bluuebunny/crossref_metadata_2025_split huggingface dataset:
High-Efficiency, High-Yield Pulsed Neutron Generators for the Well Logging Industry
Authors: Navarro Juan , Guo Weijun 
Published: September 2016

Abstract
This paper introduces new concepts for high-efficiency, high-output neutron generators for the well-logging industry, incorporating planar field ionization (FI) ion sources, which can provide for an order of magnitude higher neutron yield at a fraction of the power of conventional designs. Neutron generators for the well-logging industry primarily use electron-impact ion sources, which have low ionization efficiency and less than 10% monatomic ion production. A magnetic field or higher gas pressure is often required for improving ionization at the expense of lower reliability, average neutron yield, and large Tritium activity. The planar, FI ion source concept was investigated, and studies of a 100-µA ion-beam interaction with a thin Titanium target shows the target’s temperature at maximum operating conditions, never exceeding the Tritium desorption temperature. Particle-in-cell (PIC) simulation software was used for simulating the ion-beam transport from the planar, FI ion source, resulting in a mostly ideal beam transport covering the entire surface of the target, which reduces the target’s operating temperature and, thus, eliminates T desorption, allowing for approximately an order of magnitude higher neutron yield, higher logging speed, and a significant reduction in rig time, as well as substantial cost savings.
To the Barricades! Using a Self-Assembled Wall to Protect Ordinary Portland Cement from Acidic Corrosion
Authors: Vorderbruggen M. A. , Bryant S. , Wilson M. 
Published: September 2016

Abstract
A novel cement additive, capable of creating an insoluble barrier at the first sign of acid attack, is offered. When present in small quantities, it allows ordinary Portland cement (OPC) to protect itself from acid corrosion as shown by laboratory tests. This corrosion resistance is critical especially in regards to attack from carbonic acid produced when CO2 combines with water or from naturally occurring H2S in the well. These acids can turn OPC porous and weak, rendering it incapable of maintaining zonal isolation.
CO2 gas can enter the wellbore as part of either a stimulation technique to energize production or to sequester this green-house underground in hopes of reducing global warming. Cement used in a CO2-sequestering well must maintain its integrity for hundreds if not thousands of years to keep the CO2 trapped; otherwise, the CO2 can reenter the atmosphere. Damage to the cement sheath in the short -term can lead to contaminated aquifers or annular leakage of natural gas, both of which can have devastating results.
Laboratory testing of this commercially-available additive was performed under temperature and pressure in CO2-saturated brines for weeks. Corrosion of the tested cement samples was measured optically and through a variety of chemical analysis procedures. Samples of OPC containing the additive stopped penetration of carbonic acid near the surface whereas sample without suffered deep corrosion penetration.
When it is known in advance that the well will be highly acidic it may be cemented with acidresistant alumina-silicate cement (ASC) rather than OPC. However, this technique requires specially isolated pumping equipment to avoid flash set of the ASC, making the process more expensive and error-prone. Addition of the novel dry-powder, acid-activated, barrier-creating compound is much easier. The additive remains inert in the set OPC until acid corrosion occurs. Release of calcium ions by acid attack triggers the formation of an insoluble barrier which reduces further acid damage.
New Generation of Rotary Steerable System Enables Higher BUR and Performance
Authors: Al Dabyah Ali , Biscaro E. , Mayer Heinrich 
Published: September 2016

Abstract
In many areas around the world, rotary steerable systems (RSS) have replaced steerable motors because of the inherent advantages of RSS technology that include improved directional control, reduced wellbore tortuosity, and comprehensive logging-while-drilling (LWD) measurements.
Since the late 1990s, rotary steerable systems have revolutionized drilling and redefined how far directional drilling can go. Extended-reach drilling, multilaterals, and deepwater drilling have achieved new levels of efficiency. Well placement has also been enhanced, enabling the use of reservoir navigation that yields outstanding net-to-gross results.
Although rotary steerable systems exhibit many advantages, they still face issues of limited buildup rates, weight-on-bit and reliability. Due to the dynamic market, operators are focusing on minimizing cost and saving time by reducing the number of trips, enhancing the rate of penetration (ROP), and reducing drilling footage to avoid directional work in problematic formations that can result in stick/slip and wellbore stability issues.
To address the client needs, a new generation of RSS has been introduced.
In 2014, a 6¾-in. high-build rate RSS was developed primarily for conventional markets, which have a need for high build rates and simultaneous acquisition of LWD data. The use of a high-build rate RSS in conjunction with an optimized bottomhole assembly (BHA) for build-rate capability has enabled operators to achieve buildup rates up to 12°/100 ft.
In 2015, a 4¾-in. high-performance RSS was developed to fill the need of higher weight on bit and to provide a simple, rugged design with enhanced reliability.
In this paper the authors present the new generation of rotatory steerable and its impact on the market.
This paper will be supported by number of case studies from oil and gas.
Architecture Modeling of Stacked Point Bar Reservoir Based on Meander Loop Database and Automatic Pattern Reconstruction Algorithm: A Case Study in the M Oilfield, Bohai Bay Basin, East China
Authors: Shu Xiao , Dong Rencheng , Hu Yong , Jin Baoqiang , Ren Baicong , Shi Hongfu , Wang Jijun 
Published: September 2016

Abstract
The spatial stacking structure and contact relationship between point bars in meandering river reservoir affect the reservoir continuity, interwell injection-production connectivity and distribution of remaining oil. But its characterization and modeling is hard to achieve in traditional modeling algorithm or deterministic microfacies drawing method, especially in offshore oil fields with large well spacing and low resolution seismic data. In order to solve this problem, we developed a new prediction and modeling method based on meander loop database and automatic reconstruction algorithm of sedimentary pattern. This algorithm honors the geometries and interrelationships between point bars while honoring the conditioning data. The general methodology consists of 2 steps. (1) Build a database storing the geometries of meander loops. (2) Select the meander loop from database sequentially and place it in the simulation space constrained by predefined rule and conditioning property.
We applied this method to construct the stacked point bar model of M oilfield. Multiple equal probable architecture models were built and were compared with each other through history matching. The optimal predicted model reaches a history matching coincidence rate of 91.3% and was used to predict the abundance zones of remaining oil. Based on the prediction results, 13 adjustment horizontal wells were drilled in the study area to tap the remaining oil. The accurate predicted result implies that the pattern reproduction based on database are effective for characterizing the spatial structure of stacked point bar reservoir.
Water Salinity Determination Over an Extended Salinity Range Using a Joint Interpretation of Dielectric and Neutron Cross-Section Measurements
Authors: Donadille J. M. , Leech R. , Pirie I. 
Published: September 2016

Abstract
High-frequency dielectric dispersion has been shown to be sensitive to the water volume, the water salinity, and the water tortuosity within the pore space. Dielectric dispersion data can be inverted to estimate water saturation in conditions where the interpretation of resistivity with traditional saturation equations is problematic, such as low and variable water salinities, complex texture, and unknown wettability. There is, however, a recognized limitation: salinity can be estimated only in the low to medium range. Above about 60 ppk, water salinity, which influences the estimated water volume, must be fixed in the dielectric interpretation.
The thermal neutron capture cross-section (sigma) measurement primarily responds to the volume and salinity of the water that is present in the region of the formation seen by the tool. It provides an excellent complement to dielectric measurements for several reasons. Sigma is highly sensitive to the salinity of the water phase, particularly at high salinities. Both sigma and dielectric measurements have a similar volume of investigation and so can be interpreted in a joint inversion.
We developed a joint inversion of dielectric dispersion and neutron sigma measurements that solves for the water volume, water salinity, and tortuosity of the water phase. The addition of neutron sigma to the dielectric dispersion measurements extends the interpretation to high-salinity conditions, and enables the capability of quantifying water salinity in conditions where this was previously not possible.
We illustrate the benefits of this joint inversion on some log examples. In a well drilled with water-based mud and fully invaded, the inversion provides a robust estimate of filtrate salinity even for highly saline filtrate and reduces the uncertainty on the estimated residual hydrocarbon. In the case of oil-based mud invasion, the method quantifies the salinity of the formation water even for moderately to highly saline water.
Bottomhole Pressure Prediction Using Multiphase Hydraulics in Underbalanced and Managed Pressure Drilling Operations
Authors: Morales Gabriela , Urdaneta Gustavo , Poletzky Isabel C. 
Published: September 2016

Abstract
Underbalanced drilling (UBD) and managed pressure drilling (MPD) techniques provide the capability to precisely control bottomhole pressure (BHP). During upfront planning and engineering, as well as during the actual operation, the calculation of the BHP using a wellbore hydraulics simulator is crucial because it helps to determine the operational drilling parameters necessary to achieve the desired objectives, equipment requirements, and operational limits.
Several wellbore hydraulics simulators and multiphase flow pressure gradient methods are available in the industry to facilitate the calculation of the BHP, especially when using gasified fluids in both MPD and UBD, and when accounting for formation influx when drilling underbalanced. Furthermore, before beginning operations, the wellbore hydraulics model is calibrated using the actual readings from the pressure while drilling (PWD) sensor. Simulations were performed for several well designs to compare results and to evaluate the possible underlying causes of the differences among simulators and correlations.
Although the primary components in the BHP calculation include density, frictional pressure losses, and applied surface back pressure (SBP), another component that is usually overlooked during planning and engineering is the surface pressure losses because a considerably larger surface pipe line diameter is typically used for UBD. A case study illustrates the effect on the target BHP for an underbalanced operation when using a smaller pipe diameter. Field data are also used to illustrate the calculation of surface pressure losses; a comparison of the calculated and measured values is also evaluated for different scenarios.
This paper focuses on a comparative study of the various methods and correlations available in some wellbore hydraulics simulators and evaluates the results for different wellbore scenarios using MPD and UBD. The study evaluates actual field measurements, including PWD, surface pressures, flow rates, and standpipe, for some of the scenarios. Conclusions and recommendations address the gaps and areas of improvement that should be considered for future developments.
Evolve: A Linear Workflow for Quantifying Reservoir Uncertainty
Authors: Thiele Marco R. , Batycky Rod P. 
Published: September 2016

Abstract
The EVOLVE workflow addresses a longstanding and difficult problem in reservoir modeling: quantifying the uncertainty in NPV forecasts ensuing from uncertainties related to geological and simulation parameters, forecast scenarios, and economic variables.
The EVOLVE workflow is linear in nature composed of four key stages: (1) screening and selection of geological models; (2) calibration to field-scale measured data; (3) local calibration using well-level measured data; and (4) applying differing forecast scenarios on the resulting ensemble of models. NPV calculations are an extension of stage (4) as forecast responses are translated into NPV numbers using economic parameters such oil price, operating expenses (OPEX), and capital expenses (CAPEX).
The novelty of the EVOLVE workflow is the repeated evolution and reduction of model ensembles in a cascading fashion as new parameter distributions are injected in the various stages (1) through (4) and existing parameter distributions modified, frozen, or removed. A particular characteristic of the EVOLVE workflow lies in its judicious use of geomodeling and flow simulation, the use of distances, distance-based generalized sensitivity analysis (dGSA), efficient calibration to measured field and well responses, and multidimensional scaling (MDS). These are powerful concepts and are united to form a unique workflow.
The separation into four linear stages is deliberate and takes its cue from the favored approach geoscientists and engineers have used to address the uncertainty-problem in the past.
Price Scenario Analysis - Best Practices in a Volatile Price World
Authors: Allan Paul D. 
Published: September 2016

Abstract
E&P capital investment programs and allocation decisions can vary dramatically depending on the underlying price premise used in forecasting future cash flows. The price ‘plateau’ that developed up until the summer of 2014 reduced the criticality of robust pricing assessments in investment decisions as many projects easily met economic thresholds in that environment. Price sensitivity analysis, if conducted at all, was often based on forecast ranges intrinsically linked to the environment of the day. The significant drop in prices during the latter part of 2014 caught many investors and operators off guard, despite a history of cycles and industry memory of past price challenges. Given today's low price reality, many operators find it necessary to closely (and frequently) review their price forecasts and adjust their capital allocation programs to maintain sustainable levels of cash flow. Unfortunately, this is often a reaction to the existing price environment rather than a proactive and strategic positioning for alternative price ‘potential’. Price analysis based on revised economics and ranking, although common in the industry, often fails to yield the insights made possible through more robust portfolio-based price ‘scenario’ analysis methods. Leveraging the interaction of investment options and balancing the unique performance characteristics and timing of assets across various price assumptions can add significant value to a company's portfolio while mitigating downside exposure. This paper provides an overview of best practices in applied price scenario analysis, including methods for integrating this analysis into the ongoing business planning process, specific considerations for tools and processes required, and a case study demonstrating the application of these techniques.
The Advantages of Longitudinally Fracturing the Barmer Hill Porcellinite - A Case Study of Successfully Fractured Horizontal Wells in Barmer Basin, Rajasthan, India
Authors: Nagar Ankesh , Tibbles Raymond , Guha Rupdip , Chidambaram Prasanna , Sinha Ankaj , Pathak Shashank , Agarwal Prashant , Misra Anurag , Ranjan Amit , Ranjan Vishal , Tiwari Shobhit , Dwivedi Nikhilesh 
Published: September 2016

Abstract
Cairn India Ltd & ONGC completed a joint venture appraisal of the Barmer Hill (BH) field in the Rajasthan block of India in 2015. The objective was to evaluate the effectiveness of horizontal multi-frac completions. The Barmer hill field is a moderate permeability (0.5 - 4 mD) oil bearing porcellanite with alternating sequences of tight shale. To produce this reservoir economically, hydraulic fracturing was the obvious choice of stimulation and was performed on a number of vertical wells (see Shaoul et al).
To better evaluate the development strategy, completions using either transverse or longitudinal fracture treatments were successfully designed, executed, and evaluated. In the appraisal phase, four vertical and four horizontal wells were drilled to appraise the Barmer Hill reservoir in the Mangala field. Two of the horizontal wells were drilled along the maximum horizontal stress direction and completed with multiple hydraulic fracturing stages, which generated longitudinal fractures along the lateral wellbore. The fracture orientation with respect to the wellbore was confirmed with micro-seismic monitoring. This fracture treatment strategy provided the opportunity to decrease the number of frac stages and exhibited lower treating pressures as predicted by standard elastic rock mechanics theory.
While the initial productivity of the transverse fractured wells was expected to be almost 2.5 times more than the longitudinally fractured well, it only produced about 40% more. In addition, the EUR of the longitudinally fractured well is almost the same as the transversely fractured well. Based on the generated fracture geometry, theoretically these longitudinally fractured horizontal wells may also provide better effective sweep efficiency when converted to a water injector from a field development concept.
Multifunctional Fracturing Additives as Flowback Aids
Authors: Yue Zhiwei , Peng Yang , He Kai , Xu Liang 
Published: September 2016

Abstract
Flowback aids are usually surfactants or cosolvents added to stimulation treatments—particularly, hydraulic fracturing—to enhance cleanup of the spent fluids and ultimately improve gas or oil recovery when production begins. A range of different flowback additive chemistries have been reported in the literature containing water-wetting nonionic to amphoteric, micro-emulsion, and oil-wet components. Current unconventional reservoir surfactant technology can encounter several major challenges for use in well stimulation processes, including requirements to use nontoxic, environmentally acceptable surfactants; long-term stability at high temperature, pressure, and salinity during the hydraulic fracturing process; and minimum concentration requirements to achieve acceptable performance.
The present work focuses on the development of a new class of flowback aids package that can address these challenges. With a low treatment dosage at 1 gal/1,000 gal, they can effectively reduce surface tension and interfacial tension (with synthetic oil or crude oil). They are all "green" products, composed of 100% environmentally acceptable components and have confirmed numeric ranking using the chemistry scoring index (CSI) tool. They also demonstrated superior thermal and chemical stability to formation conditions. Column flow tests confirmed these new packages helped field oil and broken gel flow smoothly through packed formation cuttings obtained from the Permian Basin, indicating they are effective aids for fracturing fluid recovery. With careful investigation of the laboratory performance data, the final product candidate was identified. It was successfully deployed for a field trial in the Permian Basin during a harsh winter season, with positive feedback received at the early stages of production. In addition, this multifunctional additive provided the extra benefit of corrosion inhibition, which can help protect asset integrity for long-term production.
An Innovative Management Approach for Fast Track Field Development
Authors: Mata T. J. 
Published: September 2016

Abstract
During the last decades, upstream oil and gas industry have faced tremendous improvement due to the availability of continuous technology advances. However, there are still challenges to implement effective technology and talent management programs to tap into growth opportunities from subsurface resources in an effective manner. A successfully deployed game-changing innovation methodology embraces three main areas: discovering major key business opportunities, empowering a leader and a high-performance team focused on innovative solutions, and reengineering the business units to catalyze an agile innovation process.
Case studies from two fields located in Llanos Basin, Colombia, are presented to illustrate the power of these processes in boosting value creation with innovation. Experimentation, prototyping, and deployment of innovative technology, as well as processes and organizational initiatives, led to significant increases in production, reduction of capital and lifting costs, and reserves addition by increased recovery efficiency in a relative shorter cycle time. Furthermore, the excellent results gave way to business culture transformation in terms of new ways of collaborative work in E&P, effective knowledge sharing practices, and focused, high-return, R&D programs.
This systemic and agile approach is continuously expanding with the access to a network of extended workforces beyond the typical asset organizations, such in-company Technical Centers, specialized consultancy firms and Universities, as well as focused alliances with integrated service companies. In addition, it is essential to select and develop innovation leaders with the capabilities to mobilize the network of domain experts focused on solving complex problems, to coordinate provision of resources, to liaise with executive champions, and to communicate relentless about the business value of the early wins, and draft a strategic roadmap for full field deployment.
It is considered that the innovation management approach presented in this paper can be adapted to fulfill needs of assets worldwide.
Managed Pressure Drilling Operations in Deepwater and Total Circulation Losses Environments
Authors: Kuehn Andrej 
Published: September 2016

Abstract
Managed Pressure Drilling (MPD) has been widely considered as the best alternative for many drilling-related problems such as stuck pipe, lost circulation, excessive mud cost and narrow operating windows in deepwater environments. Looking for these benefits, many oil rigs has been rigged up with the MPD system, mainly because drilling engineering is emerging to even more challenging environments with the depletion of the current oil reserves. An example of that is the recent exploration of the Brazilian pre-salt fields in Santos Basin located 200km away from coast, in over 2100m water depth and up to 7000m below sea level.
Composed by huge carbonate reservoirs, the challenge to drill this porous formation has overcame the challenge to drill the two thousands meters of salt. Due to the heterogeneity of this type of formation, vugs and natural fractures are often encountered, resulting in severe or total losses experiences. Pressurized Mud Cap Drilling (PMCD) is one of MPD variations applied in situations when high rate of lost circulation occurs and can also been described as the non-return drilling method. This paper addresses a discussion regarding well control issues, application, fluid selection and safety considerations using PMCD and also the difference on the equipment alignment among this technique and others MPD methods.