertainty for Complex Integrated Production Systems with Multiple Reservoirs and Production Networks
Authors: Pathak Varun , Hamedi Yousef , Martinez Oscar , Vermeulen Stephen , Kumar Anjani 
Published: April 2019

Abstract
Integrated production systems models are very valuable for predicting the performance of complex systems containing multiple reservoirs and networks. In addition, the value of quantifying uncertainty in reservoirs and production systems is immense as it can build confidence in operational investments. However, traditionally it has been extremely tedious to incorporate uncertainty assessments in the context of integrated production systems modelling. This has been addressed in the current work with the help of a case study.
In the current work, a complex integrated production systems model is presented - from Pre-Salt carbonates reservoir offshore of Brazil. The model includes multiple reservoirs with unique fluid types and complex fluid blending in the production network, multiphase and thermal effects in flowlines and risers, gas separation, gas processing, gas compression, and re-injection for either pressure maintenance or for miscible EOR.
The operational strategies, well placement, and well and network configurations are often based on a single geological realization. With the case study presented in this paper, an integrated way of quantifying geological uncertainty has been presented. A new multi-user, multi-disciplinary tool was used for this study that removed any discontinuities and inconsistencies that typically occur in such projects when multiple standalone tools are used for individual tasks. When quantifying uncertainty on production, the dependence on a single realization was eliminated as uncertain parameters were identified and used for creating robust probabilistic forecasts. Probability distribution curves were generated to represent the uncertainty in overall production from this asset, and the risk associated with operational investments was minimized.
Typically, an end-to-end uncertainty assessment is missing from the traditional Integrated Modelling workflows. With this new approach, the challenge of achieving a truly integrated uncertainty assessment for integrated reservoir and production models has been addressed successfully.
Advanced Modeling of Horizontal Well Performance Under Different Re-fracturing Designs in Tight Oil Reservoir
Authors: Lei Zhengdong , Yang Xinping , Li Xiaoshan , Hu Die , Wu Yushu , Peng Yan 
Published: April 2019

Abstract
Re-fracturing of a horizontal well is a method to restore the productivity of the well in unconventional reservoirs after the expected production decline. Consequently, a re-fracturing approach may be necessary to improve/enhance production and ultimate recovery. However, there are many challenges for optimizing re-fracturing treatment design, due to lack accurate quantification of depletion-induced pressure and local stress change around fractures. The workflow presented can be applied to study and optimize a re-fracturing job to prevent potentially catastrophic fracture hits during re-fracturing operations.
In this paper, an integrated re-fracturing workflow was created and applied to determine the optimum re-fracturing strategy for multi-wells pad. This comprehensive workflow represents a multidisciplinary approach that integrates complex hydraulic fracture models, geomechanical models, and multi-well production simulation. The approach is able to couple simulated 3D reservoir pressure with a geomechanical model to quantify depletion-induced stress and pressure field change. Then, the altered stress field is utilized as the input for modeling the new fracture system created by the re-fracturing treatment. Two field cases from a tight oil reservoir are evaluated by comparing the model prediction to the pressure response. The model prediction agrees well with the observed pressure response and surface tiltmeter observations. The synthetic cases of interference between wells due to stresses and fracture design (number, placement and timing) are investigated in this work. A systematic sensitivity study is performed on the effects of re-fracturing time, fracturing spacing.
It is shown that quantification of stress field changes during reservoir depletion provides new insights for the design and evaluation of re-fracturing treatments to enhance field development. There is a critical time in the life of the well that protection refrac could help pressurizing the formation directly by increasing pore pressure through fluid injection and indirectly by mechanical dilation of existing fractures. The dynamic changes of stress field can guide the optimization of re-fracturing mode and zipper fracturing to reduce stress shadow effect. The dynamic change of the pressure field optimizes the fracturing fluid volume, which can increases the volume of the fracture transformation and supply formation energy.
The paper presents aN approach in calculating stress changes and dynamic fracture propagation into depleted region over time. Results obtained by this study give better understanding about propagation of new fractures as well as old fractures in re-fracturing process.
Developing a Methodology for Improved Reservoir Management: A Journey from Characterization to Simulation and Back
Authors: Mishra Shubham , Shrivastava Chandramani , Ojha Aditya , Miotti Fabio 
Published: April 2019

Abstract
An important aspect of reservoir management process is monitoring and revising plans and an essential component of reservoir management strategy is integration of technologies (Satter et al. 1994). In revisions of reservoir management plans, very rarely do operators incorporate any other data than the data from newly drilled wells and the field production in between the revisions. Any inference in the inter-well space is an interpolation between the well data, as surface seismic is limited by its resolution, as the calibration data is available only at well level. For an effective reservoir management, especially in the decline phase of the field, a logical integration of technologies to capture maximum heterogeneity in the interwell space can be very advantageous.
Crosswell technologies, that provide high resolution data between a set of wells, but if used individually, are essentially limited to a very small part of the field having multiple wells. Therefore, in order to monitor and revise reservoir management plans, it is important that such technologies are integrated with full-field solutions. This paper describes a methodology that aims to better manage reservoir by logically integration the 3D reservoir model- a full-field solution- and crosswell electromagnetics/crosswell seismic- an interwell solution.
The Feasibility Appraisal for CO2 Injection and Storage in Condensate Gas Reservoir: Mechanism Studies and Case Analysis
Authors: Jia Ying , Shi Yunqing , Huang Lei , Yan Jin , Sun Lei 
Published: April 2019

Abstract
The YKL condensate gas reservoir is one of the biggest condensate gas reservoirs in China and has been developed more than 10years. At present, the combination of subdivision layer, production speed optimization and horizontal well drilling has been the key to economically unlocking the vast reserves of the YKL condensate gas. The primary recovery factor, however, remains rather low due to high capillary trapping and water invasion. While primary depletion could result in low gas recovery, CO2 flooding provides a promising option for increasing the recovery factor.
The objective of this work is to verify and evaluate the effect supercritical CO2 on enhancing gas recovery and analyze the feasibility of CO2 enhance gas recovery (CO2 EGR) of condensate gas reservoir.
Firstly, novel phase behavior experimental procedures and phase equilibrium evaluation methodology for gas-condensate phase system mixed with supercritical CO2 with high temperature were presented. A unique phase behavior phenomena was also reported. Then, CO2 floodingmechanism in condensate gas reservoir was analyzed and clarified based on experiments. Finally, a series of numerical simulation work were conducted as an effective and economical means to maximize natural gas recovery with the lowest CO2 breakthrough by varying strategies, including CO2 injection rate, injection composition, andinjection timing. Meanwhile the CO2 storage volumes of different strategies were calculated.
The results show that higher gas recovery factor can be achieved with CO2 injection through appearing interphase between two fluids, maintaining reservoir pressure, driving gas like "cushion" and controlling water invasion. All strategies have moderate to significant effects on gas production. The control of injection and production ratio needs to be balanced between pressure transient and CO2 breakthrough over the producer to obtain the maximum gas production. The varying injection pressure shows a positive effect of enhancing gas production. Numerical simulation indicated that the recovery of gas reservoir was improved by around 10 percent. The total CO2 storage would be around 30-40% HCPV.
The research showed that CO2 flooding presents a technically promising method for recovering the vast condensate gas while extensively reducing greenhouse gas emissions.
Risk Assessment and Simulation of Injectivity Decline Under Uncertainty
Authors: Chiotoroiu Maria-Magdalena , Clemens Torsten , Zechner Markus , Hwang Jongsoo , Sharma Mukul M. , Thiele Marco 
Published: April 2019

Abstract
Waterflooding can lead to substantial incremental oil production. Implementation of water injection projects requires the project to fit into the risk (defined here as negative outcomes relative to defined project objectives) and uncertainty (defined here as inability to estimate a value precisely) a company is willing to take.
One of the key risks for water injection into a shallow reservoir is injection induced fractures extending into the caprock. If this risk is seen as "Intolerable" in an As Low As Reasonable Practicable (ALARP) analysis a decision may be made to not proceed with the project., In this study we evaluated caprock integrity by conducting simulations of long-term water injection that include the effects of formation damage caused by internal/external plugging, geomechanical stress changes and fracture propagation in the sand and bounding shale.
The risk of fracture growth into the caprock was assessed by conducting Monte-Carlo simulations considering a set of modelling parameters each associated with an uncertainty range. This allowed us to identify the range of operating parameters where the risk of fracture height growth was acceptable. Our simulations also allowed us to identify important factors that impact caprock integrity. To cover the uncertainty in geomechanical reservoir evaluation, the operating envelope is identified such that the risk of the caprock integrity is reduced. This requires introducing a limit for the Bottom Hole Pressure (BHP) including a safety margin.
The limit of the BHP is then used as a constraint in the uncertainty analysis of water injectivity. The uncertainty analysis should cover the various development options, the parametrisation of the model, sampling from the distribution of parameters and distance-based Generalized Sensitivity Analysis (dGSA) as well as probabilistic representation of the results.
The dGSA can be used to determine which parameter has a strong impact on the BHP and hence the project and should be measured if warranted by a Value of Information analysis.
The final development option to be chosen depends on a traditional NPV analysis.
Predicting the Performance of Tight Gas Reservoirs
Authors: Alem Mehdi , Baig Tarik , Muggeridge Ann , Jones Alistair 
Published: April 2019

Abstract
Engineers need to predict the production characteristics from hydraulically fractured wells in tight gas fields. Decline curve analysis (DCA) has been widely used over many years in conventional oil and gas fields. It is often applied to tight gas, but there is uncertainty regarding the period of production data needed for accurate prediction.
In this paper decline curve analysis of simulated production data from models of hydraulically fractured wells is used to to develop improved methods for calibrating decline curve parameters from production data. The well models were constructed using data from the Khazzan field in Oman. The impact of layering, permeability and drainage area on well performance is also investigated. The contribution of each layer to recovery and the mechanisms controlling that contribution is explored.
The investigation shows that increasing the amount of production data used to fit a hyperbolic decline curve does not improve predictions of recovery unless that data comes from many years (20 years for a 1mD reservoir) of production. This is because there is a long period of transient flow in tight gas reservoirs that biases the fitting and results in incorrect predictions of late time performance. Better predictions can be made by estimating the time at which boundary dominated flow is first observed (tb), omitting the preceding transient data and fitting the decline curve to a shorter interval of data starting at tb. For single layer cases, tb can be estimated analytically using the permeability, porosity, compressibility and length scale of the drainage volume associated with the well. Alternatively, tb can be determined from the production data allowing improved prediction of performance from 2-layer reservoirs provided that a) there is high cross-flow or b) there is no cross-flow and the lower permeability layer either does not experience BDF during the field life time or it is established quickly.
Alkali Co-Solvent Polymer Flooding of High TAN Number Oil: Using Phase Experiments, Micro-Models and Corefloods for Injection Agent Selection
Authors: Schumi Bettina , Clemens Torsten , Wegner Jonas , Ganzer Leonhard , Kaiser Anton , Hincapie Rafael E. , Leitenmüller Verena 
Published: April 2019

Abstract
Chemical Enhanced Oil Recovery leads to substantial incremental costs over waterflooding of oil reservoirs. Reservoirs containing oil with a high Total Acid Number (TAN) could be produced by injection of alkali. Alkali might lead to generation of soaps and emulsify the oil. However, the generated emulsions are not always stable.
Phase experiments are used to determine the initial amount of emulsions generated and their stability if measured over time. Based on the phase experiments, the minimum concentration of alkali can be determined and the concentration of alkali above which no significant increase in formation of initial emulsions is observed.
Micro-model experiments are performed to investigate the effects on pore scale. For injection of alkali into high TAN number oils, mobilization of residual oil after waterflooding is seen. The oil mobilization is due to breaking-up of oil ganglia or movement of elongated ganglia through the porous medium. As the oil is depleting in surface active components, residual oil saturation is left behind either as isolated ganglia or in down-gradient of grains.
Simultaneous injection of alkali and polymers leads to higher incremental oil production in the micro-models owing to larger pressure drops over the oil ganglia and more effective mobilization accordingly.
Core flood tests confirm the micro-model experiments and additional data are derived from these tests. Alkali co-solvent polymer injection leads to the highest incremental oil recovery of the chemical agents which is difficult to differentiate in micro-model experiments. The polymer adsorption is substantially reduced if alkali is injected with polymers compared with polymer injection only. The reason is the effect of the pH on the polymers. As in the micro-models, the incremental oil recovery is also higher for alkali polymer injection than with alkali injection only.
To evaluate the incremental operating costs of the chemical agents, Equivalent Utility Factors (EqUF) are calculated. The EqUF takes the costs of the various chemicals into account. The lowest EqUF and hence lowest chemical incremental OPEX are incurred by injection of Na2CO3, however, the highest incremental recovery factor is seen with alkali co-solvent polymer injection. It should be noted that the incremental oil recovery owing to macroscopic sweep efficiency improvement by polymer needs to be taken into account to assess the efficiency of the chemical agents.
An Efficient Mimetic Finite Difference Method For Multiphase Flow In Fractured Reservoirs
Authors: Zhang Na , Abushaikha Ahmad Sami 
Published: April 2019

Abstract
Modelling fluid flows in fractured reservoirs is crucial to many recent engineering and applied science research. Various numerical methods have been applied, including finite element methods, finite volume methods. These approaches have inherent limitations in accuracy and application. Considering these limitations, in this paper, we present a novel mimetic finite difference (MFD) framework to simulate two phase flow accurately in fracture reservoirs.
A novel MFD method is proposed for simulating multiphase flow through fractured reservoirs by taking advantage of unstructured mesh. Our approach combines MFD and finite volume (FV) methods. Darcy's equation is discreted by MFD method, while the FV method is used to approximate the saturation equation. The resulting system of equations is then imposed with suitable physical coupling conditions along the matrix/ fracture interfaces. This coupling conditions at the interfaces between matrix and fracture flow involve only the centroid pressure of fractures, which brings some simplification in analysis. The proposed approach is applicable for three dimensional systems. Moreover, it is applicable in arbitrary unstructured gridcells with full-tensor permeabilities. Some examples are implemented to show the performance of MFD method. The results showed a big potential of our method to simulate the flow problems with high accuracy and application.
Field Applications of Constrained Multiwell Deconvolution
Authors: Jaffrezic V. , Razminia K. , Cumming J. , Gringarten A. C. 
Published: April 2019

Abstract

Objectives/Scope
This paper applies a new constrained multiwell deconvolution algorithm to two field cases: a gas reservoir with two producers, and an oil reservoir with three producers and one injector. Responses given by the constrained multiwell deconvolution are compared with simulations from history-matched reservoir models.

Methods, Procedures, Process
Permanent downhole pressure gauges are routinely installed in most new wells. The resulting large datasets are usually underexploited, however, because it is near impossible to extract information with conventional techniques in the case of well interferences. Multiwell deconvolution (Levitan, 2006; Cumming et al., 2013) solves this problem by providing constant-rate derivative responses of individual wells as if they were producing alone, and interference effects from any one well to any other. The deconvolved responses have the same durations as the corresponding pressure histories, and show features not visible in any of the test build up or drawdown periods.

Results, Observations, Conclusions
The published multiwell deconvolution algorithms are extensions of the single-well deconvolution algorithm from von Schroeter et al. (2001, 2004), which has become an essential component of the well test analysis toolbox. The Cumming et al. (2013) multiwell deconvolution algorithm has been successfully applied to a North Sea reservoir by Thornton et al. (2015). Multiwell deconvolution, however, is strongly overdetermined and the algorithm may not converge to the true solutions. It may also yield solutions that can reproduce pressure histories equally well while being non-physical. This is especially true when dealing with real field data that may be affected by noise on pressure and rate data. In order to reduce non-uniqueness and ensure physically feasible results, Cumming et al. (2019) incorporated additional constraints on the shapes of the deconvolved derivatives to discourage non-physical solutions. They also introduced additional knowledge on the reservoir, for instance, if it is a closed system, all deconvolved derivatives should tend towards a common unit slope at some future time. They illustrated the application of their enhanced algorithm with synthetic examples with known solutions involving up to nine wells. In this paper, the constrained multiwell algorithm is successfully applied to both a gas and an oil reservoir.

Novel/Additive Information
By extracting well and interwell reservoir signatures, multiwell deconvolution allow identification of compartmentalization or unanticipated heterogeneities very early in field life, making it possible to adjust the field development plan and the locations of future wells. In addition, it can accelerate the history-matching process by doing it on constant rate pressure responses rather than on complex production histories. An added advantage is that the comparison between the model derivatives and the actual deconvolved derivatives enables identification of mismatch causes.
Characterisation and Simulation Insights for Gas Reservoirs with Paleo-Contact
Authors: Taggart Ian 
Published: April 2019

Abstract
Many gas reservoirs at the appraisal stage exhibit evidence of persistent gas saturations below free water levels (FWL's). The amounts of gas contained here may, under some situations, be a sizable fraction of the gas cap volumes. Many engineers appear poorly equipped to include, and model, paleo gas in simulation models. This often results in paleo gas being simply ignored when development plans are being considered. This is unfortunate because paleo gas upon pressure depletion can expand, displacing brine towards well completions. This means that while some additional gas production may occur from the paleo zone, the risk of water production may be significantly underestimated if paleo gas is simply omitted. This work discusses the evidence for paleo gas and shows that it may be described and incorporated in simple simulation models provided the user avoids some common misconceptions. It is demonstrated that under depletion conditions, paleo gas can be entirely visible to material balance pressure responses, while at the same time increasing the risk of produced water volumes. For higher pressure paleo gas reservoirs the common P on Z diagnostic plots can also provide early trends that are frequently misinterpreted. This work quantifies the curvature that can result in such systems, and shows that simulation models inherently predict the expected curvature in P on Z. The approach taken here is by design simplistic and is applicable to scoping evaluations where the paleo gas volumes could be a significant volumetric uncertainty. Where possible, we indicate where additional, or more rigorous, descriptions can be applied.