bluuebunny/crossref_metadata_2025_split huggingface dataset:
Influences of Anisotropy on Shale Brittleness Evaluation
Authors: Salah Mohamed , Ibrahim Mohamed Mohamed , Ibrahim Mazher , Pieprzica Chester 
Published: September 2019

Abstract
Shale brittleness is one of the most important parameters to assess how the shale behaves upon subjecting to applied stress and evaluate the hydraulic fracturing treatment. Presence of lamination is a common feature in organic-rich shales which significantly create anisotropy in elastic properties and rock brittleness due to the platy minerals such as clays that have the tendency to be aligned in parallel orientation during burial and the digenesis process. Characterization of anisotropy and the understanding the controlling factors on the reservoir rock elastic properties, rock strength and rock brittleness are crucial for successful production and development of shales.
The objective of this paper is to extend the previous discussion by (Ibrahim et al 2019), in which an integrated approach has been developed for evaluating the shale fracability, to explain the influences of shale lamination and emphasize on the effects of anisotropic in elastic properties on brittleness of organic-rich shales to better demonstrate the process of screening hydraulic fracturing candidate intervals and improve the hydraulic fracturing design which can eventually improve the production forecast.
In this paper, we propose the vertical transverse isotropic (VTI) modeling to investigate the effect of shale lamination and anisotropy on rock elastic properties, tensile failure and wave velocity normal to bedding plane, which differ than they are when parallel to bedding plane.
Throughout this study, it is observed that there is a remarkable effect of anisotropy parameters on rock elastic properties and tensile failure. This method help obtain more accurte brittleness index and give precise guide to optimize perforation depths choice and hydraulic fracturing design that can result in optimized hydrocarbon productivity.
Smart Unconventional Approach to Universal Oil-Based Mud Removal Using High-Performance Bio-Micromaterial
Authors: Pernites Roderick , Clark Jordan , Fu Diankui 
Published: September 2019

Abstract
Using a single universal spacer surfactant to clean a wide variety of oil-based mud (OBM) is considered the "Holy Grail" of spacer fluid system. Specialty chemical and service companies have devoted intense research and vast resources to develop the ideal spacer surfactant, but their efforts have not led to a singlesurfactant solution due to uniquely different drilling mud properties. It is no surprise to experts in the field that surfactant selection is extremely mud specific. For instance, one surfactant may effectively clean certain types of OBM, but fail in another mud from a different location that has the same density and base fluid. As a result, service companies have numerous surfactants in their portfolios, further complicating logistics and operations. This paper presents the discovery of a high-performance universal biomicromaterial, which can significantly improve the cleaning performance of any surfactants/spacer fluids to remove most, if not, all types of drilling mud. The innovative bio-micromaterial is an eco-friendly byproduct from another industry.
Successful cleaning of the drilling mud was demonstrated by standard rotor testing with different OBM samples from across North America, and the percentage of mud removal was determined. Furthermore, the ability of the innovative micromaterial to efficiently clean the mud was verified by measuring the strength of bonding between the set cement and the metal casing that had been cleaned by the spacer fluid after drilling mud contamination. Basically, this new procedure simulates downhole fluid displacement by the intermediate spacer fluid, which is ahead of the cement slurry, displacing the mud. Stability and mixability were also studied to determine the effect of the bio-micromaterial addition to the spacer fluid. Finally, a fundamental scientific study using thermogravimetric analysis and imaging techniques was done to characterize the material and determine its thermal stability.
For the first time, newly discovered, high-performance, universal cleaning micromaterial is presented to enhance the OBM removal of any spacer fluid design. This groundbreaking research has successfully demonstrated the unconventional advanced material to be a universal cleaning, single-additive spacer admixture for a wide variety of drilling mud from various regions across North America. To our knowledge, based on extensive literature search, this is the first report about the application of this natural waste product in wellbore cleaning fluids like the spacer.
Maximizing Value from an Investment in Geophysics
Authors: House Nancy , Mencin Alan 
Published: September 2019

Abstract
It is well known that geophysics, particularly the reflection seismic method, significantly changed the probability of economic success for conventional hydrocarbon deposits over the past 100 years. Astechnology improved theimages could be leveraged to determine the presence of gas and also thereservoirproperties of the rock themselves. As unconventional resource plays took off, many North American Basins have been carpeted with high quality 3D seismic that is routinely be exploited to reduce drilling risks, improve completion efficiency and high-grade acreage based on seismic indicators of Total Organic Content(TOC), brittleness, or ‘fracability’. But as the capabilities increased so did the cost. Proprietary acquisition underwritten by a single company was restricted to companies with largegeologic and geophysical budgets. Speculative data acquisitionand licensing was employed more and more to reduce the cost of 3D seismic toindividual companies. Thegeophysical companies underwrote the cost of 3D seismic surveysexpecting to makeenough to cover costs through licensing arrangements and hopefully make a profit. This was done by licensingthe data to numerouscompanies. Each of the licensees wouldthen get the benefit of the seismic data where it was needed at a fraction of the cost of proprietary acquisition. Lately the use of high-quality 3D seismic integrated with reservoir, completion and production data is used tolowerdrilling risks, high grade acreage and quantify the extent of unconventional resources. (Stephen Rassenfoss, JPT Emerging Technology Senior Editor, 2015) The technical requirements of gathering and processing the seismic data that allow the extraction of reservoir and rock properties from tight rocks and shale reservoirs are high and consequently also very costly. How can the maximum value be extracted from the investment? The investment in 3D seismic for conventional and unconventionalreservoirs must be carefully weighed against the economic benefits. We propose a simple method to evaluate the investment in seismic using simple decision analysis coupled with expressing the cost in ways that are applicable to the full economic benefit of the data.
Data-Driven Model for the Drilling Accidents Prediction
Authors: Antipova Ksenia , Klyuchnikov Nikita , Zaytsev Alexey , Gurina Ekaterina , Romanenkova Evgenia , Koroteev Dmitry 
Published: September 2019

Abstract
Majority of the accidents while drilling have a number of premonitory symptoms notable during continuous drilling support. Experts can usually recognize such symptoms, however, we are not aware of any system that can do this job automatically. We have developed a Machine learning algorithm which allows detecting anomalies using the drilling support data (drilling telemetry). The algorithm automatically extracts patterns of premonitory symptoms and then recognizes them during drilling.
The machine learning model is based on Gradient Boosting decision trees. The model analyzes real time drilling parameters within a sliding 4-hour window. For each measurement, the model calculates the probability of an accident and warns about anomaly of particular type, if the probability exceeds the selected threshold.
Our training sample comes from 20+ oilfields and consists of sections related to 80+ accidents of the following types: stuck pipe, mud loss, gas-oil-water show, washout of pipe string, failure of drilling tool, packing formation, that occurred while drilling, trip-in, trip-out, reaming.
We have designed the prediction model to work during drilling new wells and to distinguish the normal drilling process from the faulty one. One can configure the anomaly threshold to balance amount of false alarms and the number of missed accidents.
To evaluate quality of the model we measure such data science metrics as ROC AUC score and confusion matrices. While testing model can identify 24 accident from 30 with high confidence, whereas for the others there is still a room for improvement. Our findings suggest that including more accidents of underrepresented types will improve quality. Other data science metrics also support aptitude of the model. Finally, having data from multiple heterogeneous oilfields, we expect that the model will generalize well to new ones.
This paper presents a good practice of development and implementation of a data-driven model for automatic supervision of continuous drilling. In particular, the model described in the paper will assist specialists with drilling accidents prediction, optimize their work with data and reduce the nonproductive time associated with the accidents by up to 20%.
Robustness of Novel Low-Tension Gas LTG Floods in High Salinity and High Temperature Reservoirs
Authors: Nguyen Nhat , Ren Guangwei , Mateen Khalid , Ma Kun , Luo Haishan , Neillo Valerie , Nguyen Quoc 
Published: September 2019

Abstract
Low-Tension Gas (LTG) has emerged as a novel enhanced oil recovery injection strategy, employing foam in place of polymer to displace the oil bank created with the help of ultra-low-IFT (ULIFT). In our prior work, the process was successfully employed, both in sandstones and carbonates, to achieve attractive oil recoveries with relatively low surfactant retention. However, earlier experiments were carried out at high flow rates in relatively high permeability cores. To improve the robustness of this novel injection scheme, it is necessary to examine it under wider practical environments. Therefore, in this work, experiments are conducted in carbonate and sandstone cores, at lower injection rates and rock permeabilities, to determine whether the foam could provide the necessary mobility control with this novel EOR technique. Initially, a lower flow rate (1 ft/D) experiment is conducted in relatively high permeability (388 md) sandstone core to compare it with the earlier results under a higher injection rate (4 ft/D). Subsequently, even further reduced injection rate (0.5 ft/D) is employed in a sandstone core with one order of magnitude lower permeability (36 md). Two other corefloods with Estaillades limestone (166 md) and Richmont (7 md) are carried out to extend the comparison to carbonate rocks. Surfactant retentions are determined. It is found that four-times-lower injection rate (1ft/D) just slightly delayed oil production, and achieved comparably high oil recovery (87%), indicating a good mobility control. Proportionally reduced pressure drop during slug injection implies similar total fluid mobility. Accordingly, salinity propagation examined from effluents shows slight delays. Even with ten-times-lower permeability sandstone (36 md) at a lower total injection rate (0.5 ft/D), comparable oil recovery (84%) and salinity propagation are found, despite of much lower foam strength. With an intermediate-permeability Estaillades limestone (166 md), compared to high permeability sandstone, oil production is delayed, but comparable eventual oil recovery (88%) is obtained. The delay could be due to higher surfactant retention (0.301 mg/g). The delayed effluent salinity propagation is noticeable, which may be caused by increased total fluid mobility. Finally, extremely low permeability Richmont (7 md) indeed adversely impacts the oil recovery (~58%) and the salinity propagation. This could be attributed to higher surfactant retention and/or decreased foam stability due to oil-wet rock surface. The works here test the robustness of the LTG process in more practical reservoir conditions and have widened its applicability. Demonstration of its feasibility in low-permeability reservoirs, where use of polymer is not currently feasible, will greatly promote the testing and deployment of this technology in the future.
Understanding Heel Dominant Liquid Loading in Unconventional Horizontal Wells
Authors: Kannan Subash , Nagoo Anand , Lea James 
Published: September 2019

Abstract
As a common occurrence in production operations, liquid-rich horizontal gas (and gassy oil) wells in unconventional plays develop severe instabilities at different stages of their well life. In this novel work, we first quantify the three-phase gas-oil-water multiphase flow behavior leading up to the characteristic severe loading signatures in order to better understand the dynamic heel-dominant liquids loading. Then, we demonstrate how a simple analytical diameter-and-inclination-dependent critical gas velocity equation can be used to determine the onset of the severe loading instabilities in a variety of artificial lift/liquid loading mitigation strategies, namely end-of-tubing landing (EOT), tubing/casing sizing, gas lift variations and tail pipe/dip tube. Actual high frequency bottom hole pressure data along with measured surface conditions will be used to evaluate the slugging behavior and recreate using analytical multiphase flow simulator. The flow conditions will be extrapolated to the heel/near lateral section of the well and simulated for various lift strategies.
Novel Non-Aromatic Non-Ionic Rheology Modifiers for High Paraffinic Crude Oils
Authors: Sokhanvarian Khatere , Diarra Alfa , Fernandez Jorge , Stanciu Cornell 
Published: September 2019

Abstract
Wax and paraffin precipitation is a major problem around the world, costing the petroleum industry billions of dollars yearly. As temperature drops below the Wax Appearance or Wax Precipitation Temperature (WAT/WPT) of crudes, paraffin starts to precipitate out and restrict or block the effective flow. There are different methods, such as mechanical and chemical remediation to deal with wax issues. Among the latter ones, the use of surfactants is favorably looked upon since they are small molecules with surface activity properties. This study aims to introduce novel aliphatic non-ionic surfactants with different chain length and degree of ethoxylation. In addition to chain length, the impact of branching on the hydrophobic part of the surfactants was also studied.
A waxy crude oil from Brazil was characterized through determining its carbon distribution, WAT, viscosity and density based on industry standard methods. Several surfactants with different combinations of chain length/ethoxylation number were then selected for screening. The performance of surfactants was evaluated based on data obtained from treated crude versus the control sample through different experiments. Rheology studies were conducted at 50 to -10°C and at shear rates of 5 and 300 s-1. The cold finger instrument was utilized to determine paraffin content of the untreated and treated crude. Finally, the paraffin crystal size was analyzed through microscopic studies.
The results showed that shear rate can affect the wax treatment outcome as well as the effective concentration of surfactant. Therefore, it is important to assess the rheology at high and low shear rates. Some surfactants in the present study performed great at both low and high shear rates and were able to reduce the viscosity by 80% at temperatures well below WAT of the crude oil. The microscopy results confirmed that wax crystals were reduced in size and were more dispersed after treating the crude with these surfactants. The findings from High Temperature Gas Chromatography showed that the deposition of heavy fraction part of crude (C40+) is reduced after treating the crude oil with the surfactants in the present study.
The current study addresses the wax precipitation/deposition challenges of heavy crudes and proposes mitigating them through the use of some new non-aromatic non-ionic surfactants. The chemistries and findings of this research help the oil and gas industry to save money and time by mitigating flow assurance problems.
Semi-Analytical Modeling of Multi-Mechanism Gas Transport in Shale Reservoirs with Complex Hydraulic-Fracture Geometries by the Boundary Element Method
Authors: Zhang Miao , Sun Qian , Ayala Luis F. 
Published: September 2019

Abstract
This work proposes a novel boundary-element based approach to model fluid transport in unconventional shale gas reservoirs with complex hydraulic fracture networks. The fluid flow model employed in this work considers multiple fluid transport mechanisms identified in in gas transporting process in shale nanopores including diffusion, sorption Kinetics, Knudsen diffusion, and sorbed-phase surface diffusion. Accordingly, two governing partial differential equations (PDEs) are written for free and sorbed gases. In the proposed method, boundary integral formulations are analytically derived using the fundamental solution of the Laplace Equation for two governing nonlinear PDEs and Green's second identity. The domain integrals considering the nonlinear terms due to multi-mechanism effects, are transformed into boundary integrals employing the dual reciprocity method (DRM). The resulting boundary integral equations for free and sorbed gas later are solved in terms of a series of discrete nodes after coupling with fracture flow model. The validity of proposed solution is verified using several case studies through comparison with a commercial finite-element numerical simulator COMSOL.
Lessons Learned from Effective Well Integrity Management in Offshore Field
Authors: M. Al-Dhafeeri Abdullah , Fouad Abo Zkery Shebl , Ahmed Al Sdeiri Saad 
Published: September 2019

Abstract
Offshore field started on operation to produce crude oil with 27 API° as sweet crude and sour crude with 32 API° since 1960. Large number of wells in offshore field revealed undesirable phenomena related to well integrity issues as potentially sustained pressure on several casing strings. Well integrity management emphasis on preventing well problems related to well safety and integrity such as casing leak, Sustained Casing Pressure (SCP), downhole safety valve (DHSV) failures. The direct impact from integrity management added great value in terms of decreasing in operating down time, improvement in well control and safety aspects, and reducing unplanned repair intervention. In addition, the loss of well integrity can cause major accidents with a severe risk to the personnel, asset and environment.
The paper aims to illustrate a methodology results on applying effective well integrity monitoring techniques. A focus was made to improve monitoring well integrity through reviewing wellhead surface parameters, annulus sections pressure and downhole condition. In addition, the subject wells should be kept under close monitoring at a safe operable with an integral condition. Non-integral wells are common in aged wells, which are becoming a challenging issue to restore its integrity and operability especially for such aged completion. As a part of well integrity review, the concerns had been identified, investigated, and subsequently mitigations actions are recommended to restore the well integrity. Currently, it is confirmed that 25 oil producers with casing leak problems, which resulted to be converted from conventional completion to a slim hole with limited future accessblity. Based on lab reusltes and logging interpretations, it is indicated that the root cause of casing leaks is due to corrosive water flow from shallow aquifer formation. Therefore, an immediate remedial action is required to improve well construction.
A successful worked over well with integrity issue as a casing leak was repaired by cement squeeze into across the corroded casing interval, which enhanced well integrity and restore well productivity. The resulted showed that tubing leaks encountered with well integrity due to sustained casing pressure. Therefore, the pressure on production casing can cause severe failure with catastrophic damage. The results also illustrated that a water flow through poor cement is a major cause of sustained casing pressure in the outer casing strings. The cause of pressure on production casing is generally easier to diagnose than that pressure on one of the outer casing strings. Challenges, methodology, work schedule, risk assessment, lesson learned and findings are included in this paper. The effective well integrity management resulted on great deal of benefits, which are related to securing wells, well operability, cost saving, and sustained maximum production target.
Low Cost Recovery Optimization of Mature Onshore Sour Gas and Gas Condensate Assets
Authors: Maierhofer Matthias , Pamminger Johannes , Ecklmair Andreas , Schuster Markus , Lamar Justin , Otto Volker , König Joachim 
Published: September 2019

Abstract
Two mature onshore gas condensate fields, treated in one sour gas plant, are investigated with the objective to increase their recovery and to extend their economic field life. The impact of a surface pressure reduction on both reservoir delivery and facility operability is examined.
A predecessor project successfully proved the capability of the sour gas plant to treat declining gas flow rates under a wide pressure range from some 70 bara down to about 14 bara. This paves the way for an integrated method looking at stepwise pressure reduction in the whole system from the wellheads via the compressor stations and down to the sour gas treatment plant. In an iterative approach the outcomes of a subsurface PETEX model, a surface HYSYS model and compressor capacity calculations are matched. Production rate and system pressure are predicted versus time.
It is fundamental that the capacities of the reciprocating machines in the compressor stations can be increased by lowering their discharge pressures. The higher capacity achieved through lower discharge pressure in turn reduces wellhead pressures and, in consequence, enhances recovery. Respective subsurface and surface modeling and engineering studies indicate the feasibility of a system pressure reduction and the positive effects on recovery and process safety.
In particular, full system test runs covering most of the anticipated pressure ranges and specific compressor tests confirm the modeling and engineering results. Compared to other scenarios involving additional compressors a CAPEX reduction of 85% is achieved. Also 40% OPEX per year are saved. Although these latter scenarios with more/bigger compressors allow for a quicker pressure reduction at the wellheads and higher revenue, their high costs more than offset their revenue advantage over the optimized approach.
The low cost scenario increases ultimate gas recovery by 5% compared to the Asset Base. In total, the economic field life is extended by approximately six years. Additionally, the process safety increases due to the lower system pressure.
Low cost and optimized production solutions in mature onshore gas assets can only be developed using a strongly integrated multidisciplinary approach. The entire production system from the reservoir to the sales gas handover point must be considered. Notably, the suggested system pressure reduction in declining fields works with complex sour gas plants and with reciprocating compressors.