bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stimulation of Stable Micro-Emulsion at Oil-Water Interface Using Co-Surfactants as an Alternative Method for Enhanced Oil Recovery
Authors: Bahar M. , Liu K. , Rashid A. 
Published: October 2012

Abstract
In order to screen various chemical and microbial EOR methods for core-flooding experiments and potential field trials, a laboratory investigation of evaluating the effect of micro-emulsion on the reduction of interfacial tension (IFT) was recently carried out at CSIRO by using commercially available chemical and bio-surfactants. Environment friendly non-ionic, anionic surfactants and a biosurfactant (Bacillus subtilis) were used to create micro-emulsion in an oil-brine system. Stable micro-emulsion (ME) was achieved by proportionally mixing various alcohols with surfactants.
Twenty-four micro-emulsion samples with five different chemical combinations were prepared for screening. All samples were stirred to create a stable ME phase. The volume changes of the ME phase were monitored over two weeks and their density, viscosity, and IFT were measured. The size distribution of ME phases was also characterised using optical microscopy equipped with an UV light source.
The micro-emulsion created by co-surfactants were found to be quite effective in reducing the oil-brine IFT and oil viscosity, and achieved ultra low IFT under reservoir pressure and temperature. There appears to be a linear relationship between the size of micro-emulsion and IFT reduction. ME with small sizes results in more IFT reduction and achieve stable ME at high temperature and pressure. Compared with the IFT reduction from the surfactant or microbial metabolism, the reduction of IFT through stable ME can be several orders of magnitude larger and may thus achieve better enhanced oil recovery in suitable reservoir systems.
A Variable Shape Distribution (VSD) Model for Characterization of Pore Throat Radii, Drill Cuttings, Fracture Apertures and Petrophysical Properties in Tight, Shale and Conventional Reservoirs
Authors: Aguilera Roberto F. , Ramirez John Freddy , Ortega Camilo , Aguilera Roberto 
Published: October 2012

Abstract
Fractal and power law distributions have been found in the past to be useful for modeling some reservoir properties following the assumptions of constant shape and self-similarity. This study shows, however, that pore throat apertures, fracture apertures, petrophysical and drill cuttings properties of unconventional formations are better matched with a variable shape distribution model (as opposed to constant shape). This permits better reservoir characterization and forecasting of reservoir performance.
Pore throat apertures, fracture apertures, petrophysical properties and drill cutting sizes from tight and shale reservoirs are shown to follow trends that match the variable shape distribution model (VSD) with coefficients of determination (R2) that are generally larger than 0.99. The good fit of the actual data with the VSD allows more rigorous characterization of these properties for use in mathematical models. Data that could not be described previously by a single equation can now be matched uniquely by the VSD. Examples are presented using data from conventional, tight and shale formations found in Canada, the United States, China, Mexico and Australia.
In addition, the study shows that the size of cuttings drilled in vertical and horizontal wells can also be matched with the VSD. This allows the use of drill cuttings, an important direct source of information, for quantitative evaluation of reservoir and rock mechanics properties. The results can be used for improved design of stimulation jobs including multi stage hydraulic fracturing in horizontal wells. This is important as the amount of information collected in horizontal wells drilled through out tight formations, including cores and well logs, is limited in most cases.
It is concluded that the VSD is a valuable tool that has significant potential for applications in conventional, low and ultra-low permeability formations and for evaluating distribution of rock properties at the micro and nano-scale.
Experimental and Numerical Studies on the Microbial Restoration of Natural Gas Deposits in Depleted Oil Reservoirs Storing CO2
Authors: Mori R. , Sugai Y. , Sasaki K. , Fujiwara K. , Nakamura T. 
Published: October 2012

Abstract
We investigated the microbial conversion of CO2 into CH4 in depleted oil reservoirs by the interaction between indigenous oil-degrading hydrogen-producing bacteria and indigenous hydrogenotrophic methanogens that have been found in oil reservoirs universally. In this study, we investigated the influence of crude oil, yeast extract, bicarbonate and CO2 on the growth and gas production of those bacteria through the incubation experiments of isolated strains under reservoir conditions. The yeast extract was estimated to be the most influential factor on the growth and gas production of oil-degrading hydrogen-producing bacteria. Methanogen was unaffected by the crude oil, the yeast extract and bicarbonate, however, both CO2 and H2 are assumed to be the influential factors on it because they are the energy sources of methanogen.
In addition, we also investigated their growth kinetics that were needed to construct a numerical simulator of the microbial conversion of CO2 into CH4 in depleted oil reservoirs. The specific growth rate of oil-degrading hydrogen-producing bacteria was increased as the yeast extract concentration increased while that of the methanogen was constant regardless of the yeast extract concentration. These results indicate that the growth of methanogens is unaffected by the yeast extract that is injected into reservoirs to stimulate the growth of ODHPB. The growth yield of HYH-8 and HYH-10 was 5.5×1010 cells/g-(yeast extract) and 3.5×1011 cells/g-(yeast extract) respectively.
Hammer Motor Breaks Ground In China
Authors: Herrington D. , Barton S. , Sha D. , Cote B. , Gaines M. , Morrison R. 
Published: October 2012

Abstract
Bit and bottomhole assembly (BHA) dynamics are a challenge when drilling in hard and interbedded formations. Dynamic conditions such as stick-slip and whirl can limit performance or in the worst case destroy downhole components. A new percussive mud hammer motor is being implemented in China to improve drilling performance by imparting a controlled impact to the bit while drilling.
Conventional technologies to address these challenges may have limited improvement significant added costs:
Conventional motors can generate large amounts of torque to the bit but can be difficult to control tool face and depth of cut as the bit transitions through various formations. This can result in stick-slip and bit bounce that can quickly damage or destroy the bit and BHA. Rotary steerable systems can control downhole dynamics with complex electronic, hydraulic and mechanical components but are very expensive, require higher system pressures and on-site supervision. Turbines with impregnated diamond bits can provide smooth drilling but can have limited rates of penetration in the softer portions of interbedded formations. In operation they also require higher pressure drops, have limited build rates and require on-site supervision by a turbine technician.
These conventional system limitations created an opportunity for a new technology that is simpler and brings greater value to the drilling operation. The hammer motor is a conventional power section and drivetrain with the patent pending hammer mechanism fitted in place of the lower bearing. This assembly has the same geometry of a bent housing motor with all of its capability plus the impact of a rotary hammer.
A series of field trials in China have recently been performed to validate the performance increases created by the hammer motor. These trials demonstrated significant cost savings, improved drilling performance, and simplicity of operation.
Laboratory Evaluation and Analysis of Physical Shale Inhibition of an Innovative Water-Based Drilling Fluid with Nanoparticles for Drilling Unconventional Shales
Authors: Ji Lujun , Guo Quanxin , Friedheim Jim , Zhang Rui , Chenevert Martin , Sharma Mukul 
Published: October 2012

Abstract
Although key shale gas plays vary considerably in terms of reservoir pressure, temperature, mineralogy, and in-situ stresses, the principal drilling-related issues are wellbore stability, shale inhibition, hole cleaning and rate of penetration. Because many of the shale reservoirs are in either environmentally sensitive or densely populated areas, stricter environmental regulations will require new types of environment-friendly water-based drilling fluids. The traditional shale inhibition method through either chemical inhibition or use of invert emulsion drilling fluid is not enough to satisfy the stricter environmental requirements.
This paper focuses on the lab techniques and the performance results of evaluating and analyzing an innovative water-based drilling fluid system containing nanoparticles as a physical shale inhibitor. The physical shale inhibition is achieved by plugging the pores and microfractures in shale with nanoparticles and thus preventing water invasion into the shale. A series of transient pressure penetration or flow-through tests, also known as shale membrane efficiency tests, were performed to evaluate water invasion rates into various shale core samples, with initial brine permeabilities varying from less than 1 nD to over 100,000 nD. Permeability reduction was used as a proxy of water invasion reduction and the effectiveness of plugging of pores and microfractures in shale by the nanoparticles. Many orders of permeability reduction were consistently observed for the drilling fluids with nanoparticles.
Pressure increases in the near-wellbore region due to water invasion during a given time also were analytically calculated using the permeabilities for various fluids which were interpreted from these transient flow-through tests. These pressure increases then were compared to illustrate the approximate impact depth of water invasion and give an indication of shale stability and shale inhibition performance of these drilling fluid systems.
Test results and pressure increase analyses showed that this new water-based drilling fluid with nanoparticles provides an entirely different type of shale inhibition by physically plugging pores and microfractures in shale and meets the strictest environmental regulations for shale gas drilling. The tests also showed that although nanoparticles alone may be effective in preventing water invasion into shale samples with no microfractures, the combination of properly formulated drilling fluid and nanoparticles of appropriate size and concentration is the key to prevent water invasion into shale gas core samples with or without microfractures.
Failure Probability with Time under Different Operational Conditions for Low-Density System Based on Hollow Microspheres Supported By Long Term Lab Studies and Field Cases
Authors: Al-Yami Abdullah S. , Yuan Zhaoguang , Schubert Jerome 
Published: October 2012

Abstract
Cementing a string in one stage is a challenging task, especially in the presence of weak formations. Cement slurry losses during placement is highly possible if the equivalent circulating density (ECD) exceeds 82 pcf during placement. A conventional method to overcome this challenge is to use multi-stage cementing by setting the stage tool above the loss circulation zone. However, field data indicate that the tool can fail, thus causing serious delay and economic loss. In addition, stage tools are considered weak point and not good for long term seal. A second method for zonal isolation is to use low density cement.
In this study, we present extensive lab evaluation of a low density system based on the use of hollow microspheres for one year at field conditions. The tests included one year mechanical properties measurement such as compressive strength development, Young's modulus and Poisson's ratio. The low-density system (70 pcf) was tested at 300 ºF. An earlier study has shown the suitability of using low density cement in the field, Al-Yami et al. (2007). However, there is no available Investigation in the literature about the durability of low density cement at higher temperature and at different operational scenarios.
The finite element method was used to analyze the failure probability of HPHT wells over with time. At the variation of bottom whole pressure, the casing, cement, and formation system failure probability was studied for this type of cement.
This paper introduces the operational envelope for this type of cement in order to achieve successful operations. Field cases were discussed to validate the results of this investigation.
Is There A Better Way to Determine The Viscosity in Waxy Crudes?
Authors: Daungkaew Saifon , Fujisawa Go , Chokthanyawat Suchart , Ludwig John , Houtzager Fred , Platt Christopher , Last Nick , Limniyakul Theeranun , Phaophongklai Wattanaporn , Comrie-Smith Nick , Thaitong Thanagit 
Published: October 2012

Abstract
Accurate viscosity measurement is difficult even under the best of conditions and the lengthy time required to send and receive results from a lab prohibit basing important decisions on the viscosity of the reservoir fluid. Those challenges increase for reservoirs with complex fluids such as the highly viscous, waxy crudes found in many of the oil fields in South East Asia.
While correlations have been developed to determine the viscosity of waxy crudes, the accuracy can be limited under certain conditions. The objective of the paper is to review visc sity correlations for waxy crude and examine their applications to the actual field data. Limitations on the use and accuracy of these correlations will then be discussed. This paper also discusses the viscosity obtained in real-time from the suite of Downhole Fluid Analysis (DFA) measurements, and the result is then compared to standard PVT analysis over a wide range of viscosities, temperatures, and pressures.
Results of the DFA viscosity measurements in several fields in South East Asia are discussed together with other fluid properties such as GOR, density, and fluid compositions. The viscosity is then examined at the field scale to help understand the reservoir complexity in terms of compartmentalization in these waxy oil environments.
The technical contribution from this paper is that it presents the variation of the viscosity in waxy oil reservoirs and its impact on real time decision making, especially for purposes of pressure transient analysis. This paper covers the evolution of the DFA viscosity measurement including a description of the hardware, discusses the limitation of the DFA measurement for certain conditions, and summarizes the accuracy of the DFA viscosity measurement for different fluids and the ongoing development for covering more fluids in the lower end of the viscosity spectrum.
An Operator's Experience of the Successful Deployment of a Subsea Multiphase Boosting System Offshore Western Australia
Authors: Nallipogu Tim , Oppedal Jørn H , Mckay Linda , Glucina Andrew 
Published: October 2012

Abstract
The field was developed in a deepwater setting by Woodside Energy Ltd (WEL) and Mitsui E&P Australia Pty Ltd and commenced production in 2008. The field is located some 50 km offshore Western Australia, in approximately 400m water depth. Similar to other projects in the area, the development of the field was based on a subsea tieback to an Floating Production Storage and Offtake vessel (FPSO). The artificial lift for the field was based on the deployment of a subsea multiphase boosting system, to ensure satisfactory production rates and recovery of hydrocarbons.
This paper will address the typical applications and characteristics for subsea multiphase boosting systems, and provide an overview of the system deployed, as well as the drivers for selecting this technology. The benefits to the users are normally related to reduced investments, and more importantly, increased recovery and optimum utilization of hydrocarbons in place. The potential extension of field life for producing assets through multiphase boosting may have significant impact on the overall economics of the development.
The operational experience of the subsea boosting system will be discussed, including the performance of the subsea boosting system. The operation of the boosting system is based on the concept of integrated operations, and thus the performance of the subsea pumps and all auxiliaries are condition monitored on a real-time basis. The experience and added value generated through integrated operations of subsea rotating machinery will be discussed, including the potential upside with regards to system availability and maintenance.
Based on the successful deployment of a subsea multiphase boosting system the operator gained experience with the operation of subsea rotating machinery and production boosting. It is the objective of this paper to share considerations, advantages and future expectations of the technology, and put forward recommendations for future deployments of the same.
3-Phase Flow Correlation Selection for Production Logging Interpretation
Authors: Jongkittinarukorn Kittiphong , Kerr Robert 
Published: October 2012

Abstract
Production Log analysis is based on the calculation of fluid flow velocity, usually from a spinner, some fluid identification sensors to work out the holdups of fluids along the wellbore with a lookup of the slippage between the fluid phases from a correlation. The fluid rates are a result of the calculations and very dependent on the attributed slippage velocities. There are a number of slippage correlations in the Emeraude Production Logging (PL) analysis program from Kappa. The choice can be significant as the results from using different correlations may move the apparent water production from one zone to another. Usually the analyst just uses the correlation that gives the result closest to the surface test and keeps that correlation for all other zones.
The object of this paper is to find a more systematic way to pick the flow correlation to use in a 3-phase well. In Emeraude there are 7 Oil-Water (O-W) correlations and 2 full 3-phase flow correlations. For the O-W correlations, one has to pick a Gas-Liquid (G-L) correlation first. We used the correlation recommended by our previous study (Jongkittinarukorn and Kerr, 2011) to work out the G-L slippage and then used a similar statistical technique to determine which correlation works best determine the O-W slippage.
This study finds that 3-Phase G-L correlations perform better than 3-Phase correlations do. Choquette, ABB-Deviated, and Stanford Drift Flux LL correlations are the best three flow correlations and are recommended for PL analysis in a 3-phase well. The results of the statistical analysis indicate that gas rate, oil rate, and water cut are critical for flow correlation selection.
Development of MEG Regeneration Unit Compatible Corrosion Inhibitor for Wet Gas Systems
Authors: Bikkina Chaitanya , Radhakrishnan Narayanan , Jaiswal Sumit , Harrington Ryan M , Charlesworth Mark 
Published: October 2012

Abstract
Transportation of hydrocarbons and water in long subsea flow lines from satellite fields to a platform or to an onshore facility presents new challenges in the control of gas hydrates, corrosion, and mineral scale. Gas hydrates form at high pressure and low temperature and are a common problem in offshore wet gas pipelines due to low seabed temperatures and elevated pressures in these remote subsea developments. Monoethylene glycol (MEG) is widely used as a thermodynamic hydrate inhibitor in these developments to manage the risk of hydrate formation during production and transportation of multiphase fluids from subsea wells.
Due to large amounts of MEG required for effective hydrate control, it is necessary to recycle and re-use it. The main processes for recycling of MEG are regeneration and reclamation. Typical conditions of regeneration and reclamation processes are ambient to vacuum pressures and temperatures in the range of 120°C −150°C1. In addition to the use of MEG for hydrate control, corrosion inhibitors are also applied for corrosion control in the subsea pipelines and infrastructure. These corrosion inhibitors must be able to perform under high shear and highly corrosive environments without losing their effectiveness after having been subjected to the system conditions present in the MEG regeneration process. Inappropriate selection of corrosion inhibitors for MEG based applications can lead to severe fouling/formation of solids, emulsion and foaming issues in the receiving facilities. The corrosion inhibitors developed for use in facilities operating with glycol regeneration systems should remain active after multiple MEG Regeneration Unit (MRU) cycles without causing fouling/formation of solids, emulsion and foaming.
The current paper presents MRU compatible corrosion inhibitors developed based on the stringent testing methods adopted from real time MRU process.
Reservoir Geomechanics Study for Deepwater Field Identifies Ways to Maximize Reservoir Performance While Reducing Geomechanics Risks
Authors: de Souza Antonio Luiz , de Souza Jorge André , Meurer Gustavo Bechara , Naveira Vanessa Palma , Chaves Ricardo Alexandre , Frydman Marcelo , Pastor Jorge , Chaves Michelle 
Published: October 2012

Abstract
Several Petrobras fields in Campos Basin are soft sandstone with a large number of faults, which demands a careful reservoir geomechanics study in order to maximize their production and minimize geomechanical risks. Those risks are associated with compaction and/or dilation, subsidence and in special with fault reactivation due to water injection, which can lead to a connection between different layers and reservoirs.
The object of this study is a faulted turbidity reservoir in Campos basin where a water injection project has started. The Mechanical Earth Model (MEM) was developed. It was identified that the planned injection pressure would increase the risks for fault reactivation, and recommendations for a safe water injection project was obtained. Special emphasis is on factors that may have enhanced leakage pathways at some point during injection, reducing its effectiveness and bringing other related risks. Reservoir performance and associated reservoir deformation was estimated. The predicted stress and strain changes that were induced by production/injection were used to assess the wellbore stability, faults reactivation potential, cap rock integrity and rock fracturing. Understanding of the various potential processes and being able to predict the field behavior are critical to the optimal management of the reservoir for maximum productivity and recovery.