bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Acid Spending on Etching and Acid Fracture Conductivity
Authors: Pournik M. , Li L. , Smith B. , Nasr-El-Din H. A. 
Published: February 2011

Abstract
In acid fracturing, while the near wellbore area of the fracture receives fresh, unspent acid, sections of the fracture further down the length receive partially spent acid due to reaction of acid. As a result, there is a distribution of acid concentration along the fracture length. However, almost all experimental studies on acid fracture conductivity have been conducted with fresh acid, which is representative of what occurs near the wellbore.
An experimental study was conducted to investigate the effect of spent acid on the resulting fracture conductivity in a laboratory facility designed to perform acid fracture conductivity characterization. Gelled HCl acid systems with different degrees of acid spending were used to etch fractured cores under identical treatment conditions, which were set to mimic field conditions. Detailed etched surface characterization, fluid analysis, and conductivity measurements were performed on acid etched fracture faces.
Experimental results clearly show that the amount of rock dissolved and actual etching pattern depend highly on acid concentration. While there was less fracture face etching with more spent acid system, etching pattern also changed with acid spending, which sometimes offset the additional etched volume of unspent acid. As a result, the retained conductivity was generally higher for the more spent acid and the decline in conductivity with closure stress was more subtle with the spent acid due to probably less weakening of the fracture face.
While there have been many developments in enhancing the etched length of acid fractured wells, a major reason for the lack of long etched fractures is acid spending along the fracture. In order to understand the etched fracture profile, there is a need to realize how the degree of acid spending limits etching and affects the resulting fracture conductivity. Based on the newly discovered effect of acid spending on conductivity, acid etched length and conductivity can be predicted more accurately and acid fracture treatments better designed.
Engineering Approaches' Progress in Calculation of Inhomogeneous Turbulence in Pipelines
Authors: Kharlamov S.N. , Alginov R.A. 
Published: February 2011

Abstract
Results of calculation of unsteady direct and degenerating swirl turbulent flows of liquids and gases in pipes and channels with short and extensive flow regions are presented. Swirled flow hydrodynamics is investigated in details in the area of inlet into the pilot section. In modeling of turbulent heat-and-mass transfer there used 2nd order closure schemes with differential equations for Reynolds stress tensor with original low-reynolds restricting base of k-L equations. Mechanisms of generation and development of reverse flows, degeneration and rearrangement of swirl flow into direct one are analyzed in broad range of governing parameters. Developed algorithm accuracy in prediction of local and integral parameter distribution of complicated swirl flows are illustrated by means of comparison with experimental data.
Estimation of "Very-Difficult-to-Identify" Data for Hole Cleaning, Cuttings Transport and Pressure Drop Estimation in Directional and Horizontal Drilling
Authors: Ozbayoglu M. Evren , Ettehadi Reza O. , Murat Ozbayoglu A. , Ertan Yuksel 
Published: February 2011

Abstract
As the inclination of a wellbore increases, cuttings start having a tendency to accumulate in the lower section of the wellbore, and develop a cuttings bed. This developed bed causes a reduction in the flow area, an increase in the friction between the drillstring and the wellbore, leading to an increase in torque, decrease in force transfer to the bit, and lose control on the bottomhole pressure. Finally, drilling rate decreases. Estimation of total concentration inside the wellbore is not an easy task. Moreover, moving cuttings and fluid dragging them to move have different relative velocities inside the wellbore, causing variations in pressure drop. Although there are many attempts to estimate the cuttings concentration and slip between the cuttings and the fluid using mechanistic models and empirical correlations, the performances are limited either with the strong assumptions made, or the experimental facility capabilities. This study aims to determine some of the very-difficult-to- identify data for estimating total pressure drop and total cuttings concentration inside the wellbore. Extensive experimental work has been conducted using a cuttings flow loop at horizontal and inclined wellbores. Tests have been conducted using water to simulate low viscosity fluids. Data has been collected for a wide range of flow rates, cuttings injection rates and pipe rotation speeds. All experiments have been recorded using a high-speed digital camera. Images have been processed using special algorithms, and volumetric distributions of cuttings and fluid can be identified very accurately. By comparing consecutive images, very valuable information has been collected about the accumulated cuttings amount, concentration of moving particles, their relative transport velocities, slip velocity between the phases, the friction factor on the stationary bed, etc. Since the images are digital, information collected is converted into numerical values, and semi-empirical equations are developed as a function of known drilling parameters. The obtained information is tested in simple mechanistic models for estimating pressure drop inside a wellbore with the presence of cuttings, and the performance of the model is tested by comparing the results with the measured ones. It is observed that, after supplying the very-difficult-to-identify information to the mechanistic model, the performance of the mechanistic model improved very significantly. The information provided will improve the design of long extended reach wells while estimating hydraulic requirements, and make it possible to have a better understanding of what is really happening inside the wellbore.
FIB/SEM and Automated Mineralogy for Core and Cuttings Analysis
Authors: Lemmens H.J. , Butcher A.R. , Botha P.W.S.K. 
Published: February 2011

Abstract
New high resolution microscopy solutions are being used for conventional and unconventional reservoir characterization at both micron and nanometer scales. Focused Ion Beam and Scanning Electron Microscope (FIB/SEM) technology combines the high resolution of a SEM with the precise milling capability of a FIB. 3D reconstructions with resolution of a few nanometers are made possible, leading to new insights into rock fabrics, porosity and permeability. Illustrative FIB/SEM data of shale and carbonate reservoirs are presented. High resolution imaging resolves the complex micro-structure and microporosity present in the shale and carbonate.
Automated Mineralogy, another emerging solution for petrological analysis, involves the ultrafast mineral and textural mapping of cuttings and cores, achieved through a fully integrated system comprising automated SEM imaging and energy dispersive X-ray spectroscopy (EDS). Through customized analysis software, the resulting false-colored images can be used to quantify the mineralogy, grain size, grain density, porosity, and lithotypes, on a cutting-by-cutting or core-by-core sample basis. These data in turn can be used to provide objective inputs into geological, geophysical, and engineering interpretations of reservoir properties.
Characterizing the Precambrian Petroleum Systems of Eastern Siberia: Evidence from Oil Geochemistry and Basin Modeling
Authors: Everett Melanie A. 
Published: February 2011

Abstract
Uncertainties regarding the number, location, and areal extent of Precambrian petroleum systems in Eastern Siberia are primarily attributed to a lack of direct source rock data. This study provides an indirect characterization of source rocks contributing to petroliferous areas (PAs) in the southern Lena-Tunguska region through an assessment of available geochemical data from oils and gases contained in reservoirs from the Vendian through lower Cambrian. Geochemical data and basin modeling were used to: (1) establish the number of source rocks contributing to hydrocarbon accumulations; (2) define source rock depositional systems and lithology; (3) estimate source rock thermal maturity; and (4) predict source location and migration patterns.
In this study, geochemical interpretations are made on oil and gas data available from the published literature and GeoMark Reservoir Fluid Database and include comparisons of samples from the Nepa-Botuoba, Angara-Yenisey, Katanga Saddle, and Baykit PAs. One-dimensional maturity models of pseudo-wells in the Nepa-Botuoba and Angara-Yenisey PAs are constructed incorporating inferred source rock characteristics to constrain the timing and thermal histories of the petroleum system components. Results from this study confirm that the Eastern Siberian oils are non-biodegraded and were generated within the main oil window from Precambrian sources. Significant geochemical differences among oils from the Nepa-Botuoba, Angara- Yenisey, and Baykit PAs strongly support hydrocarbon generation from three distinct source rocks. Furthermore, biomarker and bulk oil parameters indicate lateral hydrocarbon migration across the Nepa-Botuoba anteclise that originated from a single source. These findings both advance the current understanding of the East Siberian petroleum systems and have direct consequences for prediction of fluid characteristics at the field and reservoir scales.
Fully Stochastic Screening and Ranking on Entire Reservoir Portfolios - A Case Study for Candidate Recognition for Waterflood Implementation
Authors: Graf T. , Zangl G. , May R. , Hartlieb M. , Randle J. , Al-Kinani A. 
Published: February 2011

Abstract
Waterflooding is among the oldest and perhaps most economical of Enhanced Oil Recovery (EOR) processes to extend field life and increase ultimate oil recovery from naturally depleting reservoirs. High oil prices provide incentive for companies to look deeper into their reservoir portfolios for additional waterflooding opportunities. Time and information constraints can limit the depth and rigor of such a screening evaluation. Time is reflected by the effort of screening a vast number of reservoirs for the applicability of implementing a waterflood, whereas information is reflected by the availability of data (consistency of measured and modeled data) with which to extract significant knowledge necessary to make good development decisions.
A new approach to screening a large number of reservoirs uses a wide variety of input information and satisfies a number of constraints such as physical, financial, geopolitical, and human constraints. In a fully stochastic workflow that includes stochastic back-population of incomplete datasets, stochastic proxy models over time series, and stochastic ranking methods such as Bayesian belief networks, more than 1,500 reservoirs were screened to reduce their number by one order of magnitude to about 100 potential candidates that are suitable for a more detailed phase of evaluation. Numerical models were used to create response surfaces that capture the sensitivity and uncertainty of the influencing input parameters on the output. Reservoir uncertainties were combined with expert knowledge and environmental variables and were used as proxy model states in the formulation of objective functions. The input parameters were assigned in a stochastic manner. The output is represented by a ranking of potential waterflood candidates.
The benefit of this approach is in the inclusion of a wide range of influencing parameters while at the same time speeding up the screening process without jeopardizing the quality of the results.
Implementation of Real Time Monitoring System for Priobskoye Field
Authors: Baryshnikov A. , Sidorenko V. , Tychinski A. , Timokhovich Y. , Safronov D. , Gladkov A. , Kondakov D. 
Published: February 2011

Abstract
The concept of “Intelligent Field” is becoming a promising strategy in the oil and gas industry. This approach includes several levels (components) of information management: Data gathering system (data channels, data transmitters);Data processing and analysis (simulation and monitoring tools);Data integration solutions;Feedback (well response, ESP frequency response).
This paper describes the application of the data gathering and integration process supported by the data processing and simulation tools in the Southern License Territory (SLT) of Priobskoye Field (West Siberia). The proposed solutions provide a suitable base for daily monitoring of problematic elements with the appropriate feedback to the related services if a problem occurs.
These solutions were implemented to monitor the production process in the SLT of Priobskoye field, they were successfully used to reach the main goals: Gathering of the field information in real time;Introduction of the tool to control artificial lift production for our technologists;Access to the information about problematic wells at least once per day;Visual and analytical reports related to problematic wells;Field development planning and monitoring tools for specialists involved in waterflood simulation and management.
The results of this work can be used to analyze the learning process, to evaluate the prospects of “return on investments” put into the simulation models, which in our case are constantly upgraded and used in work. The important result of this project is a transparent and fast decision-making process supporting oil production activities.
Remote Monitoring and Production Optimisation in Shell
Authors: van den Berg Frans , Goh Keat-Choon , van Donkelaar Edwin , Parchewsky Robert 
Published: February 2011

Abstract
With the advancement of technology, fields are increasingly monitored in real time, remotely from the office. This applies to wells and facilities alike. Shell has applied a range of capabilities across the assets worldwide. The capabilities include: –Real time monitoring and optimisation of wells–Virtual metering–ESP surveillance - real time monitoring and remote control–Advanced Rotating Equipment monitoring–Integrated Production System Modelling–Collaborative Work Environments for integrated decision making
The paper describes how these techniques are used in Shell's operations. They enable asset staff to deal with a wider range of issues faster and more efficiently while bringing global expertise as required in near real time. This involves integration across a range of disciplines, for fast and effective decision making.
Striving for Zero Serious Injuries: Experience of the Oil Operator in Western Siberia
Authors: Samoylova O. 
Published: February 2011

Abstract
Safety has been one of the most critical areas calling for rapid and fundamental improvement in the global Exploration and Production sector over the recent decades. This has resulted in recognized industry examples of outstanding safety excellence that enabled some companies to go up to five consecutive years or more without a lost time injury because they have done an excellent job of engineering and guarding their plants and equipment, providing personal protective equipment and training employees in safer systems and procedures.
Although there are unquestionable reasons behind a safety focused oil and gas production including tragic events of lost lives and ruined businesses that were caused by poor safety management and lack of safety leadership in the past, not too many companies have managed to embrace and exercise safety through every day practical commitment and action. This might seem and really does become even more difficult in the harsh environment of the Western Siberia oilfield with its inherited safety standards and widely spread risk taking practices. And that is exactly the challenge being faced by the company.
Our experience suggests that there are key success factors but also some misconceptions and undervalued opportunities for making a difference in safety as proven by our own operations.
The main purpose of the paper is to share company's learnings from implemented Goal Zero Must Win framework. The currently taken approach can be divided in three mainstreams aimed at: 1) behavior change -inspired by the company leadership who enable and encourage “compliance and intervention” culture whereby safety becomes positive, proactive and natural; 2) delivery against focused action plans - associated with high risk areas with biggest exposure, project oriented and led by the company management team members; 3) life saving rules - communicated, embedded and enforced.
We hope that experience shared will serve as a practical guide and best practice source for those companies working in the Russian Federation that put the goal of “No harm to People” as their number one priority.
Foaming Mitigation and Process Upset Management: Operation Case Study
Authors: Nengkoda Ardian , Hajri Mohd , Naabi Saud , Kindy Azzan , Reerink Hendrikus 
Published: February 2011

Abstract
Since commissioning of the new main bulk separator in X, Field Petroleum Development Oman station in 2008; the separator had gone through serious of problems of fluid foaming. Throughout 2009 and until early 2010, X station gone through big instability of production issue mainly due to the main bulk separator upset which resulted in measurable production impact. Some amount of water is exported to main station via the GRE line that causes increase in the GRE line pressure and therefore forced to shut-down of X oil producers. This disturbance in the system as flow assurance issues, observed at least every 2 months with a minimum of 2 weeks per each disturbance. The average water cut in the export of X Field in 2009 was around 7% although during the upsets it reached sometime up to 85%. In November 2009 an integrated multi disciplinary team was formed to look at this issue and action plan has been set after identifying the route causes of the instability and foaming problems. The latest production and process upset in the system during the past 2 months is even worse than the 2009 upsets (with bigger lost production impact), and took longer than usual with all the actions and measures that has been taken earlier. Based on the fluid characterization study, emulsion and foaming testing, the root caused of foaming is due to excessive CO2 content from reservoir, sodium meta silicate, carboxylic acid and shearing by artificial lifting ESP downhole and the proactive surveillance and injection of novel anti foaming polymer type combined with emulsion breaker chemicals as mitigation is success to inhibit foaming.
Integration of 4D Seismic to Add Value: The Enfield ENC01 Sidetrack Story
Authors: Medd Daniel , Thomas Peter , Sibbons Craig , Smith Megan , Ali Amna 
Published: February 2011

Abstract
The Enfield oil field, on Australia's Greater North-West Shelf, has now produced over 50 million barrels of oil. The field is a water flood development with both downdip and updip water injection wells. Faults and baffles within the reservoir create a complex dynamic system that can only be understood with the integration of 4D seismic data. Monitor surveys in 2007 and 2008 have made major contributions to reservoir management and identification of infill drilling opportunities.
This paper highlights the value of fully integrating 4D seismic into reservoir management, and the rationale for sidetracking a water injector well at short notice to provide pressure support to the field's largest producing oil well. Oil production from this well was dropping rapidly and the need to improve pressure support was clearly evident. It only became clear how best to achieve this upon delivery of new 4D results.
The reservoir model directed attention towards insufficient water injection downdip and the opportunity to sidetrack these injection wells closer to the production wells was under consideration. However, results of the December 2008 4D monitor survey became available at this time, and indicated a reservoir baffle between the oil producer and the downdip injectors, which diverts water away from the producer. Thus improving injectivity at these downdip water injector wells would have had little impact on the failing producer.
The 4D seismic data also indicated that water from a key updip injector was being deflected away from the producer. The difference here was that the baffle was close to the water injector and not the oil producer. The opportunity to sidetrack this water injector across the baffle was rapidly progressed, with the injector sidetrack drilled and completed in mid 2009.
Pressure support at the oil producer was seen within days of commencing injection in the sidetracked well. Revenue from increased oil production paid back the cost of the injector sidetrack and the 4D monitor survey within two months of startup. The involvement of all subsurface disciplines was a key success factor in the outcome.
Mechanical and Geochemical Assessment of Hydraulic Fracturing Proppants Exposed to Carbon Dioxide and Hydrogen Sulfide
Authors: Bremer J. M. , Mibeck B. A. , Huffman B. W. , Gorecki C. D. , Sorensen J. A. , Schmidt D. D. , Harju J. A. 
Published: February 2011

Abstract
The Energy & Environmental Research Center (EERC) has conducted a study to determine the mechanical and geochemical changes experienced by proppants as a result of exposure to CO2 and H2S in simulated reservoir conditions. This study was conducted under a cooperative agreement with the U.S. Department of Energy's National Energy Technology Laboratory with the goal of investigating factors affecting production in the Bakken Formation of North Dakota.
As hydraulic fracturing is critical to successfully producing tight oil, proppant longevity is also critical to maintain fracture conductivity to the wellbore. Long-term conditions such as reservoir souring and the potential for CO2 enhanced oil recovery (EOR) within the Bakken were considered in the study to examine the effects on proppant strength. The possibility exists for proppant degradation due to the large amount of fluids that travel through fractures, the high surface area of the proppant within the fractures, and the already taxing subsurface conditions.
In order to understand the potential degradation of proppant compressive strength, samples were acquired that represent common proppants, including both natural and synthetic materials. Samples were subjected to simulated downhole conditions and exposure to supercritical CO2 and acid gas containing 85% CO2 and 15% H2S. Effects of the presence or absence of brine was also examined. Samples removed from the reactor were subjected to one-dimensional confined compressive strength testing and sieve analysis to examine the amount and size of damaged material compared to baseline, as-received material.
Preliminary results indicate that all proppants show varying degrees of strength loss postreaction, and work is being performed to determine whether the causation is a product of brine interaction, reactor pressurization, or reactor depressurization, or is indeed due to mineralogical gas/proppant interactions. The results of this study will aid in the selection of optimal proppant materials for long-term or multiple-use performance in unconventional oil shale and gas shale production wells, as well as potential for retrofitting a well for injection purposes. The work has further applications with the potential use of hydraulic fracturing for increasing the injectivity of CO2 relative to carbon storage.