bluuebunny/crossref_metadata_2025_split huggingface dataset:
Determining Effective Mixture Viscosities in Oil-Water Flows for Downhole Oilfield Operations
Authors: Ejim C. E. , Xiao J. J. 
Published: October 2018

Abstract
In downhole oilfield operations that involve pumping oil and water, information on mixture viscosity is important to further understand the performance of the downhole production equipment. This study presents a method for determining the effective absolute viscosity of oil-water mixtures by applying fluid mechanics first principles to data representative of downhole production measurements. Knowledge of effective absolute viscosity in upstream and downstream oilfield operations is essential to extend equipment life and optimize production operations.
A 7-inch, 26 lb/ft pipe and a 3.5-in, 9.20 lb/ft pipe, typically used as casing and tubing, respectively, in field operations were installed in an oil-water flow loop. The volume flow rates during the tests varied from 2000 barrels per day (bpd) to 12,000 bpd, representative of target field production rates. The tests were performed at different inclinations to represent varying well deviation angles. For each oil and water flow rate, the corresponding pressure drop measurements across a fully developed section of the flow were measured. Using fundamental hydraulic relationships, the effective absolute viscosities of the oil-water mixtures were determined.
The results showed that as water cut varied, the effective mixture absolute viscosity also changed, and in some cases substantially. The highest effective absolute viscosity of 500 cP occurred at the mixture flow rate corresponding to 2000 bpd and 40% water cut. In general, mixture flow rates of 2000 bpd and water cuts between 40 and 60% consistently showed the highest effective absolute mixture viscosities, which varied between 160 cP to 500 cP. For water cuts outside the 40% to 60% range, the effective absolute viscosities were about 120 cP and less. The above results indicate that the effective mixture viscosity is about two and close to three orders of magnitude of pure oil and pure water viscosities, respectively. The results also suggest that certain flow rates and water cuts significantly affect the viscosity of oil-water flows. Other results showed that for a given mixture flow rate the effective viscosities were about the same order of magnitude for the different inclinations. This indicates that well deviation angle has minimal or negligible influence on the effective mixture absolute viscosity. From the combined results the technique used in this study provides additional insight to ascertain the effective viscosity of oil-water mixtures during field operations.This study highlights the importance of having the capability to determine the effective absolute viscosity of oil-water mixtures during oilfield production operations. The methodology is simple and has the advantage of easy integration into a flow measurement system. Such systems are beneficial tools for reservoir engineers, production engineers and field operators in general for making appropriate production modifications during operations, to increase asset life and maximize hydrocarbon recovery.
Data Analysis of Lost Circulation Events in the Hartha Formation, Rumaila Field, Iraq
Authors: Al-Hameedi Abo Taleb , Alkinani Husam H. , Dunn-Norman Shari , Flori Ralph E. , Hilgedick Steven A. , Alkhamis Mohammed M. , Alsaba Mortadha T. 
Published: October 2018

Abstract
Lost circulation is a complicated problem to be prevented or combatted during drilling through the Hartha formation. Hence, Mud losses remedies are determined to stop or mitigate losses using remedial methods or to prevent mud losses using proactive measures. Lost circulation events are analyzed in more than 300 wells drilled in the Rumaila field to determine the best ranges for the key drilling parameters, which have the greatest chance of minimizing or prohibiting lost circulation issues.
Key drilling parameters (e.g. MW, ECD, Yp, RPM, SPM, ROP) at the time of each event are extracted along with the lost circulation remedies attempted, and the outcome of those remedies. Practical field information from the Rumaila field and range of sources are reviewed and summarized to develop an integrated methodology and flowchart for handling lost circulation events in this formation. This paper will be an extended work along with previous comprehensive statistical study and sensitivity analysis models about the Hartha formation. In addition, economic evaluation is conducted for partial, severe, and complete losses to obtain the best field procedures.
Proactive approaches are made prior entering the Hartha formation to prevent or mitigate the occurrence of the lost circulation. A broad statistical work, typical drilling fluid properties, and recommended operational drilling parameters are estimated to use during drilling through this formation. Moreover, corrective actions are determined for each type of the mud losses to provide effective remedies, minimize non-productive time, and reduce cost. The best lost circulation strategy to the Hartha formation is concluded and summarized depending on a comprehensive statistical work, the most important courses of the international oil companies, technical papers, textbooks, and economic analysis evaluation to determine the successful remedies for each type of the losses. In addition, engineered solutions and practical techniques have been developed, which will contribute to give a clear image and a coherent understanding in regard this complicated and costly problem in the Hartha formation.
This study will present a typical compilation of information regarding traditional and the latest approaches to the lost circulation control. This work attempts to provide useful guidelines and effective solutions for all situations in terms preventive measures, remedial methods, and analytical economic study. In addition, due to the lack of published studies about the Hartha formation, this work can serve as a substantial resource for drilling through this zone.
Maximizing Oil Production by Using your Available Limited Resources, Case Study from Amal Field
Authors: El-Galil Yehia S. , El-Moniem Mohamed A. , El-Sherif Mamdouh , Khalifa Tarek , El-Fattah Fayad Abd , Ramadan Nasr 
Published: October 2018

Abstract
Production Optimization is often attributed to new technologies, sophisticated algorithms and application of market leading expertise. In Amal, after years of production, our learning is production optimization is more about doing simple things well and getting better at it every day through practice and planning.
In this paper, we will present an example for the capability of using limited resources in offshore fields to maximize oil production for wells suffering from high water production.
The challenge was in one of oil wells, which has been ceased to flow due to high water cut and consequently we deferred around 400 BOPD. To illustrate this point, we will focus on how we can retain the oil production from this well while the ongoing gas lift project is not ready yet. We thought about the integrity between the wells in the same platform by using one of gas wells from gas reservoir as injector to lift the ceased to flow oil well and how we could obtain the gas quantities to be injected into the oil well however the rest will be produced normally from the gas well.
We will share how a loaded well with high water cut was revived through this idea of gas lifting with a higher pressure well, many runs were performed using commercial software of wells modeling and reservoir simulation. We determined the proper rate and WHFP from the gas well to be injected in the oil well to recover that oil and we could improve the well productivity.
As a result, the well has produced over the last ten months and we could maximize the oil production with our limited resources and without any huge gas lift project. Again, this idea helped maintain safe and continuous production from ceased to flow well and we recovered around 110,000 barrels of oil until now and the well still produce.
Rate of Penetration Prediction Using Self-Adaptive Differential Evolution-Artificial Neural Network
Authors: Elkatatny Salaheldin 
Published: October 2018

Abstract
The rate of penetration (ROP) should be optimized during the drilling operation to avoid many problems such as cutting accumulation, pipe sticking, twist off, and to reduce the nonproductive time (NPT). ROP depends on many variables such as; drilling parameters, fluid properties, and formation strength. Previous models of ROP did not include the effect of the change in rock mechanics on the ROP prediction. Several models were developed based on a regression that is limited to the rock type and drilling conditions.
The objective of this paper is to apply the self-adaptive differential evolution technique (SaDE) to optimize the artificial neural network (ANN) variable parameters such as; training function, a number of hidden layers, transferring function and number of neurons in each layer. The optimized SaDE-ANN model will be used to predict the ROP as a function of torque (T), weight on bit (WOB), stand pipe pressure (P), flow rate (Q), the drilling fluid density (D), uniaxial compressive strength (UCS), plastic viscosity (PV), and RPM
The obtained results showed that ROP has a strong function of the drilling parameters; RPM, WOB, T, and horse power (HP). While ROP is a moderate function of UCS. The optimized ANN structure based on SaDE is 5-30-1; where the input layer consists of 5 neurons representing the input parameters; RPM, WOB/D, T/UCS, D/PV, and HP. The hidden layer consists of 30 neurons and the output layer contains one neuron representing the output predicted ROP. The ratio of the training and testing data was 0.6 and 0.4, respectively. The best training function was Bayesian Regularization backpropagation (trainbr) and the best transforming function was Logarithmic sigmoid (logsig). The high accuracy of the developed model confirmed the importance of compiling the drilling fluid properties with the drilling parameters.
A New Approach to Determine the Rheology Parameters for Water-Based Drilling Fluid Using Artificial Neural Network
Authors: Elkatatny Salaheldin , Mousa Tamer , Mahmoud Mohamed 
Published: October 2018

Abstract
Rheological properties play key roles in hydraulic calculations and hole cleaning. Determination of the rheological properties in real time is very important to control the drilling operation and save time. Losing the rheological properties can lead to severe problems such as; pipe sticking, kick and blowout, increase in torque and drag, and hole cleaning issue. Rheological properties can be determine using the rheometer, which required time for measurement and also for cleaning the equipment after use. In the well site, rheological properties are measured twice a day.
The objective of this paper is to develop a new technique to determine the rheological properties (plastic viscosity (PV), apparent viscosity (AV), yield point (YP), and flow behavior index (n)) of KCl water-based drilling fluid using the frequent measurements of the caliper parameters (drilling fluid density (D), Marsh funnel viscosity (MFV) and solid percent). D, MFV, and SV are measured frequently every 15-20 minutes in the well site. Artificial neural network (ANN) was used to build different models for PV, YP, AV, and n based on 3000 field data measurements.
ANN was able to predict the rheological properties on a real time with a high accuracy. Four new empirical correlations were developed to predict PV, AV, YP, and n. The accuracy of these correlations are very high (correlation coefficient (CC) greater than 90% and the average absolute percentage error (AAPE) was less than 6%. The novelty of this technique is the prediction of the rheological properties in real time based on the caliper variables, which will help the drilling engineers to perform a safe drilling operation and eliminate the common drilling problems.
A New Approach to Simulate Near-Miscible Water-Alternating-Gas Injection for Mixed-Wet Reservoirs
Authors: Alzayer Hassan , Sohrabi Mehran 
Published: October 2018

Abstract
The oil recovery factor from oil reservoirs must be increased significantly to meet the ever-increasing demand for energy. Majority of oil reserves worldwide (estimated as 60%) are held in carbonate reservoirs. It is believed that most carbonate reservoirs are mixed-wet to oil wet with high variation in wettability within the reservoir rock. Water-Alternating-Gas (WAG) injection is one of the most applicable EOR techniques known to increase oil recovery factor by 8-20% on top of waterflood alone. To maximize recovery from carbonate reservoirs, numerical simulation is the best available tool to aid with such objective. In this paper, we are presenting a new approach to simulate near-miscible water- alternating-gas injection for mixed-wet reservoirs.
The coreflood experiment used in this study was performed on a 65mD mixed-wet sandstone core sample at 38°C (100°F) and 12.69 MPa (1840 psia) where calculated Interfacial tension (IFT) between gas and oil at these conditions is 0.04 mN/m.
As recorded in the literature, the current simulation capabilities to model WAG injection behaviour is questionable. Some authors suggested that Land’s gas trapping parameter [C] should be variable during the WAG injection process. In this study, we investigated the best way to match the results of WAG injection experiments performed on a mixed-wet core. Matching the full experimental results were not possible without varying gas trapping parameter [C]. However, by updating the gas trapping parameter, based on our suggested procedure, the match between the simulation results and experimental data improved significantly.
This paper highlights the shortcomings of the commercial simulators in modelling WAG injection process. The current WAG hysteresis model can be improved based on the information published in this paper for better WAG injection simulation.
Innovative Approach to Optimize Cleanout Trips Inside Casing for Setting and Retrieving Whipstocks and Running Completion
Authors: Al Fakih Abdulqawi , Pessanha Vinicius , Aldape Alberto Gomez , Famiev Robert , Ahmad Bilal , Khan Tauqeer , Obari Wahid 
Published: October 2018

Abstract
It is considered essential to perform cleanout trips before setting or retrieving specific tools inside casing, such as whipstocks and completion packers. Multiple cleanout trips may be required, e.g., when milling a window in a multilateral well, before setting a whipstock, before retrieving a whipstock, etc. This paper explains how the cleanout trips can be combined with setting and retrieving trips to save time and improve efficiency.
Risk and engineering analysis were performed; the need of new and existing technologies such as high- performance string magnets, casing scrapers and a specialized metal catcher was identified. The data from multiple wells is presented to illustrate the reliability of the optimized practices.
This innovative approach has been implemented in over 50 wells, saving a minimum of two days per lateral in each multilateral well, and up to five days per well based on the number of whipstocks and the completion type; moreover, zero failures were recorded to date. The paper also outlines how the process was further improved by adding larger diameter magnets and scrapers above the liner top, to enhance metal recovery, and reach the theoretical metal weight value expected. This new procedure, also contributed to minimize the completion cleanout trips required for smart completion, from 5 runs to 3 runs per well as average. Finally, the paper discusses the HSE incidents exposure reduction due to the reductions of the number of trips, and highlights future improvement opportunities.
Recommended Practices for Evaluation and Development of Shale Gas/Oil Reservoirs Over the Asset Life Cycle: Data-Driven Solutions
Authors: Kennedy Robert , Minhas Haq 
Published: October 2018

Abstract
After drilling and completing over 200,000 shale wells in North America and about 3,000 more wells internationally, the industry still has more to learn in order to totally optimize hydraulic fracturing, and maximize productivity and recovery from these reservoirs. Although some, actual full-field case histories have been documented, one company has developed a set of Data-Driven Solutions (Recommended Practices) to evaluate and develop shale gas/oil (source rock) reservoirs to attain optimum producing rates and ultimate recovery.
Combined industry and company experience including our technologies, techniques, analyses methods and workflows for shale gas/oil plays led to defining these Data-Driven Solutions (Recommended Practices): Twelve Steps to Success for each of the shale gas/oil Asset Life Cycle phases. The Asset Life Cycle approach with the five phases of Exploration, Appraisal, Development, Production and Rejuvenation, was first introduced to the industry in earlier SPE papers. This approach follows three key points: 1. Begin with a complete understanding of the reservoir, 2. Use a multidiscipline and integrated approach across each Life Cycle phase and 3. Effectively use modern technology.
The Twelve Data-Driven Solutions were developed based an integrated approach for employing them across their respective life cycle phases. The solutions begin with 1. Identify and Evaluate Resource Potential and end with 12. Refrac to Improve Ultimate Recovery. Solutions are not linear, nor do they always cover only one life cycle phase. Each Step to Success is discussed by providing an Overview, Challenges, Value and specific Solutions (which include Recommended Practices).
All shales are not the same; geology, mineralogy, geochemistry varies even in the same basin/play. However; evaluation and development techniques involving Data-driven Solutions/Recommended Practices can apply to any shale (source rock) reservoir in the world.
Trialtest of Wireless Devices at Haradh Well #210
Authors: Alsaedi Abdullah 
Published: October 2018

Abstract
Novel distributed signal processing algorithms, energy-efficient medium access control and fault-tolerant routing protocols, self-organizing and self-healing sensor network mechanisms, etc. have contributed immensely to the growth of these technologies. Recent developments like Wireless HART and ISA SP100.11a have provided an exceptional boost to this novel technology. In terms of user’s perspective, significant paradigm shift can be observed from traditional wired technologies to upcoming wireless technologies.
The key market driver for performing this field trial was to reduce the damage to field cabling and well head instrumentation during the removal / reinstallation before and after workover / rig entry. With wireless instrumentation; field cabling will be eliminated, thus making it easy to remove and re-instate field instruments during workover / rig entry activities. Another major benefit for using wireless instrumentation was the turn-around time for re-flowing wells will be much shorter as wireless instrumentation could be re-installed and re-commissioned quicker.
The technology driver identified that would enable the achievement of the above objective was wireless technology.
Other motivations to use wireless instruments in a wellhead environment are as follows:- Reduced Costs. Through the elimination of cables, wireless technology greatly reduces the CAPEX associated with instrumentation.Improved Flexibility. Mobile instruments allow devices to be positioned, both temporarily and spatially, as required.
A New Methodology to Determine the Reasonable Buildup Test Time for Tight Oil Wells: A Case Study From the Ordos Basin
Authors: Chu Hongyang , Liao Xinwei , Wang Shenghua , Yuan Lijia , Yuan Zhou , Zou Jiandong , Mu Lingyu , Chen Haoshu 
Published: October 2018

Abstract
In this paper, a new methodology to determine the reasonable buildup test time is derived. The methodology has the ability to determine the starting time of quasi-radial flow (STQF) with considering wellbore storage coefficient, permeability, skin factor, reservoir thickness, and oil viscosity. The curves of pressure derivative flatten out but don’t really enter into radial flow stage at the STQF. The STQF is determined with the use of the constraint for the slope of the pressure derivative curve. Using sensitivity analysis, we build the relationship between the dimensionless factors and the dimensionless STQF. Then the STQF is identified as a reasonable buildup time. We finally verify the methodology with the field pressure test data of typical tight oil wells from the Ordos Basin.
The results show that our methodology is more practical and allows us to accurately estimate the STQF, without any influence on the interpretation results. The parameters all have a significant impact on the STQF including the wellbore storage coefficient, permeability, skin factor, reservoir thickness, oil viscosity, and the wellbore storage coefficient is what affects the STQF the most. In order to reduce the number of those key factors, we use the approach of non-dimensional treatment and obtain the relationship between the dimensionless factors and the dimensionless STQF. The results show that the relationship between the dimensionless STQF and skin factor is power function. With the increase of the dimensionless wellbore storage coefficient, STQF performs a second order polynomial function. Furthermore, a formula to determine the STQF is obtained and the two coefficients of the equation respectively represent the peak of the pressure derivative curve and the occurrence time of 0.5 straight line referred to pseudo-radial flow. We analyze plenty of pressure test data of typical tight oil wells from the Ordos Basin, and find that the two coefficients are fixed on 75.5071 and 0.2048, respectively. The results are very meaningful to determine the STQF of typical tight oil wells.
Application of Nanoparticles in Improving Rheological Properties of Water Based Drilling Fluids
Authors: Al-saba M. T. , Al Fadhli A. , Marafi A. , Hussain A. , Bander F. , Al Dushaishi M. F. 
Published: October 2018

Abstract
Nanoparticles (NPs) have been recently used for different application in the oil and gas industry. Nanoparticles have proven their effectiveness for different applications including; drilling fluids, wellbore strengthening, and enhanced oil recovery (EOR).
In this paper, different types of nanoparticles including Aluminum Oxide, Copper Oxide, and Magnesium Oxide were evaluated at two different concentrations. The main objective of this research is to investigate the effect of adding nanoparticles on the rheological properties of water-based drilling fluid. A simple 7% bentonite water-based mud was used in this study as a reference point. The rheological properties including plastic viscosity, yield point, and gel strength were evaluated at both; standard test temperature of 120°F and room temperature to understand the effect of nanoparticles on the rheological properties. In addition, the filtration characteristics were investigated using both; the standard API filter press at low-pressure low-temperature (LPLT) as well as the high-pressure-high- temperature (HPHT) filter press at 500 psi and 250°F.
The results showed that plastic viscosity was reduced by 50% when NPs were added compared to the reference point. The yield point was improved by 84%, 121%, and 231% for 0.5%Vol Copper Oxide, Aluminum Oxide, and Magnesium Oxide, respectively. In addition, the 10 seconds gel strength was increased up to 95%. A reduction in the fluid loss up to 30% was observed at LPLT conditions. However, the filtration characteristics were negatively affected at HPHT.
Based on the results, there is a good potential for using the above-mentioned nanoparticles to improve the rheological properties, especially the low-end rheology while maintaining low plastic viscosities, which in turns results in a better hole cleaning and more control over the equivalent circulation density.