bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fast Upscaling of Polymer Flood Simulations Using Fractional Flow and Scaled Mobilities
Authors: Al-Ibadi Hasan , Stephen Karl , Mackay Eric 
Published: October 2021

Abstract
We introduce a pseudoisation method to upscale polymer flooding in order to capture the flow behaviour of fine scale models. This method is also designed to improve the predictability of pressure profiles during this process. This method controls the numerical dispersion of coarse grid models so that we are able to reproduce the flow behaviour of the fine scale model.
To upscale polymer flooding, three levels of analysis are required such that we need to honour (a) the fractional flow solution, (b) the water and oil mobility and (c) appropriate upscaling of single phase flow. The outcome from this analysis is that a single pseudo relative permeability set that honours the modification that polymer applies to water viscosity modification without explicitly changing it. The shape of relative permeability can be chosen to honour the fractional flow solution of the fine scale using the analytical solution. This can result in a monotonic pseudo relative permeability set and we call it the Fractional-Flow method. To capture the pressure profile as well, individual relative permeability curves must be chosen appropriately for each phase to ensure the correct total mobility. For polymer flooding, changes to the water relative permeability included the changes to water viscosity implicitly thus avoiding the need for inclusion of a polymer solute. We call this type of upscaling as Fractional-Flow-Mobility control method.
Numerical solution of the upscaled models, obtained using this method, were validated against fine scale models for 1D homogenous model and as well as 3D models with randomly distributed permeability for various geological realisations. The recovery factor and water cut matched the fine scale model very well. The pressure profile was reasonably predictable using the Fractional-Flow-Mobility control method.
Both Fractional-Flow and Fractional-flow-Mobility control methods can be calculated in advance without running a fine scale model where the analysis is based on analytical solution even though produced a non-monotonic pseudo relative permeability curve. It simplified the polymer model so that it is much easier and faster to simulate. It offers the opportunity to quickly predict oil and water phase behaviour.
Deep Learning Assisted Doppler Sensing for Hydrocarbon Downhole Flow Velocity Estimation
Authors: Katterbauer Klemens , Marsala Alberto , Schoepf Virginie , Abbassi Linda 
Published: October 2021

Abstract
Logging hydrocarbon production potential of wells has been at the forefront of enhancing oil and gas exploration and maximize productivity from oil and gas reservoirs. A major challenge is accurate downhole fluid phases flow velocity measurements in production logging due to the criticality of mechanical spinner-based sensor devices. Ultrasonic Doppler based sensors are more robust and deployable either in wireline or logging while drilling (LWD) conditions; however, due to the different sensing physics, the measurement results may not be equivalent. We present in this work an innovative deep learning framework to estimate spinner phase velocities from Doppler based sensor velocities. Tests of the framework on a benchmark dataset displayed strong estimation results. This allows for the real-time automatic interpretative framework implementation and flow velocity estimations either in conventional wireline production logging technologies (PLTs) and potentially also in LWD conditions, when the well is flowing in underbalanced conditions.
Investigation on the Effect of Mud Additives on the Gelation Performance of PAM/PEI System for Lost Circulation Control
Authors: Shamlooh Mohamed , Hamza Ahmed , Hussein Ibnelwaleed A. , Nasser Mustafa S. , Salehi Saeed 
Published: October 2021

Abstract
Lost circulation is one of the most common problems in the drilling of oil and gas wells where mud escapes through natural or induced fractures. Lost circulation can have severe consequences from increasing the operational cost to compromising the stability of wells. Recently, polymeric formulations have been introduced for wellbore strengthening purposes where it can serve as Loss Circulation Materials (LCMs) simultaneously. Polymeric LCMs have the potential to be mixed with drilling fluids during the operation without stopping to avoid non-productive time. In this study, the significance of most common conventional mud additives and their impact on the gelation performance of Polyacrylamide (PAM) / Polyethyleneimine (PEI) has been investigated.
Drilling fluid with typical additives has been designed with a weight of 9.6 ppg. Additives including bentonite, barite, CarboxyMethylCellulose (CMC), lignite, caustic soda, desco, and calcium carbonate has been studied individually and combined. Each additive is mixed with the polymeric formulation (PAM 9% PEI 1%) with different ratios, then kept at 130°C for 24 hrs. Rheological performance of the mature gel has been tested using parallel plate geometry, Oscillatory tests have been used to assess the storage Modulus and loss modulus. Moreover, the gelation profile has been tested at 500 psi with a ramped temperature to mimic the reservoir conditions to obtain the gelation time. The gelation time of the polymer-based mud was controllable by the addition of a salt retarder (Ammonium Chloride), where a gelation time of more than 2 hours could be achieved at 130°C.
Laboratory observations revealed that bentonite and CMC have the most effect as they both assist in producing stronger gel. While bentonite acts as a strengthening material, CMC increases the crosslinking network. Bentonite has successfully increased the gel strength by 15% providing a storage modulus of up to 1150 Pa without affecting the gelation time.
This work helps in better understanding the process of using polymeric formulations in drilling activities. It provides insights to integrate gelling systems that are conventionally used for water shut-off during the drilling operation to replace the conventional loss circulation materials to provide a higher success rate.
Slim Pulsed Neutron Spectroscopy Lands for the First Time in the Egyptian Western Desert to Provide a Complete Formation Evaluation – A Novel Case Study from Abu Sennan Field
Authors: Saied Hesham , Refaat Emad , Mokhtar Hesham , Farouk Mohamed , Salim Sadek , Saleh Khaled , Gomes Renata , Cavalleri Chiara 
Published: October 2021

Abstract
Wellbore stability issues associated with mechanical failure of the formations frequently present a challenging environment for running openhole logs. Alternatively, casedhole logs can be used to provide multiple physical properties of the formation to help in reservoir characterization. Generally, conventional casedhole measurements have limitations due to the effect of borehole fluids as well as cement integrity. Therefore, it can be challenging to complete an accurate full reservoir evaluation using conventional casedhole measurements. In a field example from the Western Desert, Egypt, a state-of-the-art advanced slim pulsed neutron technology was deployed for the first time to provide a comprehensive standalone formation evaluation without openhole data.
When hydrocarbon exploration and development move into more challenging environments, deployment of fit-for-purpose technologies is required. The advanced slim pulsed neutron processing algorithms were used for recording capture and inelastic elemental spectroscopy for rock elemental concentrations, including total organic carbon, detailed mineralogy, and matrix properties, simultaneously with sigma and other neutron-based outputs. By integrating the independent pulsed neutron measurements that are borehole self-compensated, casedhole reservoir characterization is now feasible with high accuracy and precision where the conveyance of openhole logging is of high risk due to borehole conditions and wellbore stability issues.
This case demonstrates the applicability of advanced slim pulsed neutron logging for comprehensive reservoir characterization in casedhole environments without any openhole data. It presents this innovative approach for the first time in the Egyptian Western Desert in a field with complex geological background, mixed lithology, and reservoir fluids types. The characterization paved the way to a new gas discovery in a complex clastic environment with a total net pay of 36m of gas condensate. Detailed mineralogy, reservoir porosity, fluid types identification, and hydrocarbon saturation were obtained with high accuracy behind the cased borehole independent of cement integrity and borehole fluid invasion. Leveraging this novel approach, the same methodology can be applied to old reservoirs with limited openhole data available to provide a robust formation evaluation that would aid in re-assessing brownfields.
The advanced slim pulsed neutron spectroscopy establishes a paradigm shift in reservoir characterization for casedhole environments to provide a comprehensive formation evaluation and fluid saturation without any openhole input. The workflow can be implemented in various scenarios as a cost-effective solution for reservoir evaluation or reservoir management applications.
Numerical Investigation of Wettability Effects on Two-Phase Flow in Naturally Fractured Reservoirs Using Complex System Modelling Platform
Authors: Sedaghat Mohammad , Dashti Hossein 
Published: October 2021

Abstract
Wettability is an essential component of reservoir characterization and plays a crucial role in understanding the dominant mechanisms in enhancing recovery from oil reservoirs. Wettability affects oil recovery by changing (drainage and imbibition) capillary pressure and relative permeability curves. This paper aims to investigate the role of wettability in matrix-fracture fluid transfer and oil recovery in naturally fractured reservoirs. Two experimental micromodels and one geological outcrop model were selected for this study. Three relative permeability and capillary pressure curves were assigned to study the role of matrix wettability. Linear relative permeability curves were given to the fractures. A complex system modelling platform (CSMP++) has been used to simulate water and polymer flooding in different wettability conditions. Comparing the micromodel data, CSMP++ and Eclipse validated and verified CSMP++. Based on the results, the effect of wettability alteration during water flooding is stronger than in polymer flooding. In addition, higher matrix-to-fracture permeability ratio makes wettability alteration more effective. The results of this study revealed that although an increase in flow rate decreases oil recovery in water-wet medium, it is independent of flow rate in the oil-wet system. Visualized data indicated that displacement mechanisms are different in oil-wet, mixed-wet and water-wet media. Earlier fracture breakthrough, later matrix breakthrough and generation and swelling of displacing phase at locations with high horizontal permeability contrast are the most important features of enhanced oil recovery in naturally fractured oil-wet rocks.
Investigation of Well Control Parameterization with Reduced Number of Variables Under Reservoir Uncertainties
Authors: Santos Daniel Rodrigues , Fioravanti André Ricardo , Santos Antonio Alberto Souza , Schiozer Denis José 
Published: October 2021

Abstract
Although several studies have shown that life-cycle well control strategies can significantly improve a field's economic return, the industry often relies on short-term strategies. One drawback of traditional parameterization, adopted for well control life-cycle numerical optimization, is that it often generates control strategies that yield impractical abrupt changes in production curves. Another issue, especially in cases with a large number of decision variables, is the local optima convergence related to the non-convex optimization problems. In this context, we proposed and compared four life-cycle well control parameterizations to maximize the net present value (NPV) of the field under uncertainties, which are able to mitigate both the above-mentioned problems.
The first parameterization optimizes the apportionment of well rates at the beginning of the field management and well shut-in time. The other three are based on optimizing the coefficients of parametric equations (first-and second-order polynomials, and logistic equation) to guide the bottom-hole pressure (BHP) over time. We executed each parameterization five times in a deterministic reservoir scenario and compared them with well control short-term strategy that prioritizes production in wells with higher oil-water ratio and that aimed to replicate the general industry practice. In this strategy, the wells’ priority rank was updated at every 30-simulation days. Subsequently, the best parameterization was used to select the well control life-cycle strategy under reservoir uncertainties and this strategy was applied to the reference model representing a real reservoir.
The results showed that all the proposed parametrizations significantly improved the NPV in comparison to the well control short-term strategy, while simultaneously ensuring a smooth well production curve. The logistic equation presented the best result among all parameterizations, as it delivered both the highest average of NPV and the smallest dispersion over the five experiment repetitions. This parameterization also produced similar results when applied under uncertainties and for the reference model. These results endorse the importance of not only relying on a short-term strategy, but also planning it for the life-cycle.
Horizontal Versus Vertical Wells: Assessment of Sweep Efficiency in a Multi-Layered Reservoir Based on Consecutive Inter-Well Tracer Tests - A Comparison Between Water Injection and Polymer EOR
Authors: Davidescu Bogdan-George , Bayerl Mathias , Puls Christoph , Clemens Torsten 
Published: October 2021

Abstract
Enhanced Oil Recovery pilot testing aims at reducing uncertainty ranges for parameters and determining operating conditions which improve the economics of full-field deployment. In the 8.TH and 9.TH reservoirs of the Matzen field, different well configurations were tested, vertical versus horizontal injection and production wells. The use of vertical or horizontal wells depends on costs and reservoir performance which is challenging to assess. Water cut, polymer back-production and pressures are used to understand reservoir behaviour and incremental oil production, however, these data do not reveal insights about changes in reservoir connectivity owing to polymer injection. Here, we used consecutive tracer tests prior and during polymer injection as well as water composition to elucidate the impact of various well configurations on sweep efficiency improvements.
The results show that vertical well configuration for polymer injection and production leads to substantial acceleration along flow paths but less swept volume. Polymer injection does not only change the flow paths as can be seen from the different allocation factors before and after polymer injection but also the connected flow paths as indicated by a change in the skewness of the breakthrough tracer curves. For horizontal wells, the data shows that in addition to acceleration, the connected pore volume after polymer injection is substantially increased. This indicates that the sweep efficiency is improved for horizontal well configurations after polymer injection.
The methodology leads to a quantitative assessment of the reservoir effects using different well configurations. These effects depend on the reservoir architecture impacting the changes in sweep efficiency by polymer injection. Consecutive tracer tests are an important source of information to determine which well configuration to be used in full-field implementation of polymer Enhanced Oil Recovery.
Advances in Cased-Hole Formation Evaluation—The Access to Untapped Tight-Gas Resources in Mature Fields: A Case Study from the Dnieper-Donets Basin, Ukraine
Authors: Zambrano Rafael , Makar Yevhen , Sadivnyk Michael , Butenko Andriy , Doroshenko Oleksandr , Novikov Volodymyr , Cimic Miljenko , Cavalleri Chiara , Ahmad Samira , Akashev Yernur 
Published: October 2021

Abstract
The Sakhalin Field is located in the Dnieper-Donets Basin, east of Ukraine, and has been producing 7.7 billion cubic meters of natural gas in place from carboniferous rocks since the 1980s. Notwithstanding, it is strongly believed that significant untapped resources remain in the field, specifically those classified as tight intervals. Advances in wireline logging technology have brought, besides better accuracy on measurements behind the casing, a new measurement called fast neutron cross-section (FNXS), which has proved to be sensitive enough to the volume of gas in low-porosity formations. This enabled a quantitative interpretation for a better understanding of where these additional resources may lie in the Sakhalin Field.
The methodology is based on advanced pulsed neutron spectroscopy logs to assess the essential formation properties such as lithology, porosity, and gas saturation and reduce the evaluation uncertainty in potential tight gas intervals. The advanced technology combines measurements from multiple detectors that represent independent formation properties such as formation sigma, thermal neutron porosity, FNXS, and elemental fractions. To address the lithology, the tool measures directly the rock elements required to determine representative mineralogy and matrix properties, which in turn are used to compensate for the matrix effects and obtain a reliable porosity and gas volume estimation.
The methodology was tested on the upper Visean productive zones (Mississippian epoch) characterized by its low porosity (&lt;10 pu) and permeability (&lt;10 mD). In the past, those intervals have been overlooked because of inconclusive petrophysical interpretation based on basic openhole logs and their low production in some areas of the field. The necessity to finding new reserves has motivated the re-evaluation of possible bypassed tight-gas intervals by logging of mature wells behind casing in different sectors of the field. Advanced pulsed neutron spectroscopy logging behind casing uniquely identifies reserves in tight-gas intervals where basic open-hole interpretations were ambiguous. The gas production obtained from the perforated intervals supports the formation evaluation parameters estimated from the standalone interpretation of the pulsed neutron data.
This work describes in detail the application of the alternative methodology and interpretation workflow to evaluate the formation through the casing. A concrete example is presented to illustrate the effectiveness of this approach in the revealing and development of tight gas reservoirs in mature fields in the Dnieper-Donets Basin.
An Integrated Modeling Approach to Estimate the Shut-in Wellhead Pressure for Well Integrity Applications – Case Study
Authors: Mohamed Mohamed Ibrahim , El-Menoufi Ahmed Mahmoud , Ezz El-Regal Eman Abed , Hegazy Abd Allah Moustafa , Mansour Khaled Mohamed , Negm Mohamed Nagy , Hussein Hatem Mohamed 
Published: October 2021

Abstract
Oil and gas operators must measure or calculate the shut-in wellhead pressure for well integrity applications. Some operators adopt a method that gives satisfactory results for dry gas and lean gas condensate. They are using the steady-state simulator to calculate the wellhead pressure at a very low gas rate. The friction losses become negligible, and the only losses are due to hydrostatic head simulating (to some extent) the shut-in condition. This method again can work well with oil producers with low GOR/Bubble point pressure as the production string will be nearly a single phase. The problem is that this method is inaccurate for high GOR/CGR wells because of phase redistribution and the error can be significantly high.
Phase redistribution occurs After shut-in, liquid droplets will accumulate at the bottom of the well. The interface liquid/gas will move up with sometimes liquid cushion is being re-injected back in the reservoir due to gravity or gas expansion in the tubing while the gas/liquid interface will move down a little. Many factors affect the behavior, including the well deviation, fluid properties, and the productivity and the injectivity of the formation. Thus, simulating this behavior requires a dynamic multiphase simulation. As some of the fluids might return to the formation, as a result of compressibility, coupling with a numerical reservoir simulation to model the near wellbore is also necessary.
In this paper, we applied a dynamic multiphase model to predict the shut-in wellhead pressure. We used an uncertainty analysis approach to investigate the effect of many parameters on the accuracy of the results. We presented all recommended calculation procedures with a guide to minimizing the uncertainty associated. We presented our approach to three actual wells with different configurations and fluid properties with a deviation of +-10% of the real measurements.
Real-Time EM Look-Ahead Resistivity for Mapping of Oil/Water Contact While Drilling at Low Deviated Well, New Perspective for Mature Oil Fields Development: A Case Study Of Umm Gudair Field, Kuwait
Authors: Al-Khalifa Nasser Faisal , Hassan Mohammed Farouk , Joshi Deepak , Tiwary Asheshwar , Pasaribu Ihsan Taufik , Siam Mahmoud , Leveque Soaziq , Osman Salih Noreldin 
Published: October 2021

Abstract
The Umm Gudair (UG) Field is a carbonate reservoir of West Kuwait with more than 57 years of production history. The average water cut of the field reached closed to 60 percent due to a long history of production and regulating drawdown in a different part of the field, consequentially undulating the current oil/water contact (COWC). As a result, there is high uncertainty of the current oil/water contact (COWC) that impacts the drilling strategy in the field. The typical approach used to develop the field in the lower part of carbonate is to drill deviated wells to original oil/water contact (OOWC) to know the saturation profile and later cement back up to above the high-water saturation zone and then perforate with standoff. This method has not shown encouraging results, and a high water cut presence remains.
An innovative solution is required with a technology that can give a proactive approach while drilling to indicate approaching current oil/water contact and geo-stop drilling to give optimal standoff between the bit and the detected water contact (COWC). Recent development of electromagnetic (EM) look-ahead resistivity technology was considered and first implemented in the Umm Gudair (UG) Field. It is an electromagnetic-based signal that can detect the resistivity features ahead of the bit while drilling and enables proactive decisions to reduce drilling and geological or reservoir risks related to the well placement challenges.