bluuebunny/crossref_metadata_2025_split huggingface dataset:
Automated Mud Logging System as a Cost-Efficient Way of Acquiring Subsurface Data: Results of the Field Trial
Authors: Nikitin Anton , Krugliak Zinovy , Stepanov Vitaly , Dolan Sean 
Published: October 2017

Abstract
In this paper, we present a new surface logging technology, named the Automated Mud Logging System (AMLS), which is a cost-effective alternative to advanced wireline logging required to identify producible oil in tight rocks.
AMLS provides characterization of drill cuttings samples at the well site. Current version of the system (AMLS ver 1.0) includes a Natural Gamma-ray Spectrometer (NGS) and Nuclear Magnetic Resonace (NMR) relaxometer, with an automated sample feeding system which can be installed in a mud logging unit to perform sample analysis while drilling. The sensitivity of NGS and NMR measurements to sample volume avoids time consuming and labor intensive sample preparation required by other geological material characterization methods (e.g. X-ray diffraction, X-ray fluorescence, etc.) which are surface sensitive. The ability of NGS and NMR to characterize "as received" cuttings allows for the automation of data acquisition and minimizes the operational expenses.
Results from a field trial of AMLS on a vertical well, drilled through tight formation at a rate of penetration (ROP) of approx. 120 ft/hour are also presented. The uranium (U) concentration curve from cuttings, acquired by the AMLS ver 1.0, compares favorably with that acquired by a wireline tool. This demonstrates the robustness of the developed system to characterize drill cuttings for formation evaluation. The main challenge in cuttings analysis is ensuring efficient mud logging operations at the well site during fast drilling (e.g. sampling cuttings every 5 ft in depth with a ROP of 100-120 ft/hr)
The presented results demonstrate the feasibility of converting mud logging from a source of qualitative information about the subsurface into a source of quantitative information comparable to the information delivered by wireline or LWD logging but acquired at much lower cost and operational risk. The addition of other components to AMLS such as automated sample catcher and Neutron Induced Gamma-ray Spectroscopy (NIGS) measurement system should make this mud logging system even more valuable source of subsurface information. Another enhancement of the data acquired by AMLS can originate from properly acquired advanced mud gas logs. An example of the application of data acquired by NGS node of AMLS ver 1.0 and mass spectroscopy-based mud gas logging system to identify intervals containing producible oil in a tight rock formation in West Texas, is presented.
Reducing BOP Testing Costs During Wireline Logging Campaigns
Authors: Stroud J. , Basu R. 
Published: October 2017

Abstract
During a wireline logging campaign on exploration wells, function testing a Blow Out Preventer (BOP) happens every 7 days per regulations. This test can take 12 to 24 hours and result in 1 to 1.5 days of rig downtime. The authors have internally developed a method of reducing the time of test to approximately 10 hours or less through novel invention. This paper intends to release the intellectual property of said invention into the public domain.
The current practice of executing BOP Functional Tests involve tripping down standard drill pipe to the BOP. If the operator is in the process of running a log, that means putting the process on hold and running back down with pipe. The BOP Function Test Bar (Bftb) is a tool capable of being attached to wireline which allows the function test of a BOP without tripping pipe. This method is conceived as a cost-saving and safer alternative.
The Bftb is a newly developed and patented wireline conveyed device that can be used to function test the BOP significantly faster and safer than the traditional pipe-in pipe-out method. The Bftb-Gen1 was qualified for sub-sea operations and piloted on Nobel Globetrotter-1 in the GOM after an 8-month development process in 2015. The Bftb –Gen 2 tool with increased utility to allow BOP pressure testing capability was deployed in early 2017. Conveying the Bftb directly on the wireline improves HSSE and reduces the time required to conduct the BOP function test by ~10 hours, resulting in significantly less rig down time. The entire R&D investment was recovered in the initial pilot, and there stands to gain annual OPEX savings in the millions, based on 4-8 deployments a year.
This paper will present both the technical specifications and operational implementation of Bftb for the audience's use. Additionally, the results of both deployments will be available to compare with the forecasted value proposition. There overall desire is to share the lessons learned with industry and allow the market to determine the adoption rate and further development of the Bftb.
Transient Operations and Instabilities in Different Production Scenarios: Modeling and Validation
Authors: Almudairis Fahad , Zhang Hong-Quan 
Published: October 2017

Abstract
This study presents a unified transient model that can be used as a tool to predict different transient multiphase flow phenomena in petroleum production and transportation through wells and pipelines. These transient behaviors such as production rate change, sudden perturbation of steady state flow or cyclic flow behavior are predicted and analyzed. For cyclic flow behaviors, the casing heading instability that occurs in gas-lift operations are investigated. The development of the model is based on mass and momentum conservation equations. A transient heat transfer model is also developed to estimate the temperature profile along the production system. The black oilmodel is added to calculate the fluid properties at each time step.Several methods were developed in the past to predict flow instabilities. However, they are designed for specific transient behavior and they can only predict whether or not the flow is unstable. They cannot quantify how unstable it will be. The present model can predict the detailed multiphase flow hydrodynamic behaviors including pressure, temperature, local flow pattern, liquid holdup, and fluid velocities. The model is validated through comparisons with experimental results and field data.
Relative Permeability and Residual Saturation Estimates for Organic-Rich Shale Samples From Bakken, Wolfcamp, Eagle Ford and Woodford Formations
Authors: Ojha Shiv Prakash , Misra Siddharth , Sinha Ankita , Dang Son , Tinni Ali , Sondergeld Carl , Rai Chandra 
Published: October 2017

Abstract
Relative permeability and residual saturations of organic-rich samples were determined from low-pressure nitrogen adsorption-desorption measurements on the samples. Robustness of this relatively new estimation technique for shale-reservoir samples is evaluated in this study. Petrophysical correlations of relative permeability and residual saturations with kerogen maturity, kerogen content, kerogen removal, and sample cleaning are developed for purposes of improved understanding of the saturation-dependent transport behavior of shale reservoirs. These correlations enable comparative predictions of intra-well and inter-well production performances.
Adsorption-desorption isotherm measurements were performed on 100 organic-rich shale samples from Bakken, Wolfcamp, Eagle Ford and Woodford formations. Total organic content varied in the range of 1 to 9 wt.% and the porosity varied in the range of 1 to 10 %. The adsorption-desorption measurements were interpreted to obtain pore size distribution (PSD) using a modified Barrett-Joyner-Halenda method. Bimodal fractal model was then applied to the PSD estimates to compute certain percolation and fractal parameters, which were implemented into percolation theory, effective medium theory and critical path analysis models to generate the relative permeability curves and residual saturations of the 100 samples.
Kerogen maturity was found to be the dominant factor affecting the relative permeability and residual saturation estimates. Irreducible water saturation and residual hydrocarbon saturation estimates increased from 30% to 60% and 20% to 40%, respectively, with an increase in kerogen maturity from oil window to late-condensate window. This implies a sharper decline in hydrocarbon rates (lower cumulative hydrocarbon production) and a prolonged period with lower water rates (lower cumulative water production) for shale reservoirs with higher kerogen maturity. Estimates of relative permeability of hydrocarbon and aqueous phases at 80% saturation of the corresponding phases increased from 0.7 to 0.75 and 0.05 to 0.2, respectively, with the decrease in kerogen maturity. This can be explained by decrease in relative contribution of micropores to total porosity with decrease in kerogen maturity. Higher mean pore size for samples with lower thermal maturity leads to better saturation-dependent transport properties in these samples. When the samples were cleaned with toluene-methanol mixture to remove soluble, dead hydrocarbons and bitumen from the samples, the hydrocarbon phase residual saturation estimates decreased by 20%, whereas the aqueous phase irreducible saturation estimates increased by 9%. Simultaneously, cleaning resulted in decrease in wetting phase relative permeability with increase in non-wetting phase relative permeability.
Comparison of PR-EOS with Capillary Pressure Model with Engineering Density Functional Theory on Describing the Phase Behavior of Confined Hydrocarbons
Authors: Liu Yueliang , Jin Zhehui , Andy Li Huazhou 
Published: October 2017

Abstract
Peng-Robinson equation of state (PR-EOS) with capillary effect has been extensively used to describe the phase behavior of hydrocarbons under nano-confinement in shale reservoirs. In nanopores, surface adsorption may be significant and molecular distribution is heterogeneous. While PR-EOS cannot take into account these effects, statistical thermodynamic approaches such as density functional theory (DFT) can explicitly consider the intermolecular and fluid-surface interactions. In this work, we compare the phase behavior of pure hydrocarbons and mixtures in nanopores from PR-EOS with capillary effect and engineering DFT. We apply the Young-Laplace (YL) equation assuming zero contact angle to calculate the capillary pressure in PR-EOS with capillary effect. On the other hand, we extend the PR-EOS to inhomogeneous conditions by using weighted density approximation (WDA) in engineering DFT.
For pure components, both approaches predict that the dew-point temperature increases in hydrocarbon-wet nanopores. While engineering DFT predicts that the confined dew-point temperature approaches bulk saturation point when pore size approaches 20 nm, the saturation point obtained from PR-EOS with capillary effect approaches bulk only when the pore size is as large as 1 μm. With engineering DFT, the critical points in nanopores deviate from that in bulk, but no change is observed from PR-EOS with capillary effect model. The difference between PR-EOS with capillary effect and engineering DFT on the dew-point temperature decreases as the system pressure approaches the critical pressure. At low pressure conditions, PR-EOS with capillary effect model becomes unreliable.
For binary mixtures, both approaches predict that the lower dew-point decreases and the upper dew-point increases. More interestingly, phase transition can still occur when the system temperature is higher than the bulk cricondentherm point. Engineering DFT predict that the confined lower dew-point approaches bulk when pore size approaches 20 nm, whereas the dew-point obtained from PR-EOS with capillary effect approaches bulk only when the pore size is as large as 100 nm. This work illustrates that assuming homogeneous distributions in nanopores may not be applicable to predict the phase behavior of hydrocarbons under nano-confinement.
API RP 19B Section 2 Perforation Tests Conducted at Multiple Facilities to Guide the Latest Section 2 Revision
Authors: Ayre David , Atwood David , Geerts Shaun , Grove Brenden , Haggerty Dennis , Hardesty John , Lattanzio Dario , McNelis Liam , Sampson Tim , Sokolove Chris 
Published: October 2017

Abstract
The results of API RP 19B Section 2 tests conducted at eight charge manufacturer's testing facilities were used to determine whether differences in vessel size and configuration resulted in different depth-of-penetration results. Findings from these round-robin tests were also used to help guide changes to the newly revised Section 2 documentrecently voted on, approved, and currently in review by API.
After agreement among the eight companies was reached on the testing specifics, the tests were conducted over a period of time, enabling an independent operator to observe the tests at each facility. A batch of quality, deep-penetrating shaped charge was supplied by a single manufacturer, and the rock targets were sourced from the same block to minimize differences and allow for fair evaluation of the different testing systems. The hardware materials and test configurations used in the tests were specified (scallop plate and casing coupon, wellbore and target pore pressures), and the independent operator verified that each test was conducted accordingly. The independent operator tabulated the penetration-depth and casing-hole-size data from the tests for comparison per Section 2 testing specifications.
At each testing site, a set of successfully performed tests was conducted at confining stresses of 1,500, 3,500, 6,500, and 9,500 psi. The resulting penetration depths were all plotted versus confining stress on the same chart. A statistically significant correlation was found between penetration depth and confining stress (as expected); with a minor correlation with porosity. Most of the scatter in the data was observed at confining stresses of 1,500 and 3,500 psi. A statistical analysis showed that the diameter of the core (4, 5.25, and 7 in.) did not influence the penetration results for this particular deep-penetrating, 21-g explosive shaped charge. This knowledge enables a testing company to conduct Section 2 tests at a lower cost. Additionally, based on statistical analysis, the option of housing the shaped charge within the wellbore chamber versus an open-style configuration is valid because it did not affect the penetration results. The information and results collected from the eight different facilities provide options for vessel type and system configuration and also suggestthe variance to expect in Section 2 tests. Insight into the methods used for conducting these tests and background information on handling the cores are included.
Real Time Cement Displacement Tracking using Distributed Fiber Optic Sensors
Authors: Wu Qian , Dininger Marjorie , Nair Sriramya , van Oort Eric , Guzik Artur , Kishida Kinzo 
Published: October 2017

Abstract
Cement displacement efficiency significantly affects the quality of a well cementing job. Inefficient displacement of drilling fluids by spacers and cement slurry results in poor placement and potential contamination of the cement, which in turn can compromise cement integrity and threaten zonal isolation of oil and gas wells. In this paper, a novel method is introduced to monitor the cement displacement process in real time using fiber optic distributed temperature and strain sensing (DTSS) technologyas drilling fluid, spacer and cement are pumped through the casing annuli.An advanced DTSS system, based on hybrid Brillouin and Rayleigh backscattering, was used in combination with a specially designed fiber optic cable to identify the location of each fluid (i.e. drilling fluid, spacer fluid and cement slurry) during the cement displacement process. The fiber optic cable consists of a single-mode optical fiber packaged with a polymer that has selective sensitivity to various well construction fluids, and thus can be used to detect the presence of each fluid. Both strain and temperature changes were monitored by the DTSS system to track the cement displacement process. When the proposed fiber optic cable was exposed to synthetic-based mud (SBM) and spacer fluid, the strain values recorded by the fiber differed by a few orders of magnitude. When the cable is exposed to cement slurry, the location of cement can be determined from its exothermic heat release signature, which is apparent in both strain and temperature measurements. Contamination of cement slurry with drilling fluid was found to have a significant impact on the strain and temperature profiles. Thus, the DTSS system can provide useful information regarding top of cement (TOC), the wait-on-cement (WOC) time and the displacement efficiency in real time. Cement displacement of drilling fluids and spacer fluids has been modeled in the past; however, to date the displacement process and the locations of these fluids have never been tracked and verified in real time. This paper presents a new way for real-time, in-situ, continuous, and non-disruptive monitoring of the cement displacement process and tracking of the well construction fluids.
Novel Use of Application-Specific Integrated Circuits in Quartz-Based Permanent Downhole Gauges Increases Reliability Estimates in High-Temperature Applications
Authors: Zheng Quanling , Garcia Elias , Balasubramanian Aswin 
Published: October 2017

Abstract
This paper demonstrates the benefits of using application-specific integrated circuits (ASICs) in the design for downhole, quartz-based, pressure and temperature permanent downhole gauges (PDGs).
Historically, downhole electronics have been built with general purpose chipsets, whose functions areadapted to suit design needs. In contrast, through integrating and optimizing the necessary functions into a single integrated circuit (IC), ASIC technology enables a chipset to be customized for a particular use. Compared to the previous generation of PDGs, this approach reduces the overall footprint of the gaugeand improvesthe overall gauge performance,especially for reliability performance. Suchimproved reliability performance is validated through the use of the design for reliability (DFR) process, which consists of define, identify, verify, and validate stages. Thecoreof the validate stage is thereliability demonstration test (RDT).
The detailed advantages of the novel use of ASIC technology in PDGs are discussed in this paper, with comparison to the previous generation of PDGs. The incorporation of ASIC circuitry enables lower current consumption, which in turn enables deployment of an increased quantity of pressure and temperature PDGs without increasing the system's power budget. The implementation of ASIC technology helps reduce the overall size of the PDGs, with a 67% reduction in length and a 44% reduction in outer diameter (OD), which also enables direct integration to tubing encased conductors (TEC) by means of prewelded and prespooled connections.The RDT results demonstrate that the ASIC-based PDGcan at least triple the operationlifetimecompared to the previous generation of PDGsin high-temperature downhole environments.
Overall, the adoption of ASIC technologysignificantly improves the reliability of PDGs, demonstrating a life of 10 years at 175°C with 80% reliability and 60% confidence in accordance with industry recommended practices, andprovides a permanent downhole monitoring system with a deployment of 40 or more gauges for high-pressure/high-temperature (HP/HT) applications.
Multi-Scale Fluid Phase Behavior Simulation in Shale Reservoirs by a Pore-Size-Dependent Equation of State
Authors: Luo Sheng , Lutkenhaus Jodie L. , Nasrabadi Hadi 
Published: October 2017

Abstract
The phase behavior of reservoir fluids plays a fundamental role in predicting well performance and ultimate recovery. Currently, the uncertainty in phase behavior is one of the greatest challenges in developing unconventional shale resources. The complex phase behavior is attributed to the broad range of pore sizes in shale. In macro-scale geometries such as fractures and macropores, the fluid behavior is bulk-like; in nano-scale pores, the fluid behavior is significantly altered by confinement effects. The overall phase behavior of fluids in porous media of mixed pore sizes is yet to be understood.
In this paper, we present a multi-scale fluid phase behavior study. A pore-size-dependent equation of state (EOS) is used to describe the fluid by the confining pore diameter. The EOS confinement parameters for fluid-pore wall surface interaction are determined by experimental results from differential scanning calorimetry and isothermal adsorption of species C1~C14. The multi-scale phase equilibria are simulated by directly minimizing the total Helmholtz free energy. A modified Eagle Ford oil is used for the case study. Constant composition expansions (CCE) of dual-scale (bulk and 15 nm) and triple-scale (bulk, 15 nm, and 5 nm) systems are simulated. The first bubble emerges from the bulk region at a lightly suppressed "apparent" bubble point pressure. Below the bubble point, the liquid saturation in the bulk region drops sharply, but the fluids in the nanopores are undersaturated throughout the multi-stage expansions. In the end, large amounts of intermediate to heavy hydrocarbons are retained in nanopores, implying a significant oil recovery loss in shale. The confinement effect also leads to near-critical phase behavior in small-scalenanopores (&lt;5 nm).