bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Study of Artificial Lift Strategy Selection and Optimization for Unconventional Oil Wells in the Williston Basin
Authors: Escobar Patron Katherine , Zhang Kathy , Xu Tao , Lu Haidan , Cui Shihao 
Published: October 2018

Abstract
As a major unconventional resource play, the Williston basin contributes more than 10% of total U.S. crude oil production. Due to significant concerns about net present value and payback period, the process to select the optimum artificial lift method has always been a top priority for operators. In this case study, we investigate the potential artificial lift strategies for new wells in Williston basin. The objective is to propose an artificial lift strategy that handles the challenges associated with unconventional resources and that maximizes the asset value.
In this study, a novel workflow that replaces subjective decisions with objective analysis has been applied for the process of selecting the lifting strategy that will best achieve an operator's goal based on analysis of technical criteria and economic calculated results. An initial prescreening is performed to narrow down the number of applicable artificial lift systems that will meet the technical challenges of the well. Then, the selected artificial lift methods are evaluated combining a steady state flow simulator and a reservoir model to determine the well performance and response to each lift system. This response is integrated with an economic model to determine the net present value of the proposed strategy. Different strategies and sensitivities on key parameters as oil price, expected production, and water cut are performed to determine the optimum artificial lift approach. The ability to include future well performance based on a reservoir model helps in building a strong analysis that goes beyond current well conditions and includes the changes that occur to the reservoir during the production phase, such as pressure depletion and consequent production decline. Those changes drive the need to switch from one artificial lift system to another as conditions evolve. The workflow allows the user to determine the best time to start the selected artificial lift system and the appropriate transition time to a second artificial lift method.
For the Williston basin case study, only electric submersible pumps (ESP) and jet pumps (JP) can be implemented during the high-flow-rate period. As production declines, a transition to a lower-flow-rate method is required. Hydraulic rod pump systems are considered the most appropriate transition method because they make it possible to pump the required volumes from deep installations. A production forecast is combined with two different water cut scenarios to evaluate the impact on the economic results of the project.
The successful use of this workflow has proven its ability to analyze the life cycle of an unconventional well and establish a process for artificial lift selection. Furthermore, the current workflow is flexible enough to be extended to other fields with different input variables.
Modifying Proppant Surface with Nano-Roughness Coating to Enhance Fracture Conductivity
Authors: Shrey Shubhankar , Mokhtari Mehdi , Farmer Warren R. 
Published: October 2018

Abstract
Nano-Roughness coating reduces the fluid/solid interaction leading to super-hydrophobicity or the Lotus effect. The objective of this study is to determine how this phenomenon can be applied in petroleum production system to enhance fluid flow in propped fractures using nano-roughness coating on the surface of proppants. The permeability and the wettability of coated proppant packs are compared with non-coated packs to determine the reduction in friction or enhancement in fracture conductivity.
The simulation of flow in a proppant pack is done using sand packs of different permeabilities. The base case for the work is established using sandstone samples with various permeabilities. The sandstone samples include Gray-Berea with uncoated absolute permeability of 86 mD, Buff Berea with uncoated absolute permeability of 374 mD, Bentheimer sandstone with uncoated absolute permeability of 277 mD and Leopard sandstone with the uncoated absolute permeability of 803 mD. The sand packs used are 20/40 mesh with uncoated absolute permeability of 31 D, 40/60 mesh with uncoated absolute permeability of 22 D and 50/70 mesh with uncoated absolute permeability of 21 D. After measuring the absolute permeability, wettability (using contact angle method) and relative permeability, all the samples were coated and the properties were measured again.
The results show that the modification enhances fluid flow through pores. The surfaces for all the samples were altered from a hydrophilic to a hydrophobic surface. The contact angle between the fluid and samples was observed to be almost 90° with water and &gt;60° for oil, after modification. This confirms modification of samples to partial-wetting state. An increase in absolute permeability is observed from 14.54% for Gray-Berea to 184% for Leopard sandstone. The increase in absolute permeability for sand packs is observed from, 23% for 20/40 mesh sand, to 5.28% for 50/70 mesh sand. It was observed that modification is more efficient for a sample with a higher permeability, but further studies are in process to relate the permeability enhancement to total surface area.
Since the production rate of tight sandstone and shale reservoirs is low, especially in liquid-rich reservoirs and significant amount of water is injected for reservoir stimulation, enhancement in fracture conductivity resulting from proppant surface modification can have a meaningful impact on the recovery of these reservoirs. This study uses experimental techniques to show the effectiveness of nano-roughness coating on the reduction of friction which can lead to enhancement in fracture conductivity.
Validation of the Generalized Scaling Curve Method for EUR Prediction in Fractured Shale Oil Wells
Authors: Saputra Wardana , Albinali Ali A. 
Published: October 2018

Abstract
The generalized scaling curve method (Patzek et al., 2017) was proposed as a solution to substitute the empirical decline curve analysis that may be inappropriate to fit the production of shale oil wells. As the method is derived from the physics-based model on fractured well geometry, it can match the rapid one over square root of time declines in early production and moderate exponential declines in boundary- dominated production, where the popular decline curve analysis struggles. The proposed method was believed to deliver the results that are comparable to numerical reservoir simulation with less time and data requirement.
In this paper, the generalized scaling curve method is validated using field data from Niobrara and Eagle Ford shales. The results are then compared to an analytical solution from an anomalous diffusion approach (Albinali et al., 2016) that has been successfully applied to the data. A synthetic reservoir simulation model is also created and run with the reservoir simulator GigaPOWERS. The simulated oil production rate is then adopted as the synthetic data to feed the generalized scaling curve input. Sensitivity analysis is conducted using the numerical model to investigate the role of porosity, permeability, gas oil ratio, initial reservoir pressure and hydraulic fracture spacing on affecting the scaling curve.
The results suggest that the generalized scaling curve is a robust practical approach that is somewhere in between decline curve analysis and numerical reservoir simulation and can be used to predict the EUR of shale oil wells. The method is shown to give similar results to the analytical and simulation solutions with predominantly requiring production data only as the favoured empirical decline curve analysis.
Upscaling of Microgel Treatment in Fractured Reservoirs: Experimental and Simulation Investigation
Authors: Alhuraishawy Ali K. , Wei Mingzhen , Bai Baojun , Almohsin Ayman 
Published: October 2018

Abstract
Excess water production through fractured reservoirs is one of the most serious problem for sweep efficiency and oil recovery factor. Gel treatment have been widely used to plug the fractures and reduce excess water production to improve macroscopic sweep efficiency. Field studies showed that gel treatment can be successfully applied in mature oilfield and fracture reservoirs to reduce water production and improved oil recovery factor. The objective of this paper is to understand the preformed particle gel (PPG) propagation through fractures by conducting laboratory work and upscaling these data to filed scale to investigate which parameters can be more affected gel treatment.
The semi-transparent fracture model was made of oil-wet carbonate core and acrylic plates with 1.5 mm fracture width. Seawater was used for brine flooding and to prepare the swollen gel. The experimental results showed that the preformed particle gel improved the oil recovery by 12% with 20% water cut reduction. The experimental results were history-matched using UTGEL simulator and an excellent agreement between lab data and simulation data was achieved. The simulation results of the filed scale indicated that the PPG concentration and PPG treatment timing are the main PPG design variables and the conformance control improved when PPG concentration increased and when PPG treatment applied early. Upscaling the laboratory results to filed scale provide a deeper understanding of PPG treatment and can investigate the effect of PPG concentration for PPG application in fractured reservoirs.
Laboratory Screening Tests to Further Characterize Low-Salinity Waterflooding in Low-Permeability Sandstone Reservoir
Authors: Alhuraishawy Ali K. , Almansour Abdullah , Bai Baojun , Wei Mingzhen , Imqam Abdulmohsin , Geng Jiaming 
Published: October 2018

Abstract
The latest oil price decline simply increases the demand for enhanced oil recovery (EOR) and pushes research developers to keep improvements in oil recovery. The goal is always to recover as much oil as possible at the lowest possible cost. Low-salinity water flooding (LSWF) is an EOR method that operates at a lower cost than other EOR methods, which makes it a preferred area of interest for oil industry economists, who continue to call for EOR costs to come down. The objective of this study was to test the ability of low-salinity waterflooding to improve oil recovery from low permeability sandstone reservoirs. Four types of tests were conducted: imbibition, interfacial, core flooding, and zeta potential tests. Three key factors were studied: salinity of the injected water, type of salt, and aging time. Their influence on the amount of oil recovery, stabilized injection pressure, pH, and permeability reduction was determined. Berea sandstone was used in all experiments. Sodium chloride (NaCl) and calcium chloride (CaCl2) were used to prepare the brine. The imbibition test and core flooding results showed that the oil recovery increased as brine concentration decreased for both sodium chloride and calcium chloride. Sodium chloride resulted in higher oil recovery than calcium chloride at a certain salinity in both imbibition and core flooding tests. The oil recovery factor results during the second water flooding cycle (after aging for 24 hrs.) showed more oil recovered during low salinity waterflooding. The stabilized inaction pressure was higher for CaCl2 than NaCl injection at certain flow rate and brine concentrations. Effluent pH values became more basic during low salinity water flooding for both sodium and calcium chloride. The zeta potential results showed that decreasing the salinity of injected water resulted in a decrease of the zeta potential value for both injection cycles, before and after aging for 24 hours. Results also imply Low- salinity water flooding redistributes the flowing paths by releasing sand particles and some fine minerals causing the flow path to narrow. Thus, low salinity water flooding can create a new streamline (fluid flow diversion) and improve both displacement and sweep efficiency.
Effects of Injection Parameters on Foam Rheology in Vertical Wells
Authors: Sinde Seydou 
Published: October 2018

Abstract
Foam underbalanced drilling is the use of the entrapped gas bubbles within the continuous liquid fluid as the drilling medium to overcome one the most challenging drilling problems: lost circulation, regardless of its various reasons. It is also used to improve the reservoir productivity by preventing the formation damage and the skin factor. The complexity of foam composition as a drilling fluid is by the fact that it is affected by both constituent ingredients: liquid and gas as well as the downhole conditions. The combination between compressible gas and incompressible liquid in addition to the intrusion of annular cuttings and influx fluids necessitates better understanding of the mechanism of the hydrodynamic flow of the three-phase. One of the first fundamental steps in achieving that is to intensively conduct the experimental and analytical studies of foam rheology. A hydraulic model, based on the recent experimental and analytical conclusions, was developed not only for better studying foam rheology, but also for analyzing the exhaustive foam drilling operation from the injection lines till the cuttings removal on the surface. In order to simplify the use of the complex mathematical equations and iterative procedures, the programming language VISUAL BASIC has been used and implemented for the modeling. For the rheological study, results concluded the dependence of foam hydraulics, primarily, on rheology. The results also revealed the influence of the rheological properties by drilling parameters such as injection pressure, liquid and gas rates, rate of penetration (ROP), and surface back-pressure. If the increase of injection pressure acts to decrease the flow power index (n) and Reynolds number (NRe), it, in contrast, increases the flow consistency index (k) and friction factor (FF). Gas injection opposes the effects of the injection pressure, whereas liquid injection has variable effects depending on the nature and amount of the addition.
A Comprehensive Review of Differential Sticking, Spotting Fluids, and the Current Testing and Evaluation Methods
Authors: Alshaikh Abrar A. , Amanullah Md. 
Published: October 2018

Summary
Differential-pressure pipe sticking is one of the biggest problems encountered during drilling and also one of the leading causes of high nonproductive time. It usually occurs in permeable or depleted formations due to the cession of drillstring movement to connect a new pipe, make a trip, overcome a drilling problem, etc. As the drillstring becomes stationary, it gets embedded into the filter cake because of the pressure difference between the formation and the wellbore, and also due to the high filtration in the presence of a high permeable zone. The sticking bonds created in the pipe/filter-cake interface due to the combined action of adhesive and cohesive forces acting in the vicinity of the sticking zone prevent any movement of the drillstring in the wellbore. Therefore, the driller is unable to rotate or reciprocate it without releasing it by mechanical or chemo-mechanical actions.
The industry uses various spotting fluids to recover a differentially stuck pipe as soon as possible as any delay may lead to an increasingly complicated rescue operation with the possibility of abandoning the well in extreme conditions. Therefore, the selection of a suitable spotting fluid that is compatible with a particular mud composition is very important to improve the success rate of a rescue operation. Use of an incompatible spotting fluid, instead of helping in recovering a stuck pipe, may lead to disastrous conditions. There are other factors that can aggravate the recovery of a stuck pipe significantly. Therefore, understanding the root causes of this problem, the conditions that lead to this problem, and the working mechanism of various spotting fluids along with their application domains, are very important for prevention, remediation, and improving the ease of recovery of stuck pipe.
This paper provides a comprehensive review of pipe sticking problems with emphasis on differential pipe sticking encountered while drilling and the various spotting fluids used to recover a stuck pipe. The paper further discusses the current testing and evaluation methods used for screening, testing, and evaluating spotting fluids to select the superior and reject the inferior along with their advantages and disadvantages. Finally, a recommendation is made to improve the testing and evaluation method and overcome the limitations of conventional methods and apparatus.
Induction Versus Permanent Magnet Motors for ESP Applications
Authors: Xiao J. J. , Lastra Rafael 
Published: October 2018

Abstract
This paper provides an overview comparing Induction Motors (IM) and Permanent Magnet Motors (PMM) for Electric Submersible Pump (ESP) applications. What are the design differences and how the performances of the two types of motors are stacked against each other? What are the advantage and unique applications of PMMs? Why and how are PMMs controlled differently from IMs? Are there safety aspects that field engineers need to be aware of with PMMs? These questions will be addressed in the paper.
The information presented includes literature review and latest R&D results. It covers operating principles of IM and PMM, selection of permanent magnet materials, operating frequency, stator windings and magnetic poles.
PMMs offer better efficiency, higher power factor performance and compactness. Ideal applications include slim well applications, through-tubing rigless deployment, Y-tool completion and Electric Submersible Progressive cavity Pump (ESPCP). The paper will also shed some light on why conventional IMs cannot be used to drive ESPCPs directly without speed reduction gearboxes.
It is very likely that the use of PMM will increase for ESP applications in the near future and this will require engineers to acquire a basic understanding of this technology. A high level comparison between IM and PMM is missing in the ESP industry and this paper fills the gap. PMMs need to be operated with a different type of control for Variable Speed Drive (VSD) and require matching transformers for high frequency applications. The paper also intends to highlight the safety aspects of PMMs in shop and field handling.
Evaluation of EOR LS Water Flooding in Sandstone: Eliminate the Role of Clay
Authors: Al-Saedi Hasan N. , Almansour Abdullah , Flori Ralph E. , Brady Patrick V. 
Published: October 2018

Abstract
Recently, we proposed a chemical mechanism for the role of clay in sandstone during low salinity water (LS water) flooding using acetate to simulate the oil-bound carboxylic acids with the reservoir (Al-Saedi and Brady 2018). In this study, we propose to quantify the control of mineral composition and water chemistry on water/rock interactions by using oil during low salinity waterflooding of spatially heterogeneous sandstone porous media. A sandstone core and free-clay sand core were prepared in chromatography columns and were water flooded sequentially with high-low salinity water at the reservoir temperature of 90ºC. Brine with high salinity (100,000) ppm was injected to simulate formation water. Then, Inflow LS water (1100) ppm. One of the columns only contains quartz, to investigate the role of the clay in the mechanism of LS water enhanced oil recovery (EOR). The other columns contained quartz and different quantities of clays. The results showed that during flooding, the free-clay column with LS water the oil recovery from the quartz column was as great as that of the clay-containing cores. On the other hand, our previous investigation showed a noteworthy desorption of Ca2+ from the free-clay core surface. That indicates further RCOO- detachment in the absence of clay. The pH also increased significantly during LS water flooding for the free-clay column.
Predictive Data Mining Techniques for Mud Losses Mitigation
Authors: Al-Hameedi Abo Taleb , Alkinani Husam H. , Dunn-Norman Shari , Flori Ralph E. , Hilgedick Steven A. , Alkhamis Mohammed M. , Alshawi Yousif Q. , Al-Maliki Madhi A. , Alsaba Mortadha T. 
Published: October 2018

Abstract
Wells drilled in the Rumaila field are highly susceptible to lost circulation problems when drilling through the Hartha formation. This paper presents a comprehensive statistical work and sensitivity analysis models of the lost circulation events for more than 300 wells. Moreover, this study will demonstrate an integrated analysis regarding the most significant drilling parameters, which have a pivotal impact on the lost circulation to provide the greatest chance of mitigating or avoiding lost circulation in the Hartha formation.
Lost circulation events are extracted from daily drilling reports, final reports, and technical reports. Key drilling parameters are analyzed using statistical software to understand the relationship between the mud losses and various drilling parameters such as MW, ECD, Yp, ROP, SPM, RPM, WOB, flow rate, and bit nozzles. The sensitivity analysis is conducted to examine the impact of each parameter in all models. In addition, variance inflation factor (VIF) method is used to test for the multicollinearity phenomena in each model to maximize the accuracy and to obtain a solid mathematical model.
The volume loss model is conducted to predict lost circulation in the Hartha formation. As a proactive action, this model can be used to estimate the volume loss prior drilling the Hartha formation. Observations that have been made from the volume loss model are MW, ECD, and Yp have a significant impact on lost circulation respectively; however, SPM, RPM, and ROP have a minor effect on the volume loss model. Equivalent circulation density (ECD) model is obtained to estimate ECD in the Hartha formation, and from this model can be deduced that MW, ROP, and Q have a significant impact on ECD respectively; nevertheless, RPM and Yp have a minor impact on the ECD. The rate of penetration model is made to estimate ROP in the Hatha formation. It is concluded that WOB, SPM, and RPM have a significant impact on the ROP respectively, but MW, ECD, and Yp have a minor influence on the ROP. In addition, engineering solutions are developed to give a clear image regarding lost circulation, and it will provide a unique statistical study and coherent sensitivity analysis of all factors which have an essential or a small impact on this issue.
Due to the lack of published studies for this formation, this study will provide a unique understanding for lost circulation events, drilling fluid properties, and operational drilling parameters, which have a prominent or a minor impact on the mud losses issue. Lost circulation will be illustrated in terms of causes, consequences, recommendations, and guidelines to reduce or avoid unwanted losses. In addition, this work can serve as a practical resource for drilling through the Hartha formation.