bluuebunny/crossref_metadata_2025_split huggingface dataset:
A More Sustainable Approach: Nanofiltered Seawater-Based High-Temperature Fracturing Fluids
Authors: Li Leiming , Chang Fakuen F. , Saini Rajesh K. 
Published: March 2019

Abstract
In recent decades, the widespread implementation of horizontal drilling and multistage hydraulic fracturing in unconventional plays has increased the use of fresh water in oilfield operations. The formulation of fracturing fluids with non-fresh water sources such as seawater or produced water are attracting more attention due to the long term sustainability of non-fresh water use.
Fracturing fluids using seawater are available in the industry. But the compatibility between the composition of local seawater and reservoir brine can add complication in the formation damage consideration. For example, if a seawater rich in sulfate comes in contact with formation brine rich in calcium or barium, severe scale can be expected if the proper caution is not taken. Treated seawater with nano-filtration to removal sulfate is a good practice to eliminate this problem. This paper describes a fracturing fluid formulated by using nanofiltered seawater for high temperature applications at 300 to 325°F. The crosslinked fracturing fluid formulation was optimized in the lab to accommodate the nanofiltered seawater, resulting in satisfactory fluid performance thereby enabling the fracturing operations to conserve fresh water.
A high-temperature crosslinked fracturing fluid system was prepared with the nanofiltered local seawater. The fluid system showed robust stability at high temperatures. For example, the fluid viscosity stayed above 400 cP (at 100 sec−1 shear rate) for 2 hr at 300°F, with 45 ppt of the polymer loading. At 325°F, the fluid maintained viscosity above 300 cP for 2 hr with 60 ppt of the polymer loading. The nanofiltered seawater-based fluids was found to be compatible with a number of commonly used fluid additives including biocide, surfactant, and clay stabilizer. The fluid system also showed low formation damage and scaling tendencies. In the coreflow tests at 300°F, a regained permeability of greater than 95% was obtained. In the scaling tests without the presence of scale inhibitor at 300°F, traceable (&lt;0.01 wt %) amount of scale was observed in the mixture of the nanofiltered seawater and high total dissolved solids (TDS) formation brine. Overall, it was found using the nanofiltered seawater can lead to better fluid stability at elevated temperatures, better fluid cleanup, and reduced downhole scaling tendency.
By careful selection of the fluid components, the nanofiltered seawater-based fluid relieve the burden of needing fresh water for hydraulic fracturing treatment, allowing for a more sustainable approach. This paper discusses the technical functions of the key fluid additives used in the fracturing fluid preparation.
New Artificial Neural Network Model for Predicting the TOC from Well Logs
Authors: Sultan Abdullah 
Published: March 2019

Abstract
The key factor for characterizing unconventional shale reservoirs is the total organic carbon (TOC). TOC is estimated conventionally by analysis cores samples which requires extensive lab work, thus it is time-consuming and costly. Several empirical models are suggested to estimate the TOC indirectly using conventional well logs. These models assume the TOC and well logs are linearly related, this assumption significantly reduces the TOC estimation accuracy.
In this work, the design parameters of the artificial neural network (ANN) were optimized using self-adaptive differential evolution (SaDE) method to effectively predict the TOC from the conventional well log data. A new correlation for TOC calculation was developed, which is based on the optimized SaDE-ANN model. 460 data points of different well logs from Barnett formation were used to learn and validate the optimized SaDE-ANN model. The predictability of the SaDE-ANN correlation was compared with the available correlations for predicting the TOC using 29 data point from Duvernay formation.
The TOC was estimated using the optimized SaDE-ANN model with an average absolute percentage error (AAPE) and correlation coefficient (R) of 6% and 0.98, respectively. The SaDE-ANN correlation developed for TOC prediction outperformed the recent models suggested by Wang et al. (2016) and Mahmoud et al. (2017). The new empirical equation reduced the AAPE in predicting the TOC by 67% compared to Mahmoud et al. (2017) model in Duvernay formation.
Large-Scale Chemically Pulsed Fracturing Stimulation of Unconventional Reservoir Using Hybrid FEM-DEM Approach
Authors: Alruwaili Khalid , Han Yanhui , Al-nakhli Ayman , Bataweel Mohammed 
Published: March 2019

Abstract
In this paper, FDEM simulation approach was used to simulate the chemically-induced pulse fracturing of a large-scale wellbore confined by far field stresses. The mesh near wellbore is refined to maximize the model resolution in the critical regions, while coarser mesh elements are used in the regions away from the borehole to minimize the run time. The buildup of gas pressure generated by the reactive chemicals injected inside the borehole is applied to the borehole surface as a time-dependent surface pressure.
Simulation showed that mixed tensile and shear fractures initiate from the borehole extending randomly towards the maximum horizontal stresses. These fractures continue to nucleate and eventually form an elliptical-shaped fracture region around the borehole. As the model undergoes more mechanical damage, shearing along the tip of the created fractures generate new shear fractures. As the pressure loading propagates, radial fracture is created and extended to into the model domain. Explicit deformation of rock near the wellbore is observed during the drilling process.
The computational cost of large-scale dynamic simulation can be prohibitive. In this study the chemically pulsed fracturing processes in a large reservoir is investigated using FDEM approach, which optimizes the computational load while still accurately capturing an explicit deformation response of large rock rocks in the near-well regions using DEM and elastic dynamic response of rocks in the far-field using FEM.
Ultrasound Tomography Based Flow Measurement System; Field Experiences
Authors: Arsalan Muhammad , J. Ahmad Talha , Li Weichang , Adams Robert , Deffenbaugh Max 
Published: March 2019

Abstract
Multiphase flow meters are available from sometime, however, there still remain unresolved challenges. Dependable flow sensing is essential for reservoir management and production optimization. Most commercial water-cut and multiphase flow meters have limitations while measuring over the full range of flow conditions. Exiting meters need recurrent calibration, and have significant capital and operational overheads. In this paper an ultrasonic tomography based meter for water hold-up measurement is presented and the the experiences and challenges of testing the system in the field are shared. The designed system has the potential to resolve the shortcomings of available multiphase metering solutions.
Strategy Towards Unlocking and Accelerated Development of Low Permeability, Microporous Reservoirs-II
Authors: Kumar Kamlesh , Awang Zaidi , Azzazi Mohamed , Hamdi Abdullah , Hughes Brendan , Abri Said 
Published: March 2019

Abstract
The microporous rock types in Upper Shuaiba are low permeability (~ 1mD) rocks occurring in thin (2-5 m) formations within the extensive Upper Shuaiba carbonate formations in Lekhwair. These microporous rocks constitute a significant volume of hydrocarbon in-place. Unlike the higher quality rudist-rich and grainstone rock types, appraisal pilots in the microporous areas have shown poor performance with waterflood development, which is the preferred development concept in the entire Lekhwair field. Two work streams are active in parallel to identify a technically and commercially feasible development option: Phase 1, technology trials to enable a successful waterflood implementation, and Phase 2, further studies to screen the potential of enhanced oil recovery (EOR) techniques and other light tight oil development.
The technology trial work stream, initially considered four initiatives targeting injectivity improvement. To date, trials are complete for abrasive jetting and designer acid stimulation, early results are available for Directional Acid Jetting, and evaluation of Fracture Aligned Sweep Technology (FAST) is ongoing with hydraulic fracturing evaluation accelerated to Phase 1 due to synergies with the FAST evaluation. Trial results to date:
Abrasive Jetting: 7 trials complete, limited success in improving injectivity. Designer Acid Stimulation: 1 trial complete, no to limited injectivity improvement Directional Acid Jetting: implemented in 3 wells, injectivity improvement in early injection FAST: trial planning ongoing Hydraulic Fracturing: trial planning ongoing
This paper discusses the encouraging results and learnings to date with regard to these new technology trials, and the early screening results for the implementation of gas injection as an alternate recovery mechanism.
Efficient Large Volume Acid Fracturing in Openhole Horizontal Well with Pre-Created Circular Notches
Authors: Kayumov Rifat , Arias Urbina Rommel , Bander Khateeb , Aidagulov Gallyam , Chang Fakuen 
Published: March 2019

Abstract
Tight carbonate reservoirs often require acid fracturing stimulation treatments to exploit them economically. In a horizontal well with a long openhole interval across a tight carbonate reservoir, multiple acid fracturing stages might be desirable, however this typically requires permanent completion devices to isolate discrete target intervals into specific stages. Multistage completions face many complications, such as hole-shape dependence, risk of communication between stages, completion deployment risks, and cost. A simplified completion technique was proposed to enable placement of multiple fractures along the openhole reservoir section without a complex completion.
The main challenge in fracturing long openhole horizontal wellbores is limited or lack of control in positioning and orienting initiated fractures. One way to lower the fracturing pressure and force the hydraulic fracture to initiate at one or more desired target depths is to mechanically weaken the formation at specific points along the wellbore. An example of such a weak point is a cavity in the shape of a circular notch cut into the openhole wall. This technique was implemented in a multilateral horizontal water injector well drilled in a tight carbonate reservoir. Four circular notches were cut at predefined depths before stimulation with a goal of creating four separate fractures during one pumping operation. The volume of treating fluids required for the operation was significantly larger compared to a conventional acid fracturing job with only a single fracture propagating. To increase the effectiveness of stimulating all four intervals, degradable particulate diversion material was used during the treatment to temporarily isolate already stimulated fractures and divert treating fluids into less stimulated intervals.
The stimulation treatment was successfully placed after the circular notches were created by coiled tubing using a rotational jetting tool with hydrochloric acid. As the primary result of the circular notching and acid fracturing stimulation, the injectivity index of this well increased almost four times. Temperature, caliper, production, and saturation logs were taken before and after fracturing to evaluate the applied completion approach. These measurements confirmed improved overall injectivity and highlighted areas for further improvements to the new technique, mainly related to preventing overstimulation of untargeted laterals in a multilateral well.
Methodology to Identify Presence of Resin During Post-Fracturing Flowback
Authors: Al-Hulail Ibrahim , Al-Abdullatif Abeer 
Published: March 2019

Abstract
Proppant flowback can cause equipment damage and restrict hydrocarbon production, making it an expensive issue. In response to industry demands for a solution, this paper presents a methodology designed to identify and help prevent flowback issues and to exhibit high cohesive strength to increase the stability of proppant packs.
Liquid resin proppant coating applied during pumping operations shows significant conductivity enhancement and fines control in hydraulic fracturing operations, as compared with traditional curable resin-coated proppant (CRCP). The concentration of resin applied follows proven industry standards. Placement technique and concentration of resin can delay the cure time if needed, which enables the proppant pack to consolidate after placement in the fractures. In addition, it enables the proppant to obtain better grain-to-grain contact in the fracture, and capillary action pulls the liquid resin coating to the contact points of the proppant grains. This process provides a highly cohesive, consolidated proppant pack.
The liquid resin system was designed to be mixed with the proppant immediately before it is added to the fracturing fluid during pumping operations, to consolidate after it is carried into the fracture. Laboratory analysis demonstrates that the resin will prevent fines from flowing back, and it will remain coated on the proppant in the fracture. During the post-treatment cleanout process, a flowback sample was collected and sent to the laboratory to verify that there was no resin content present. The sample was analyzed using Fourier transform infrared (FTIR) spectroscopy, and the resulting spectra were compared to the original resin chart. No resin was present. To confirm the results, a sample of the resin used on the treatment was mixed and analyzed for comparison in FTIR spectra.
This paper describes the methodology to identify the presence of resin during well cleanout and to evaluate the proppant consolidations expected. A new methodology is presented to compare the fluid returned during well cleanup and to evaluate samples in laboratory experiments.
A Novel Method to Determine Kerogen Content of Tight Gas Shale
Authors: Lawal Lateef Owolabi , Mahmoud Mohamed , Adebayo Abdulrauf Rasheed , Syed Rizwanullah Hussaini 
Published: March 2019

Abstract
Reservoir evaluation of source rock is still a challenge because the geochemical assessment of the kerogen content is complicated and time consuming. Existing traditional methods to characterize kerogen involves the removal of inorganic minerals which is a critical preliminary step. The incomplete isolation of kerogen may introduce some errors and uncertainties in kerogen content estimation. The alteration of kerogen microstructure during this process has also been documented. The current approach still requires input from geochemical measurement of total organic carbon (TOC) while the conversion of TOC to kerogen volume requires the precise value of a conversion factor and kerogen density. Overall, there is yet a standard lab or field scale approach to characterize kerogen content. These difficulties and uncertainties prompt the motivation to attempt a new methodology to quantify the kerogen content of unconventional shale from porosity measurements.
Porosity is the basic rock property that is related to the volumetric average of pore space. The distinction between the total and effective porosity is meaningless for shale and this characteristic property has enabled the preservation of its organic content. The recent popularity and growth of different measurement techniques is in part closely tied to the near zero porosity of shale. Two special cases of practical interest are NMR and density porosity measurements which can both be measured in the rock physics lab and well logs. NMR porosity is sensitive to 1H which is naturally enriched in kerogen whereas density porosity must be calibrated to the mineral matrix.
Based on porosity measurements, the emerging aproach is that the kerogen volume fraction is the contrast between NMR and density porosity. Although, the theoretical basis of this approach is not satisfactory, it is straightforward and far less complicated than the existing approaches to quantify kerogen content. We investigate this concept further based on laboratory measurement. We conducted laboratory measurements of NMR porosity, bulk density, grain density and TOC on Qusaiba shale to characterize its kerogen content. In our approach, we conducted the NMR experiment on the shale samples in the dry state without fluid saturation.
Machine Learning in Oil & Gas Industry: A Novel Application of Clustering for Oilfield Advanced Process Control
Authors: Patel Kalpesh , Patwardhan Rohit 
Published: March 2019

Abstract
Data Analytics is an emerging area that involves using advanced statistical and machine learning algorithms to discover information & relationsips present in different types of data. The work described in this paper illustrates the application of machine learning techniques to an Oilfield Advanced Process Control (APC) project involving deployment of APC at a large onshore conventional oilfield in Saudi Aramco. APC implementation enables better control and optimization of the production from hundreds of oilwells.
APC rollout at the large oilfield involved APC deployment on 300+ oil wells. Using conventional APC implementation methodology, the rollout would be very difficult to manage and would have taken about 3 man years which was not practical. Use of innovative data analytics techniques was essential to ensuring the timely deployment of such a large scale APC project. A machine learning algorithm used to cluster similarly behaving wells, enabled significant (80%) reduction in the engineering effort and operator involvement in developing the models for each well. This allowed the implementation to be completed one year in advance thus realizing the APC benefits earlier than planned.
How Over 60% Recovery Achievable in a Multi-Layer, Heterogeneous Sandstone Reservoir
Authors: Lu Xiaoguang , Xu John , Feng Lijing , Yang Qing , Li Guoqiang , Lin Lihua 
Published: March 2019

Abstract
The XB Field in China contains more than 100 thin sand units deposited in a non-marine environment, which results in an extremely heterogeneous sandstone reservoir. Comparison with global field analogs of similar reservoir characteristics indicates that the &gt;60% ultimate recovery in the XB Field is much higher than average. This paper reviews the over 50 years of production history and summarizes its development strategies, successful reservoir management practices, key IOR/EOR technologies and lessons learned, which can benefit efforts of maximizing recovery in other reservoirs.
This paper begins by summarizing the basic reservoir and fluid characteristics as well as the production performance history. This is followed by a benchmarking analysis focused on reservoir heterogeneity, fluid properties and recovery factor against global analog reservoirs. Finally, the authors highlight the development strategy, key IOR/EOR methods, and integrated reservoir management practices based on fit-for-purpose reservoir and remaining oil characterization studies.
The benchmarking study against global analogs shows the XB reservoir to possess much higher heterogeneities and poorer fluid properties than average. The field is expected to achieve an ultimate recovery of more than 60%, which is substantially higher than the average of 36.7% and P50 value of 36% based on global reservoir analog in C&C Reservoirs DAKS. The key IOR methods applied include pressure maintenance through water injection starting at early development stage, infill drilling, and chemical EOR methods. Water injection and infill drilling have helped improve recovery by 30% and 20%, respectively. Water injection optimization has been applied throughout the 50-year production history, focused on by-passed oil or poorly swept areas. Zonal water injection, subdivision of injecting-producing unit, modification injection pattern and cyclic water injection are methods of this category. Other IOR methods, such as horizontal well targeting by-passed oil, profile modification, and fracturing of low permeability reservoir sands also contribute to the high recovery factor. When the field entered the mature production stage, field-wide polymer and ASP flooding have been implemented based on numerous laboratory studies and pilot tests. The chemical EOR application in this field is one of the most successful cases in the world. Polymer flood and ASP flood are expected to achieve incremental recovery factor of 10% and 20%, respectively.
The XB Field case suggests that many mature fields in the globe have the potential to further improve their recovery. Most of the technologies discussed in this paper are well established, conventional, inexpensive and readily available. The key point is that detailed reservoir characterization, remaining oil identification and application of lessons learned from global analogs are of prime importance.
Beyond One-Dimensional Evaluations: The Search for Genetic Reservoir Regions through Time & Space
Authors: Hadidi Shahab , Yaarubi Hilal , Baaske Uwe , Suwannathatsa Sakharin , Farsi Shadia , Bazalgette Loic , Hamdoun Lana 
Published: March 2019

Abstract
The infill potential of one of the most complex fractured carbonate reservoirs in the Sultanate of Oman has been evaluated through the integration, visualization and analysis of different data sources. The field has been split into different simplified genetic geobodies which contain the culmination of facies changes that define rock quality, fluid fill, oil saturation distribution and fracture network, amongst other properties that affect fluid flow. The long production history of more than 45 years, along with the large number of logged long horizontal wells scattered around the field, were key enabler for the analytical methodology.
Production data, coupled with resistivity logs in horizontal wells, viewed through time were the backbone of the analysis. Data analysis was achieved by combining these data in a single platform and performing the analysis at different slices of time. At each timeslice, different interpretations were inferred that explain the observed production behaviour and remaining oil saturation from the logged wells. The interpretations were narrowed down into a minimum number of realizations by combining interpretations from the same area gathered from different slices of time.
The analysis has resulted in the identification of four genetic performance regions in the field. Each region approximates a primary depositional facies belt and has a general defined relative behaviour of initial wells potential, water-cut development, initial and remaining oil saturation and, most importantly, infill wells potential. The analysis has aided in narrowing the subsurface uncertainties and has given a promising explanation for the large variations in wells behaviour. Infill wells opportunities have been identified, selected and ranked relatively in each of the regions.
The value of data analytics on large volumes of acquired information normally not used was demonstrated. Visualization of different data sources in one platform is a challenging task that usually stops engineers from experimenting. The team has found fit for purpose solutions to visualize different data sources through time. The shift of mind-set from uncertain complex models and evaluations into finding simple genetic performance regions of the reservoir was vital in unravelling infill potential.