bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Impact of Near-Wellbore Refinement on Modelling Advanced and Smart Well Completions in Reservoir Simulation
Authors: Awid Abdurrezagh , Geiger Sebastian , Mackay Eric 
Published: October 2018

Abstract
Advanced or smart completion wells are different from conventional wells by being equipped with downhole flow control devices such as Interval Control Valves (ICV) and Inflow Control Devices (ICD) to offer improved reservoir management and control and thus maximise hydrocarbon production and recovery. In order to justify their implementation and increase their economic return, a high degree of robustness in modelling, prediction and optimisation of their performance is required.
To improve the robustness of forecasting production from advanced or smart wells using reservoir simulation, high-level details in rock and fluid flow properties are needed in the near-wellbore region to accurately capture the flow dynamics. The paper presents an improved approach that enables us to robustly predict the performance of advanced or smart wells in reservoir simulation and highlights the importance of representing the near-wellbore region when optimizing smart well completions.
Performances of advanced or smart well completions are very dependent on changes in flow rate, pressure, and saturations, which mainly occur in areas around the wells. The paper demonstrates the use of local grid refinement (LGR) in the near-wellbore region to enhance the accuracy level of simulation predictions. In the study, an objective function based ICV optimization strategy was used to identify the optimum settings for every time step during the simulation run. We also demonstrate how to correlate ICV settings to Passive Inflow Control Device (PICD) or Autonomous Inflow Control Device (AICD) strengths if a requirement arises to impose the use of ICVs.
Using a well-established synthetic reservoir model, we demonstrate how the representation of the near-wellbore region impacts reservoir performance predictions and influences the way ICVs and ICDs are optimized. We observe that by applying this approach, the predicted NPV and recovery factor change by 6.6% and 6.1%, respectively. In addition, this study also quantifies the impact of near-wellbore representation on four completion types; Openhole, ICV, PICD and AICD completions.
The novelty of this paper is that it presents an approach to improve production forecasts that supports decision making during field development planning to maximize profit and minimize risk.
Real Time Determination of Rheological Properties of Spud Drilling Fluids Using a Hybrid Artificial Intelligence Technique
Authors: Abdelgawad Khaled , Elkatatny Salaheldin , Mousa Tamer , Mahmoud Mohamed , Patil Shirish 
Published: October 2018

Abstract
Measuring the rheological properties during the drilling operation is time-consuming and usually, these properties are measured twice a day. The rheological properties play a key factor in controlling the drilling operation. The knowledge of these properties are very important for hydraulic calculations which are required for hole cleaning optimization, surge and swab pressure calculations and others. Wrong estimation of these properties may lead to big disaster during the drilling operation such as pipe sticking, loss of circulation, and/or well control issues. The aforementioned problems will increase the non-productive time and hence the overall cost of the drilling operations. Artificial intelligence techniques, once they are optimized, can be used to predict the rheological properties in a real time.
The main idea of this paper is to use the frequent measurements of the mud density, Marsh funnel viscosity and solid percent, which are measured every 15-20 minutes and build new artificial intelligent models for plastic viscosity, yield point, apparent viscosity, and flow behavior index. Different AI techniques were evaluated such as; artificial neural network, support vector machine (SVM) and adaptive-network-based fuzzy inference system (ANFIS). The model which yielded the highest accuracy (lower average absolute error (AAPE) and highest correlation coefficient (R)) was used to develop new empirical correlations for each rheological properties. For the first time, the artificial intelligence techniques were combined with the self-adaptive differential evolution algorithm to optimize the best combination of the AI parameters.
The results obtained showed that ANN is the best AI technique to predict the rheological properties from the mud density, Marsh funnel viscosity, and solid percent. It is very important to combine the self-adaptive differential evolution with the artificial neural network to predict the rheological properties with high accuracy (AAPE less than 5% and R greater than 95%). The ANN black box was converted to a white box by extracting the weights and biases of the optimized SaDe-ANN model for each rheological parameter and a new empirical correlation was developed. The developed technique will help the drilling engineer to predict the rheological properties every 15 to 20 minutes and this will help in hole cleaning optimization and avoid most of the drilling problems such as pipe sticking and loss of circulation. The developed correlation can be used without the need for the ANN model and can apply using any software. No additional equipment or especial software is required for applying the new method.
Detecting Natural Fracture properties using Rate Transient Analysis
Authors: Assiri Wisam J , Ozkan Erdal 
Published: October 2018

Abstract
Most unconventional reservoirs are characterized by an ultra-tight matrix and commercial production requires existence of a pervasive fracture network or conductive laminations within a shale play intersecting hydraulic fractures of horizontal wells. This paper shows that the early time flow for hydraulically fractured horizontal wells can be analyzed to quantify the properties of the hydraulic fracture and the feeding natural fractures. The linear or bilinear flow of early time can provide important information about the existence of natural fractures and their properties. A suite of tools is presented to analyze early time flow periods.
The solution is based on the trilinear model with a stimulated reservoir volume (SRV) represented by the transient, dual-porosity, slab model. This model is suitable to define flow from laminated unconventional reservoirs with tight matrix. Asymptotic solutions are derived for linear and bilinear flow regimes and conditions for their existence are provided. The start and end time of each flow regime can reduce uncertainty in the analysis. Flow restriction due to choking effect is considered. This analysis can help to forecast production from fractured horizontal wells in ultra-tight, fractured unconventional reservoirs.
Simulated examples demonstrate how hydraulic fracture conductivity can be estimated as well as the properties of natural fractures. Application of the analysis is also demonstrated on flowback data.
The importance of the recognition and analysis of the flowback data is in the potential to estimate the size of the SRV before productivity decline. Moreover, this paper explains the procedure to correctly use the start and end time of each flow regime and the conditions to bilinear flow to prevail. Application examples and results of misinterpretation of linear flow behavior are demonstrated.
Experimental Investigation of Radial and Linear Acid Injection into Carbonates for Well Stimulation Operations
Authors: Qiu Xiangdong , Edelman Eric , Aidagulov Gallyam , Ghommem Mehdi , Brady Dominic , Abbad Mustapha 
Published: October 2018

Abstract
Linear core flooding experiments have been extensively conducted to develop a fundamental understanding of the interactions between the acid and rock and provide guidance to control and optimize matrix acidizing operations. These experimental studies are mostly performed at lower than true reservoir operating conditions (pressure and temperature) using cylindrical cores of few inches length. Well treatment design software based on upscaling linear core flood data to design well treatment schedules including the selection of pump volumes, rates and fluids may fail to predict wormhole penetration depth and identify the optimum injection rate as the field acidizing operations are dictated by radial flow configuration. Given its associated complexity, only few radial acidizing experiments have been reported in the literature.
A sophisticated experimental set-up capable of treating large-scale rock blocks is used to conduct radial acidizing experiments at high pressure levels mimicking real reservoir conditions. A series of linear core flow experiments are also conducted for various injection rates at similar operating conditions in terms of applied pressure and temperature. Acidizing efficiency curves showing the variations of the pore volume to breakthrough (PVBT) as function of acid injection rate, along with the optimum injection rate are obtained and compared. The experimental results show that the acidizing efficiency curve of radial acid injection is drastically different from that of linear core acid injection. Higher PVBT values are for the linear acidizing case. The 3D wormhole networks resulting from acidizing such as wormhole depth, branching, initiation and death are influenced by a transfer to radial acid injection, leading to a significant change of the resultant fluid conductivity compared to that predicted from linear studies.
Acidizing efficiency curves constitute a critical component of most carbonate-matrix-stimulation models used in the oil & gas industry. Most of the existing models are based on the linear core acid injection experimental data while radial acidizing is more representative of real acidizing operations. The present experimental study is expected to redefine state-of-the-art of PVBT and optimum injection used in matrix acidizing applications.
Physico-Mathematical Model for forecasting Gas-Condensate Reservoir Performance in Multiphase Linear and Radial Flow Systems
Authors: Abdul-Latif Benson Lamidi , Abdul-Rashid Bawah 
Published: October 2018

Abstract
In this paper, a physico-mathematical model is presented for forecasting gas condensate reservoir performance in multiphase radial and linear flow systems using analytical and semi-analytical models. The proposed methodology is based on the three phase black-oil formulation, incorporating capillary pressure effect in fluid PVT properties in linear and radial flow regimes under constant bottomhole pressure (BHP) and constant flow rate well conditions.
The proposed analytical methodology is developed by reducing a system of governing partial differential equations (obtained by rewriting the black-oil mathematical formulation using the Boltzmann transformation) to a system of ordinary differential equations and hence solved using an adaptive step-size Runge-Kutta integration technique coupled with the shooting method without the need to linearize the system of differential equations.
Simultaneously, the proposed physico-mathematical model forecasts reservoir pressure profile and saturation behavior in linear and radial multiphase flow systems using three phase relative permeability data and gas condensate PVT data without the need for pressure-saturation or producing gas-oil ratio data inputs into the model.
To validate the proposed semi-analytical solution for multiphase-constant gas flow radial systems above the dewpoint pressure, analytical solutions were compared to the line-source solution.
Optimized Drilling Fluid and Tailored Drilling Practices Help Successfully Drill and Complete Wells along the Minimum Horizontal Stress Direction in Khuff Reservoirs
Authors: Hegazy Mohamed , Sharma Sunil , Fares Khaled , Dave Alok 
Published: October 2018

Abstract
From a drilling operation's prospective, wells drilled in the direction of maximum horizontal stress are ideal as they have less risk of wellbore instability. Unfortunately, when these wells are hydraulically fractured, the fracture grows along the wellbore in the direction of well azimuth. To avoid overlapping of two adjacent induced fractures and thereby communication between stages, only two to three multistage fracture treatments can be performed.
To increase production and enhance recovery, operators now drill horizontal wells along the minimum horizontal stress direction to generate multiple transverse fractures during the stimulation stage. However, drilling along the minimum horizontal stress direction requires higher mud weights to minimize formation breakout due to prevailing in-situ stress conditions. This increased mud weight leads to higher differential pressures across the depleted reservoir layers, which when coupled with formation instability, creates greater challenges like stuck pipe, breakouts, and breakdowns. During the completion phase, the stiff multistage fracturing string containing multiple packers makes it more difficult to run through a slim hole, resulting in multiple failures, stuck incidents, and non-productive time.
While drilling high angle wells in Saudi Arabia's onshore gas fields, production holes are drilled through many reservoir layers. A few are highly depleted and the rest are highly pressurized. A high degree of skill is required to manage drilling fluids and drilling practices so that the depleted layers seal efficiently, thus preventing development of a thick filter cake and differential sticking incidents.
This paper outlines a successful neoteric methodology adopted in these challenging wells after a detailed analysis of offset data and failure incidents. The outstanding performance achieved by adaptation in operational procedures while using the existing setup in both drilling and completion phases, challenges while implementing the strategies, and comparison of results with previous drilling techniques will also be covered in detail to help operators drilling in similar conditions.
Testing and Evaluation of Shale Stability for Zubair Shale Formation
Authors: Abbas Ahmed K. , Flori Ralph E. , AL-Anssari Ahmed , Alsaba Mortadha 
Published: October 2018

Abstract
Zubair Formation consists of approximately 55% shale, which causes almost 70% of wellbore problems due to incompatibilities of drilling fluids and shale formations. The most common and effective solution to shale instability is through the design and selection of drilling fluids. Understanding the interaction between drilling fluids and shale has been a challenge due to the complexity of both physical and chemical variations in shale formations. This paper presents some of the important laboratory and well-site testing techniques that are often used by mud engineers for characterizing and remediating drilling fluids and shale interaction. Well-preserved shale samples were analyzed to describe the special characterization of the Zubair shale. Moreover, the traditional laboratory methods such as capillary suction time test, hot rolling dispersion test, bulk hardness test, and the linear swelling test were used to evaluate the stability of shale in the presence of test fluids. Our laboratory test results show that the Zubair shale is composed mainly of brittle mineral (quartz and calcite) with average content 51.46% and 43.54% of the clay mineral. In addition, the cation exchange capacity analysis and capillary suction time test indicated that Zubair shale has low to moderate reactivity with drilling fluids. This paper will present the preliminary process of analysis and understanding of shale structural failures due to shale/fluid interactions. Consequently, it can be used to control and minimize shale instability by improving the selection of chemical additives for clay inhibition.
Rheology Studies of Crosslinked Fracturing Fluids Utilizing Seawater
Authors: Yamak Raafat M. , Nasr-El-Din Hisham A. , Rahim Sabiq , BinGhanim Ahmed 
Published: October 2018

Abstract
Seawater-based fracturing fluids are used to generate a stable crosslinked fracturing fluid for higher formation temperatures primarily using two types of guar derivatives—HPG and CMHPG. Results are compared to other seawater-based fracturing fluid data in the literature, as well as to traditionally used freshwater-based fracturing fluid. A HP/HT rotational rheometer for viscosity measurements was utilized to assess the stability of the fracturing fluid. Chlorous-acid-based breakers were also tested in the fracturing fluid at various temperatures to assess effectiveness of reducing fluid viscosity. Additionally, a phosphonate-based scale inhibitor was used at various concentrations to mitigate the formation of scales that arise from the mixing of seawater and formation water. The concentration of the additives and consequent results are all provided to display the functionality of the crosslinked gel using seawater.
Results confirmed that a dual-crosslinked seawater-based fracturing fluid stability was feasible, as viscosity remained greater than 500 cP for two hours. Freshwater-based fracturing fluid displayed longer gel stability primarily because of a lack of salts that hinder polymer hydration. The stability time varied owing to the thermal degradation of the polymer. The high total of dissolved solids of the seawater had minimal effect on the breaker, as it reduced the stability time of the seawater-based fracturing fluids by over 50%. The introduction of new, cost-effective fracturing fluid formulations introduces environmentally friendly ways to find substitutes for fresh water in hydraulic fracturing operations.
Shale-Fluid Sensitivity for an Unconventional Shale Formation
Authors: Alouhali Raed , Al-Arfaj Mohammed , Al-Rashead Mohammed , Hayton Shaun 
Published: October 2018

Abstract
Shale instability is a major problem for drilling operation. Shales make up over 75% of drilled formations and are responsible for 90% of wellbore instability problems. There are many problem associated with shale drilling such as wellbore instability, cuttings dispersion, stuck pipe, and bit balling. Shales used to be the problematic formations that needed to drill through with the minimum number of problems, lowest possible lost time and generally the shortest possible open-hole time to minimize fluid sensitivity issues. However, with the advancement in drilling and production techniques, some shale formations are now the target for hydrocarbon production, meaning that much longer periods of open-hole are required for horizontal drilling, logging and completion meaning fluid sensitivity is an increasingly important question..
In this paper, we evaluate the shale-fluid sensitivity of a target unconventional shale formation. A total of 20 samples from 6 different wells were used in this study. The mineralogy of all 20 samples were analyzed using XRD. Then two shale-fluid sensitivity tests (dispersion test and capillary suction time test) were run on the samples using four different water based fluids (7% KCl, 3% KCl, 3% NaCl, and 5% NH4Cl) in addition to fresh water and diesel which were used to establish bounding parameters.
Overall, all inhibitors performed well, with 7% KCl and 3% KCl being the best performing inhibitors for drilling shale formations of this composition followed by 5% NH4Cl and lastly 3% NaCl.
Adding More Value in the Downturn Time from Digital Oil Field; what is more to leverage?
Authors: Al Qahtani Abdullah M. , Al Qahtani Mubarak 
Published: October 2018

Abstract
Operators have gotten onboard on digital field implementations as a game-changer to optimize oil production, reduce asset development and operation cost by leveraging fields' real-time data, software solutions, and smart workflow processes. Such implementations have demonstrated improved well placement, well delivery, real-time well monitoring, reduced production loss from unplanned well downtime, and improved HSE.
This paper covers overlooked aspects of digital oil field applications and focus on developing ADHOC solutions pertaining to well/reservoir performance optimization. These solutions will help identify high value opportunities and candidate wells for intervention and workover using operating envelopes, developing robust systems for well integrity and equipment reliability. The solutions will provide transient flow/pressure analyses for reservoir and well performance optimization and provide assessment of well productivity and well system performance. Moreover, the introduced solutions will enable efficient reservoir management and performance analytic tools, well flow capacity validation and optimization (single well/multiple wells). It will also enable horizontal/multi-lateral well monitoring and optimization.
New indices/metrics are introduced to gage the performance and ensure maximum return possible, well architected/subsystem designs, reliability, integrity, and well control issues. These indices are meant to develop life-cycle designs and assure total well management. In addition, to promote operational excellence and improve reliability.
A Fast Algorithm for the Estimation of the Equivalent Permeability in Heterogeneous Formations
Authors: Liao Qinzhuo 
Published: October 2018

Abstract
Reservoir simulation is an important component of reservoir development and management. Due to the heterogeneity in the subsurface formation, the accurate representation of the reservoir requires high-resolution geostatistical modeling with extremely large numbers of grid blocks in realistic models, which can be computationally prohibitive. This motivates the development of upscaling methods from fine-scale to coarse-scale by estimating the equivalent permeability. In this work, we have developed a rapid analytical method to increase the absolute permeability of heterogeneous reservoirs.
The equivalent permeability for a uniform flow in a given direction is bounded by (1) the harmonic mean of the arithmetic means of the local permeabilities, calculated over each slice of cells perpendicular to the given direction (upper bound), and (2) the arithmetic mean of the harmonic means of the local permeabilities, calculated on each line of cells parallel to the given direction (lower bound). The idea is to take a value between these two bounds, and the weighting coefficient is the key for accurate results. We presented a fast algorithm to estimate the weighting coefficient in the sense of probability expectation.
We compared the pressures and velocities calculated from three approaches, the fine-scale model, the coarse-scale model by numerical upscaling, and the coarse-scale model by analytical upscaling. We considered various conditions, including uncorrelated and correlated, isotropic and anisotropic, the effects of permeability variance and grid block geometry. We found that the pressures and velocities calculated from the coarse-scale model by analytical upscaling are very close to those from the coarse-scale model by numerical upscaling, i.e., the analytical method is as accurate as the numerical method, while the former can be O(10) times faster than the latter.