bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effects of Initial Roughness and Mechanical Property of Fracture Surface on Acid Fracture Conductivity in Tight Dolomite Reservoir
Authors: Lai Jie , Guo Jianchun , Chen Chi , Wu Kaidi , Ma Huiyun , Zhou Changlin , Wang Shibin , Ren Jichuan , Wang Zhi 
Published: March 2019

Abstract
As the most commonly used technology to exploit tight dolomite reservoirs, acid fracturing usually begins with injecting pad fluid to create rough-surface fractures, followed by pumping acid to form non-uniform etching on fracture surfaces. Thus, the etching pattern and acid fracture conductivity depend largely on initial character of rough-surface fractures. In this work, experiments were conducted to examine the effects of initial roughness and mechanical property of fracture surface on acid fracture conductivity.
Eight artificially split core samples were collected from tight dolomite outcrops and classified into three categories based on the surface topography and splitting force curve. Rough fracture surfaces were scanned utilizing the 3D laser scanner. Then, dynamic acid etching tests were conducted, varying the acid flow rate and acid-rock contact time. Besides, the roughness of fracture surfaces were measured utilizing the 3D laser scanner again. After that, acid fracture conductivity was determined. The effects of acid flow rate, acid-rock contact time, fracture surface topography and mechanical property on acid etching and acid fracture conductivity were discussed.
The experimental results demonstrated that the initial fracture surface topography and acid flow rate jointly controlled the acid etching pattern and the resulting acid fracture surface topography. The orientation of the fractures distributed on the fracture surface had significant effects on the acid fracture conductivity. Dissolved mass increased with longer acid-rock contact time. Longer acid-rock contact time brought higher acid fracture conductivity under low closure stress, while shorter contact time sustained higher acid fracture conductivity under high closure stress. Higher maximum splitting force referred to higher mechanical property, and more breaking stages referred to more microfractures developed. Rock samples with higher maximum splitting force and only one breaking stage exhibited higher acid fracture conductivity.
This paper provides a systematic method to study the effects of initial roughness and mechanical property of fracture surfaces on acid fracture conductivity. Compared with the results based on smooth-surface fracture, the experimental results based on rough-surface fracture can guide acid fracturing design and optimization in a more accurate way. Accordingly, a cost-effective stimulation outcome can be expected.
Review of the Applications of Decision Tree Analysis in Petroleum Engineering with a Rigorous Analysis
Authors: Alkinani Husam H. , Al-Hameedi Abo Taleb , Dunn-Norman Shari , Alsaba Mortadha T. , Amer Ahmed S. 
Published: March 2019

Abstract
As oil prices are fluctuating, decision makers are challenged to make the "best" decisions for field's developments. Decision Tree Analysis (DTA) can help decision makers to make the "best" decisions. DTA focuses on managerial decisions, such as whether to do workover or not, whether the additional information will be valuable or not. The aim of this work is to review the applications of DTA in petroleum engineering and provide a clear methodology on how to apply DTA for any petroleum engineering application.
The combination of Expected Monetary Value (EMV) and DTA is one of the most common methods used in the decision-making process. If EMV is positive, the decision is considered to be feasible. However, that doesn't mean the decision will be successful at all times. It simply means that if a similar decision is made for a larger number of cases, the decision will be successful. DTA will account for the uncertainty in the probability. A good number of papers about the applications of DTA in petroleum engineering were read and summarized into three categories. Also, a clear methodology on how to apply the DTA for any petroleum engineering application was established.
After reading and summarizing a good number of papers and case histories about the applications of DTA in petroleum engineering, it was concluded that the applications can be classified into three main categories; applications of DTA and EMV for the whole oil and gas prospect projects, applications of DTA and EMV for a specific operation or development, applications of DTA, EMV, Monte Carlo simulations, and other methods to assess the value of information. These applications were summarized into tables.
In addition, a clear methodology accomplished by a flowchart that explains how to successfully apply the EMV and DTA for any petroleum engineering application was provided. The method consists of three main steps: 1) how many scenarios need to be considered and what are they 2) collection of the required data 3) use the visual tool (DTA) or programming to find EMV. Each of the previous steps has its own challenges, thus these challenges were addressed and the solutions to overcome the challenges were provided. Finally, practical guidelines have were developed that when used with the accompanying flow chart will serve as a quick reference to apply the DTA for any petroleum engineering application.
As the petroleum engineering applications becoming more complicated nowadays, accomplished by the oil prices fluctuations, the decision-making processes becoming more difficult. The DTA is a very important tool for the decision makers to make the "best" decision. This paper provides a clear methodology on how to successfully apply the DTA which can serve as a reference for any future DTA applications in petroleum engineering.
Bringing Back the Damaged Wells into Production Using Microemulsion Technology
Authors: Abahussain Abdullah , Pino Rafael , Addagalla Ajay , Qadi Anas 
Published: March 2019

Abstract
Investing in new wells during a period of volatile oil prices is not the best option for E&P companies. During hard economic environments such companies make plans to produce or enhance hydrocarbon recovery from existing wells for continuous cash flow and to maximize rate of return on investors’ expectations. In several regions, it may take years to produce the hydrocarbons from the drilled well. These wells were drilled and completed successfully, but they were idle, waiting for the production commencement date. This delay depends on various factors including reservoir conditions, market conditions and geopolitical situations. Due to these delays, wells undergo severe formation damage that either minimizes hydrocarbon production or halts hydrocarbon flow completely.
A solution was identified to increase production from a damaged well or bring a non-producing well back into production. This solution is based on microemulsion chemistry. Microemulsions consist of mixtures of oil and water, along with surfactants and other components. These fluids are optically transparent, thermodynamically stable, possess extremely low interfacial tension, and require minimum or zero energy to form. Microemulsions are transparent because of an extremely small droplet size. These are naturally occurring and have less risk involved in deploying and executing the job when compared to conventional solvent treatments. Cleaning efficiency and reaction time of microemulsions depend on many parameters including reservoir conditions, salinity, temperature and type of hydrocarbon used during the drilling or completion phase. These microemulsion fluids were pumped using an inflatable straddle packer (ISP) designed to isolate and divert into the required small area of exposure. The system consists of two inflatable packers with variable spaceout possibilities, enabling adequate positioning over the selective formation area. This tool was deployed using coiled tubing and real-time depth correlation to estimate the correct treatment zones.
A customized fluid was designed using specialized surfactants, brine and an acid. These individual components were mixed on the surface and pumped down hole. This blend works by solubilizing oil and emulsifiers from the oil-based filter cake and forming a microemulsion.
This paper discusses an openhole completion well that was drilled and then completed with ICD screens. Oil-based mud was left in the hole, causing severe damage that prevented bringing the well back to production. The designed surfactant package was pumped through an ISP tool that was suitable for the reservoir conditions. The ISP tool elastomers were designed after performing detailed lab tests that included the filter-cake destruction test, a wettability test and elastomer compatibility tests. Surfactant was pumped into the reservoir with an engineering approach, and successful results were achieved with good production results.
Reservoir Fluid Geodynamics in Brazilian Presalt Carbonate Field
Authors: Bertolini Andre Carlos , Monteiro Jacyra , Canas Jesus A. , Betancourt Soraya S. , Mullins Oliver C. , Colacelli Santiago , Polinski Ralf K. 
Published: March 2019

Abstract
The objective of this study is to characterize fluid distributions in a presalt field by using well data including downhole fluid analysis (DFA) from wireline formation testers (WFT), openhole logs, and a simplified structural/geological model of the field. From an understanding of the petroleum system context of the field, reservoir fluid geodynamics (RFG) scenarios are developed to link the observations in the existing datasets and suggest opportunities to optimize the field development plan (FDP).
DFA measurements of optical density (OD), fluorescence, inferred quantities of CO2 content, hydrocarbon composition, and gas/oil ratio of fluids sampled at discrete depth in six presalt wells are the basis of this study. DFA data at various depths captures fluid gradients for thermodynamic analysis of the reservoir fluids. OD linearly correlates with reservoir fluid asphaltene content. Gas-liquid equilibria are modeled with the Peng-Robinson equation of state (EOS) and solution-asphaltene equilibria with the Flory-Huggins-Zuo EOS based on the Yen-Mullins asphaltenes model. OD and other DFA measurements link the distribution of the gas, liquid, and solid fractions of hydrocarbon in the reservoir with reservoir architecture, hydrocarbon charging history, and postcharge RFG processes.
Asphaltene gradient modeling with DFA reduces uncertainty in reservoir connectivity. The CO2 content in some sections of the field fluids limits the solubility of asphaltene in the oil, and the small asphaltene fraction exists in a molecular dispersion state according to the Yen-Mullins model. Low values of OD and small asphaltene gradients seen in most of the upper zones reflect the small asphaltenes concentration in the crude oil. The CO2 concentration was modeled with the modified Peng-Robinson EOS in good agreement with measurements in upper reservoir zones. Matching pressure regimes and asphaltene gradients in Wells B and C indicate lateral connectivity. The hydrocarbon column in this part of the reservoir is in thermodynamic equilibrium. In Wells A, C, D, E, and F the OD of the oil indicates an asphaltene content increase by a factor of four at the base of the reservoir as compared with the crest of the reservoir. This tripled the viscosity in Wells C and D, as indicated by in-situ viscosity measurements. The accumulation of asphaltenes at the bottom of the reservoir is most likely driven by a change in solubility resulting from thermogenic CO2 diffusion into the oil column from the top down.
The challenge of the limited number of wells in the development phase of a presalt field for obtaining data to evaluate reservoir connectivity before the FDP is ably addressed by deploying the latest WFT technologies, including probes for efficient filtrate cleanup and fluid properties measurement. These measurements and methodology using a dissolved-asphaltene EOS enabled developing insightful RFG scenarios.
Tracing Production with Analytical Chemistry: Can Oil Finger Printing Provide New Answers
Authors: Nielsen Julie , Poulsen Kristoffer G. , Christensen Jan H. , Solling Theis I. 
Published: March 2019

Abstract
Mature fields often times surprise with respect to the production from the various wells across reservoir sections. This is for example the case in a tight chalk field that we have used as a case study for newly developed technique that employs oil finger printing in the analysis of production data. A small subset of wells has been found to produce significantly better than the remainder and we set out to explore whether the root cause is that there is a connection to higher lying reservoir sections through natural or artificial fractures. This was done with advanced analytical chemistry (GC-MS) and a principal component analysis to map differences between key constituents of the oil from wells across the reservoir section. The comparative parameters are mainly derived from biomarker properties but we also developed a way to directly include production numbers. The approach provides means to correlate the molecular properties of the oil with the production and the general composition that determines density and adhesive (to the rock) properties. Thus, the results provide a new angle on the flow properties of the oil and on the charging history of the reservoir. It is clear from the analysis that the subset of wells does not produce better because of a connection to an upper reservoir section that contributes to the production with oil of a different composition because the molecular mix is indeed quite similar in each of the investigated wells. It is not possible to rule out that there is a connection to an upper-lying section with oil from the same source. One aspect that does differs across the field is the ratio of heavy versus light molecules within each group of molecules and the results show that the region that produce better has the lighter components. We take that to indicate that the lighter components come from oil that flows better and thus is produced more easily. The reservoir section with the lighter oil also lies higher on the structure and is therefore must likely to have been charged first so part of the favorable production seems to be a matter of "first in" "first out". A GC-MS approach such as the one proposed here is cost-effective, fast and highly promising for future predictions on where to perform infill campaigns because the results are indicative of charging history and flow properties of the oil.
Production Forecast and Optimization Utilizing In-Situ Determined Relative Permeability in a Highly Unconsolidated Sour Heavy Oil Clastic Reservoir
Authors: Ayyad Hazim , Dashti Bashaiyer , AL-Nabhan Abdulrazzaq , Al-Ajmi Afrah , Khan Badruzaman , Sassi Khaled , Liang Lin , Nagaraj Guru 
Published: March 2019

Abstract
In Umm Niqa field, Lower Fars (LF) is a shallow, unconsolidated, sour heavy oil and low-pressure sand reservoir. During the current appraisal and exploratory phases, oil production forecasts based on reservoir simulation models were observed to be significantly higher than actual production. Furthermore, unexpected early water breakthrough and the rapid increase in the water cut added more complexity to the reservoir production. This paper will focus on how these challenges were addressed with a unique workflow.
If the reservoir is producing more than one phase, then relative permeability determination becomes essential for the production forecast as well as production optimization to delay the water breakthrough. Due to the unconsolidated nature of LF reservoir, it was challenging to perform coring operation in this environment. In the few cases where cores were obtained, it was almost impossible to perform the relative permeability analysis on the core plugs. Therefore, there was a need to obtain this information by exploring other technique or methodology. Hence in-situ relative permeability technique was implemented in three different wells.
To address the relative permeability determination challenge, an innovative approach was implemented in three different wells. This approach determines the relative permeability at downhole conditions by utilizing the fluids clean-up and sampling data during the wireline downhole formation testing as well as some advanced petrophysical measurements such as the array resistivity, the nuclear magnetic resonance (NMR), and the dielectric dispersion. The data obtained were used as inputs for a multi-physics integrated workflow, which inverts for the relative permeability curves based on the modified Brooks-Corey model.
In this paper, it will be demonstrated how the relative permeability results obtained from this technique in these three wells were applied to update the reservoir simulation models. The production forecasts were found to be significantly improved and close to the actual production figures. The early water breakthrough is better anticipated; therefore, the production rate can be adjusted to delay it and maximize the oil recovery. This method provides an alternative and efficient way to derive the relative permeability curves when it is challenging to obtain from the conventional core analysis techniques. This helped to better understand the number of wells required to be drilled to achieve the planned production target.
This paper adds to the literature unique case studies where relative permeability determination is required, however, not possible to be obtained through conventional industry techniques such as core analysis due to a highly unconsolidated formation. Hence, an innovative workflow was adopted to measure the relative permeability at downhole conditions.
NMR Wettability of Carbonate Reservoir Cores: Best Practices
Authors: Sauerer Bastian , Valori Andrea , Krinis Dimitrios , Abdallah Wael 
Published: March 2019

Abstract
Water flooding has been practiced for many decades as a method to recover a significant part of the post-depletion drive residual oil. Wettability has a dominant effect on reservoir fluid distribution and transport properties such as capillary pressure and relative permeabilities. Unfortunately, capturing reservoir wettability remains a challenge, leaving current input to reservoir simulation models suboptimal. The focus of this study is providing practical and experimental guidance on performing wettability inversion of heterogeneous carbonate reservoir core plugs under complex oil-water interaction using NMR-T2 distributions.
United States Bureau of Mines (USBM) and nuclear magnetic resonance (NMR) wettability measurements on three restored limestone reservoir cores are reported, together with petrophysical properties and dielectric permittivity of the cores.
This paper describes the experimental challenges and the optimization achieved toward obtaining satisfying NMR wettability results under adverse conditions. The NMR measurements were first conducted using dead crude oil. However, the results of the inversion were unreliable owing to the presence of strong oil-water emulsion within the core plugs. To overcome this challenge, while maintaining the prevailing wettability, the plugs were flushed with synthetic oil, Soltrol, which helped the NMR inversion to derive the in-situ wettability. The results were quite consistent with the USBM data, indicating mixed to moderately oil-wet plugs.
The described NMR inversion method, combined with the fluids substitution by synthetic oil, if required, due to oil-brine emulsion formation, can be utilized to complement wettability characterization by conventional SCAL measurements such as USBM and Amott-Harvey. The NMR method is considerably faster than the conventional methods.
The Brain on Fire: A Case Study on Anti-NMDA Receptor Encephalitis
Authors: Crasto Grissel B 
Published: March 2019

Abstract
Anti-NMDA receptor encephalitis is a rare disease that occurs when antibodies produced by the body’s own immune system attack the N-methyl-d-aspartate (NMDA) receptors in the brain (Dalmau, 2016). For a relatively rare condition, one academic hospital in an urban centre noted four cases of anti-NMDA receptor encephalitis in one single year. Patients develop a multistage condition that progresses from psychosis, memory deficits, seizures, respiratory difficulties, abnormal catatonic movements and language disintegration into a state of unresponsiveness (Dalmau, Lancaster, Hernandez, Rosenfeld and Gordon, 2011).
This case study will focus on the pathologies and medical journeys of three female patients diagnosed with anti-N-NMDA receptor encephalitis at this hospital. This paper will discuss the presentations of each of the cases and the individualized nursing care plans developed to address the needs of this patient population. More specifically, it will highlight the importance of ensuring patient and staff safety in the development of these care plans. The need for implementing ongoing evaluations of these nursing care plans to address the developing needs of patients as they proceed through the diverse and complex phases of the condition will also be discussed.
Bioactive Compounds of Pseudoalteromonas sp. IBRL PD4.8 Inhibit Growth of Fouling Bacteria and Attenuate Biofilms of Vibrio alginolyticus FB3
Authors: SUPARDY NOR AFIFAH , IBRAHIM DARAH , MAT NOR SHARIFAH RADZIAH , NOORDIN WAN NORHANA MD 
Published: March 2019

Abstract
Biofouling is a phenomenon that describes the fouling organisms attached to man-made surfaces immersed in water over a period of time. It has emerged as a chronic problem to the oceanic industries, especially the shipping and aquaculture fields. The metal-containing coatings that have been used for many years to prevent and destroy biofouling are damaging to the ocean and many organisms. Therefore, this calls for the critical need of natural product-based antifoulants as a substitute for its toxic counterparts. In this study, the antibacterial and antibiofilm activities of the bioactive compounds of Pseudoalteromonas sp. IBRL PD4.8 have been investigated against selected fouling bacteria. The crude extract has shown strong antibacterial activity against five fouling bacteria, with inhibition zones ranging from 9.8 to 13.7 mm and minimal inhibitory concentrations of 0.13 to 8.0 mg/ml. Meanwhile, the antibiofilm study has indicated that the extract has attenuated the initial and pre-formed biofilms of Vibrio alginolyticus FB3 by 45.37 ± 4.88% and 29.85 ± 2.56%, respectively. Moreover, micrographs from light and scanning electron microscope have revealed extensive structural damages on the treated biofilms. The active fraction was fractionated with chromatographic methods and liquid chromatography-mass spectroscopy analyses has further disclosed the presence of a polyunsaturated fatty acid 4,7,10,13-hexadecatetraenoic acid (C16H24O2). Therefore, this compound was suggested as a potential bioactive compound contributing to the antibacterial property. In conclusion, Pseudoalteromonas sp. IBRL PD4.8 is a promising source as a natural antifouling agent that can suppress the growth of five fouling bacteria and biofilms of V. alginolyticus FB3.