bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pressure Measurements Challenges in Low Permeability Reservoirs of Neuquén Basin, Argentina
Authors: Bianchi Federico , Heine Sebastián , Carrizo Páez Nicolás , Bosco Sergio , Bach Roberto 
Published: October 2018

Abstract
This work discusses reservoir pressure gathering relevance in tight gas sands description. Data validation and interpretation procedures are outlined, as well as the impact of using this kind of data in reservoir characterization and optimum completion design.
A workflow to gather reservoir pressure values within an acceptable certainty range for the description of these low permeability reservoirs is presented. The proposed methodology is based on the analysis of historical data obtained according to traditional standards, with the aim of improving the pressure data acquisition efficiency.
The workflow considers the characteristics of most of the commercially available tools (i.e. snorkel geometry and size, flow rate ranges, etc.). Optimum zone selection and tool placement points based in log interpretation is also described.
The proposed workflow proved to be helpful in optimizing pressure data obtained through wireline formation testers. Data are in good agreement with pressures estimated by DFIT. These results encourage the continuous improvement of the technic.
In addition, some conclusions were drawn from the analysis of the DFITs obtained.
From the data analyzed, the tight sands of Cuyo Group can be best described as low porosity – low permeability reservoirs, in the micro Darcy (μD) range. Deeper zones can reach pressures and temperatures of up to 80 MPa (11600 psi) and 165°C (HPHT). Both normally and overpressurized sands can be found.
We propose a workflow to guide pressure acquisition with formation tester, to deal with the challenge of low permeability sands. Even though the results are presented in relatively wide ranges, those are suitable for better reservoir description and well completions.
Unconventional EOR: Field Tests Results in Vaca Muerta Shale Play: A Capillary Based Improved Oil Recovery Case Study for Shale/Tight Oil Scenarios.
Authors: Bodini Santiago Alejandro , Forni Luis Pablo , Tuero Fernando , Crotti Marcelo Alejandro , Labayen Inés Lidia 
Published: October 2018

Abstract
In Shale plays, EURs relay almost exclusively on "primary" production with practically no account for Enhanced Oil Recovery (EOR) practices. However, many recent works show the feasibility of using different techniques to improve the well's EUR by means of some kind of assistance. Lean gas, CO2 and water injection, mostly in a huff-n-puff manner, seem to lead the industry's most accepted EOR methodologies in ultra-tight (shale) formations. Conceptual, theoretical and experimental work has been made in the water huff-n-puff arena including lab and field work and documented in previous work published by the authors. The methodology consists on a novel operative sequence to enhance oil production in multi-stage fractured Tight/Shale Oil scenarios involving countercurrent water imbibition processes and consists of a cyclic scheme of (i) high pressure water injection, (ii) soaking and a (iii) production period. These cycles could be repeated until capillary effects fade out. These phenomena, which should occur in areas where a substantial portion of the shale matrix contains water-wet effective porosity, could explain some anomalous behaviors such as the low water recoveries observed in many cases, rapid salinization of the flow-back water and the rapid appearance of hydrocarbons at early flow-back times, when no substantial % of the injected water is yet recovered.
This work shares the partial results of the second field test performed in the Vaca Muerta resource play, implemented on a vertical, three-stage well in the black oil window, similar to the first field experience from previous work. The test design was modified (i.e. lower water volumes and alternation of injection and shut-in periods) based on the insights gained in previous tests, to minimize the test complexity, costs and to extract additional information from the transients. The results of this new field test showed that it was possible to inject significant water volumes without reaching original fracturing pressure and without damaging the fracture network productivity. Compared to previous tests, the surface and downhole operations were simpler and inexpensive. Partial results were encouraging, as the pre-test oil rates were recovered and even slightly improved with less than 40% of the injected water volumes recovered. Despite this, due to the shut in periods included and operative issues, in this particular trial, oil rates were not as instantaneous and as important yet, as to compensate for the cumulative oil losses during these shut-ins.
Spatial Distribution of Mechanical Properties of the Late Ordovician Glaciogenic Sandstones, SW Saudi Arabia
Authors: Benaafi Mohammed , Al-Shaibani Abdulaziz 
Published: October 2018

Abstract
The Late Ordovician Sanamah Formation of the Wajid Group, exposed in Wadi Al-Dawasir area, southwest Saudi Arabia, is an analogue of the late Ordovician tight gas sandstone reservoirs in Rub’ Al- Khali Basin. Sanamah Formation consists mainly of glacial origin sandstones and conglomerates deposited in Paleo-valleys. The Formation is divided into three lithological units from the bottom up, massive to cross-bedded conglomeratic sandstone and conglomerate (S1), massive to cross-bedded coarse-grained sandstone (S2), and siltstone to medium-grained sandstone (S3). The three units (S1, S2, and S3) are the proximal, medial, and distal outwash facies, respectively. This study aims to investigate the vertical and lateral variations of the mechanical properties (Schmidt hammer rebound (R), unconfined compressive strength (UCS), Young’s modulus (E), and Poisson’s ratio (V)) of the three lithological units of Sanamah Formation, and define their mechanical layers. The strength of the studied sandstone was measured in the field using Schmidt hammer rebound (R), and the sedimentology and stratigraphy were described in detail. Unconfined compressive strength (UCS), Young’ modulus (E), and Poisson’s ratio (v) were measured in the laboratory. Petrography study conducted to delineate the mineral composition and diagenetic features (e.g. type and amount of cement materials) of the studied formation. The entire sequence of Sanamah Formation subdivides vertically into three major mechanical layers (MS1, MS2, and MS3), which correspond to the proximal (S1), medial (S2), and distal (S3) outwash facies units, respectively. The increase in the strength values was found to be associated with a decrease in the grain size and increase in the cementation degree of the studied sandstone. Therefore, the vertical and lateral distribution of the mechanical layers of the studied formation is believed to be controlled by the lithological and diagenetic alterations. In the lateral extent, the mechanical layers are not consistent with lithological boundaries, whereas, the proximal facies (S1) in the southern part of Wadi Al-Dawasir quadrangle can be mechanically correlated with the medial facies (S2) in the northern part. This lateral crossing of the mechanical layer over lithological boundaries is probably related to the lateral change in the sandstone diagenesis. Understanding the vertical and lateral changes of outwash facies of late Ordovician Sanamah Formation along with its diagenetic alterations can help to predict the mechanical behavior of the equivalent sandstone reservoir in Rub’ Al-Khali Basin. Thus, the result of this study will help to enhance hydrocarbon exploration from the tight gas sandstone reservoirs in Rub’ Al-Khali Basin
High Rate of Penetration Correction of LWD Magnetic Resonance Data
Authors: Oifoghe Stanley , Thern Holger , Coman Radu , Okowi Victor 
Published: October 2018

Abstract
One of the major challenges of Logging-While-Drilling (LWD) Magnetic Resonance data acquisition is its limited logging speed. Typically, LWD Magnetic Resonance is logged at speeds of approximately 20m/hr (65ft/hr). Higher logging speeds will substantially reduce the vertical resolution of the data and prevent full polarization of the Hydrogen Protons in the formation, thus, introducing errors in the measurement of total porosity, fluid fractions, and permeability.
The axial motion (rate of penetration) of the magnetic resonance data has multiple effects on the acquired data. The main effects occur to the data during the polarization time, and the amplitude of the echoes during the Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence time. The effects on the amplitude are broadly referred to as the flow effects.
During the drilling of a well in the Niger Delta, an operator needed to save rig cost by increasing the Rate of Penetration (ROP) for LWD Magnetic Resonance from 20m/hr to 40m/hr. This increased ROP caused an overestimation of the total porosity from magnetic resonance.
A newly introduced correction technique enables the compensation of effects due to high ROP on magnetic resonance data. This ROP correction methodology compensates flow and polarization effects. Total porosity and fluid fractions were corrected, resulting also in an updated Magnetic Resonance permeability index. Validation of the technique was accomplished by an accurate match of the corrected total porosity to results from offset wells.
This paper demonstrates the effect of a high rate of penetration on acquired LWD data. Details of flow and polarization effects, and the procedure for correcting these effects, making the data useable and accurate, are also presented.
Date Palm Tree-Based Fibrous LCM ARC Eco-Fiber -A Better Alternative to Equivalent Imported Products
Authors: Amanullah Md. , Arfaj Mohammed K. 
Published: October 2018

Abstract
A novel fibrous LCM coined "ARC Eco-Fiber" has been developed using deceased date tree wastes to use as an alternative to equivalent imported products. Every year about 5 to 10% trees are discarded due to old age, poor food bearing capacity and also due to the damage and degradation of trees by diseases. Currently, there is no industrial use of the discarded and deceased date palm trees available in the Kingdom. Moreover, the disposal of the deceased and old trees is a big headache for the date farming communities due to the economic cost and their negative impact on surrounding environment and the existing date farm plants. As there is a sustainable source of discarded and deceased date trees in the Kingdom, it is a potential source of raw material for localization of fibrous LCM product development to replace the equivalent imported products. The industrial use of deceased and old date trees will also boost the growth of local industries and enterprises along with the creation of new job opportunities for the local communities. It will also help to uplift the social and economic condition of the date farming communities. The date palm trunk-based fibrous LCM described in this paper indicates good ductile and malleable characteristics and thus expected to have good tensile and compressive load bearing capacity to prevent damage and degradation while pumping.
The performance of the newly developed fibrous LCM "ARC Eco-Fiber" was evaluated using a see-through and a Permeability Plugging Test (PPT) Apparatus. The PPT apparatus used 2mm slotted disc, 250 oF temperature and 1000 psi pressure to conduct the tests. A commercial fibrous LCM product widely used by industry has also been tested to compare the performance of the date palm trunk-based fibrous LCM -ARC Eco-Fiber. The results demonstrated superior sealing and plugging efficiency for the ARC Eco-Fiber with little or no loss of whole mud compared to the widely used commercial fibrous LCM product. Both the conventional and see-through test results indicate effective sealing and plugging performance for the date palm waste-based fibrous LCMs and thus demonstrated the reliability of the product as an alternative to equivalent imported LCM products.
Novel Methods and Test Apparatus for Comprehensive Characterization of Oil and Gas Field Fluids and Additives
Authors: Amanullah Md. , Arfaj Mohammed K. 
Published: October 2018

Abstract
Currently available API test apparatus and methods though provide good guidelines in drilling and drill-in fluid design, they often unable to provide comprehensive fluid and additive characteristics for various application scenarios. This is due to the inability of the current API methods and apparatus to provide application specific information for trouble free drilling and production of oil and gas resources. Moreover, no other industry methods and apparatus are suitable for specific characterization of fluids or additives used for oil and gas field applications. Hence, the industry needs novel test apparatus and methods for comprehensive and better characterization of oil and gas field fluids and additives for trouble free drilling and production operation. This paper describes several novel methods and test set up for comprehensive characterization of oil and gas field fluids and additives for various application scenarios.
Experimental results indicate that the newly developed methods and apparatus provide valuable information on mudcake cleaning and cleaning fluid efficiency, spotting fluid performance, quality control and quality assurance of various sized bridging materials for non-damaging drill-in fluid design, inhibition durability of shale inhibitors to prevent time dependent borehole instability and resilient characteristics of LCM products to improve sealing and plugging efficiency of seals and plugs formed by LCM pills or slurries. The methods introduce several application specific index parameters to provide useful technical guidelines for superior fluid design and appropriate additive selection for trouble free and economic drilling and production operation. The methods will play an important role to discourage the use of trial and error methods in some oil and gas field applications and thus expected to improve the success rate significantly.
Characterization of Emulsion Formation with Nanoparticles for Enhanced Oil Recovery
Authors: Arshad Muhammad Waseem , Feilberg Karen Louise , Shapiro Alexander , Thomsen Kaj 
Published: October 2018

Abstract
Characterization of emulsion formation (amount and droplet size) in the brine–oil–nanoparticle systems as a function of varying size of nanoparticles and modified brine salinity is presented. Different brines were used with a range from zero salinity for deionized water (DIW) to synthetic seawater (SSW), mimicking the salinity of North Sea water. Brines (FW1 and FW2) representing the composition of formation water obtained from different production wells (North Sea) were also used. Two model oils (decane (D) and hexane–hexadecane (HH) mixture of 1:1 vol. ratio) and a sample of North Sea crude oil (NSCO) were used. CaCO3 nanoparticles of three different sizes of 15-40, 50, and 90 nm were used. Nanoparticles characterization was performed with Transmission Electron Microscopy (TEM). A commercially available sonication equipment, Branson Sonifier® SFX250, was employed for emulsion formation in brine–oil–nanoparticles systems. All the experiments were performed at room temperature for the same experimental conditions of 5 minutes of ultrasonic processing by using a 6.5 mm tapered microtip (sonication probe) with an output power of 30 W. Emulsion characterization (emulsion droplet size) was performed with an optical microscope (Axio Scope.A1).
The effect of size of CaCO3 nanoparticles and brine salinity on emulsion formation was investigated for different brine–oil systems. The results showed that the emulsion formation in brine–model oil (D and HH) systems was an inverse function of the size of nanoparticles i.e., a large amount of emulsion formation was observed for the smaller sized nanoparticles and vice versa. Emulsion characterization for these systems showed that the emulsion droplet size increased with an increase in size of the nanoparticles. The brine salinity also showed a significant effect on emulsion formation in brine–model oil systems i.e., a decrease in brine salinity showed an increase in emulsion formation and correspondingly smaller emulsion droplet sizes. However, the brine salinity did not affect the emulsion formation and emulsion droplet size for 15-40 nm nanoparticles. Contrary to the brine–model oil results, the results of brine–NSCO systems neither showed any dependence on the size of nanoparticles nor on the brine salinity. This might be due to the presence of polar fractions (polar acids and polar bases) in the crude oil.
The characterization study presented in this paper can provide a foundation for future development of calcite nanoparticle based EOR applications in the carbonate reservoirs.
Chemically Tuned Waterflooding in Carbonate Reservoirs: Experimental and Simulation Investigation
Authors: Alhuraishawy Ali K. , Han Pu , Almohsin Ayman , Bai Baojun , Wei Mingzhen 
Published: October 2018

Abstract
Low salinity waterflooding (LSWF) has been widely investigated to reduce the residual oil saturation in swept areas and thus improve oil recovery. Recently, extensive studies on crude oil, brine, and rock system reported that LSWF and increased sulfate ion concentration in the injected water could change rock wettability during waterflooding. The objective of this paper is to provide a deeper understanding the effect of sulfate ion concentration and low salinity waterflooding on oil recovery improvement due to wettability modification by applying experimental and simulation approaches.
An experimental model with the properties of the same core was designed to understand the effect of LSWF and sulfate ion concentration on improved oil recovery during the waterflooding process. Reactive transport simulator (CrunchFlow 2007) was used to simulate the experimental result. Once the experimental and simulation results were matched, a sensitivity analysis was done by changing sulfate ion concentration and calculate the wettability index based on chromatographic separation of tracer (SCN-) and sulfate ion (SO42-) to investigate how could affect the sulfate ion concentration on modifying rock wettability. So when the area between SCN- and SO42- increased, the wettability modified toward water wet.
The experimental results found that both LSWF and increased sulfate ion concentration three times can improve oil recovery factor by 10% and 19.5%, respectively. The reactive transport simulator results showed that the area between SCN- and SO42- increased as SO42- concentration increased and improved the core wettability toward more water wetness. The temperature has a significant effect on the SO42- adsorption and the high temperature resulted in more SO42- adsorption and the core wettability modified to be more water wetness.
Combined two approaches, experimental and simulation, could be a viable technique to understand LSWF and sulfate ion concentration effect on improved rock wettability toward water-wet.
A General Compositional Rescaled-Exponential Model for Multiphase Boundary-Dominated Performance Analysis
Authors: Will Ryan , Ayala Luis F. 
Published: October 2018

Abstract
Hydrocarbon reservoir performance forecasting is an integral component of the resource development chain and is typically accomplished via reservoir modeling using either numerical or analytical methods. Although complex numerical models provide rigorous means of capturing and predicting reservoir behavior, reservoir engineers also rely on simpler analytical models to analyze well performance and estimate reserves when uncertainties exist. Arps, for example, empirically demonstrated that certain reservoirs may decline according to simple, exponential, hyperbolic, or harmonic relationships; such behavior, however, does not extend to more complex scenarios, such as multi-phase reservoir depletion. Due to this limitation, an important research area for many years has been to transform the equations governing flow through porous media in such a way as to express complex reservoir performance in terms of closed analytical forms. In this work, it is demonstrated that rigorous compositional analysis may be coupled with analytical well performance estimations for reservoirs with complex fluid systems, and that the molar decline of individual hydrocarbon fluid fractions can be expressed in terms of rescaled-exponential equations for well performance analysis. This work demonstrates that, by the introduction of a new partial pseudo-pressure variables, it is possible to predict the decline behavior of individual fluid constituents of a variety of gas condensate reservoir systems characterized by widely varying richness and complex multi-phase flow scenarios. A new four-region flow model is proposed and validated to implement gas-condensate deliverability calculations at late times during variable bottomhole pressure production. Five case studies are presented to support each of the model capabilities stated above and validate the use of liquid-analog rescaled-exponentials for the prediction of production decline behavior for each of the hydrocarbon species.
An Automated Flowing Bottom-Hole Pressure Prediction for a Vertical Well Having Multiphase Flow Using Computational Intelligence Techniques
Authors: Tariq Zeeshan 
Published: October 2018

Abstract
The need for accurate estimation of flowing bottom-hole pressure (FBHP) is owning an immense importance in petroleum engineering applications such as continuous field production optimization, cost per barrel of oil reduction, assess reservoir performance and to quantify workover remedial operations.
Induction of pressure down-hole gauges in oil wells to measure FBHP is a common practice especially in wells artificially lifted with downhole electrical submersible pumps. However, intervening a producing well is a quite exhaustive and expensive task which is involved with production risk, and disruptions. For these reasons, various empirical correlations and mechanistic models were developed to estimate FBHP. Majority of these models were formed under laboratory scale conditions and are, therefore, imprecise when scaled-up to field conditions. Because of the complexity associated with the numerical modeling and physical implementation these models are also computationally very expensive to run.
In this study, an empirical model based on computational intelligence (CI) technique is developed to quantify FBHP in a vertical well with multiphase flow. The proposed model is based on only surface production data which includes; oil flow rate, gas flow rate, water flow rate, oil API gravity, perforation depth, surface temperature, bottom-hole temperature, and tubing diameter. The data used to develop empirical model covered a wide range of values and are collected from published sources and several wells from different locations. The proposed model is then tested against new field data and results were compared statistically with the estimations of some commonly used empirical correlations and mechanistic models in oil industry. The comparison results show that the proposed empirical model significantly outperforms all other existing models and delivers the predictions with high accuracy. A small average absolute percentage error of less than 2% was found with new proposed empirical correlation, while comparing the existing published correlations on the same data gives more than 15% error.
The novelty of proposed empirical model is that it is very simple and only require surface production data while previous models requires exhaustive computationally expensive calculations. The new model is accurate enough and can serve as a handy tool for the production engineers to forecast the FBHP in wells with high level of certainty.