bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technical Breakthrough in Production Engineering Ensures Economic Development of ASP Flooding in Daqing Oilfield
Authors: Jiecheng Cheng , Wanfu Zhou , Qingguo Wang , Gang Cao , Wenguang Bai , Changming Zhao , Meie Luo 
Published: September 2014

Abstract
Pilot tests commenced from 1980s in Daqing Oilfield have proved that ASP flooding could improve the recovery rate by 20% based on water flooding, while scaling issue in producers was the only factor which made it hard to reach that objective. Investigation in site indicated that more than 70 percent producers had scaling issues, and scaling types and degree in ASP producers varied dramatically in different wells and different period. In the peak of scaling period, the averaged running life was only a couple of months.
A project focused on the harness of scaling issue in ASP producers was implemented from 2002. In the first stage, the study aimed at getting the scaling principle in ASP producers. A series of monitoring and analysis on producing fluid's ion concentration were implemented in different ASP producers. The scale deposited on tubing in different depths were picked out and analyzed. The scaling mechanism of ASP producing liquids in artificial lift systems were created which presented the varying principle of scaling ions as well as the characteristics of scale in ASP producers. A set of scaling principle prediction plates was also created with a success ratio being above 90%.
In the second stage, a series of anti-scaling artificial lift techniques were developed including new anti-scaling pump, chemical scale removers and scale inhibitors, and other matching techniques. The new anti-scaling techniques were put into application from several wells up to near 1,000 wells. The operating rate has been improved by 4.13 percent as well as the operating cost decreased by 72.77%.
The technical breakthrough in anti-scaling artificial lift systems improved the operating life of ASP producers considerably. It applied solid foundation for ASP flooding to become a beneficial method for mature oilfield development in commercial scale.
Controlled Freeze Zone Technology for the Commercialization of Australian High CO2 Natural Gas
Authors: Valencia Jaime A. , Denton Robert D. , Northrop P. Scott , Mart Charles J. , Smith Ransdall K. 
Published: September 2014

Abstract
The simple separation of CO2 from natural gas by distillation would involve cryogenic temperatures at which CO2 solidifies. Most CO2 separation processes avoid this and use instead solvents that bind to CO2 molecules. For solvent regeneration, the binding process is reversed by addition of heat, lowering of pressure, or both. This adds extraneous chemicals and processes. The Controlled Freeze Zone™ brings back the simplicity and efficiency of a single step distillation process for the separation of CO2 from natural gas. Rather than avoiding the freezing of CO2, it allows it to take place, albeit in a very controlled fashion. The technology has shown the potential to more efficiently and cost-effectively separate carbon dioxide and other impurities from natural gas, and to discharge these contaminants as a high-pressure liquid stream ready for underground injection, either for enhanced oil recovery applications or for acid gas injection disposal.
An LWD Open-Hole Sigma for Time-Lapse Reservoir Monitoring - Case Study from South East Asia
Authors: Khairul Azhar A B , Hassan Nur Atiqah , Thanapala S M , Han Mei , Lee Samie , Roberts Iwan 
Published: September 2014

Abstract
Sigma log has long been crucial in cased-hole evaluation as it is one of a few measurements that can be made through complicated well completions. In fresh water environments, sigma log was used to discriminate gas from liquid; in some cases can differentiate water from oil, hence used subsequently for time-lapse reservoir monitoring to indicate changes in fluid type over production. A problem arises when no baseline sigma is available for time-lapse comparison. Traditionally a synthetic baseline sigma log may be artificially derived but suffers from uncertainty due to compounding of any errors in original volumetric interpretation as well as errors in the endpoint estimations.
The measurement of formation sigma under open hole condition has been enabled by a downhole pulsed neutron generator (PNG), installed in a multi-function logging while drilling (LWD) tool. The relatively large LWD collar reduces significantly the influence of borehole salinity which results in accurate sigma measurement while drilling. Thus a direct sigma baseline can be obtained in open-hole without errors brought from volumetric interpretation and sigma endpoint estimation. Verification of mud filtrate invasion can be done through Multi Depth of Investigation (MDOI) sigma measurements.
In order for an LWD baseline sigma measurement to be suitable for time-lapse analysis, the instrument response should be accurate, precise and repeatable by the subsequent cased-hole logging instrument. Sigma logs from both open-hole LWD and cased-hole wireline conveyed tools, over intervals of similar depth, were compared in offset wells within the same license block. Some 25 datasets from 5 producing fields in the region were examined and statistical analysis affirmed the response characteristics of both logs were emanating compatible. It confirms the data compatibility measured by both tools and supports the potential application of open-hole sigma log to serve as a baseline log for future time-lapse application.
Estimating Probability of Failure for Drilling Tools with Life Prediction
Authors: Carter-Journet K. , Kale A. , Zhang D. , Pradeep E. , Falgout T. , Heuermann-Kuehn L. 
Published: September 2014

Abstract
Drilling tools are subject to numerous operational parameters such as revolutions per minute (RPM), vibration (lateral, stickslip and axial), pressure, torque and temperature. These parameters can greatly fatigue even the most robust tool depending on where and how the tool is operated. Lifetime prediction methodologies represent an affordable and statistically significant way to estimate the probability of failure (risk) of drilling tools in a cost effective way. Understanding the potential risk is vital to ensuring reliability, performing the most efficient maintenance on the equipment and improving drilling performance. Sophisticated risk-modeling techniques reduce uncertainty in drilling operations by making use of readily available operational field data, thus eliminating the need for costly laboratory experiments. Blind spots in the decision making process are eliminated by proactively identifying precursors to costly failures in the field. Preemptive guidance during maintenance periods, for parts that may have otherwise been overlooked based strictly on procedure, is enabled. Statistical models that relate the operating environment to component life are derived from field component failure data, and introduce a fresh way to boost the drilling tool efficiency. A Bayesian-based model selection technique is also developed which incorporates operating environment variables after each successful drilling run to dynamically select the model that gives the best survival probability, ensuring maximum utilization of a component, while avoiding failure and improving the overall reliability of the tool in the field. The implementation of lifetime prediction methodologies also leads to lowered life-cycle and maintenance costs, reduced risk and improved operational performance. The paper presents the methodology used to estimate the probability of failure of drilling tools and further illustrates how to reach risk-informed decisions.
Lessons Learnt from the Large Scale Application of Image Logs to Unconventional Resources
Authors: Meyer Jeremy J. , Mildren Scott D. , Bartdorff Oliver , Tavener Emma 
Published: September 2014

Abstract
Image logs are a key tool in understanding unconventional reservoirs, providing geomechanical information and characterisation of natural fractures. This information can prove crucial in completion design and optimising production, especially where hydraulic stimulation is considered.
Image log datasets associated with unconventional developments can be large, utilise a variety of different tool types and contain data across multiple vintages. The size of the datasets requires multiple interpreters to facilitate interpretation in a reasonable time frame, while the different tool types require an interpretation scheme that is effective for image logs of different types. These factors necessitate a rigorous quality assurance system to ensure the data quality, and consistency of interpretation across multiple interpreters and tool types to maximise the utility of the interpretation results.
This paper presents a workflow for assessing large image log datasets practically derived from assessment of large datasets from multiple unconventional and conventional assets as applied to large Australian unconventional assets. Key elements of this workflow include: ·A tool independent quality control checklist that can be applied prior to interpretation.·Classification of image quality with respect to image log type.·Classification system for coal bed methane cleat characterisation of coals.·Classification system for fracture characterisation independent of tool type.·Classification system for stress related deformation independent of tool type.·A post interpretation quality control checklist to ensure consistency between multiple interpreters.
Application of Closed Loop Control Logic to Optimise End-of-life Cycling Production in a Mature Gas Field
Authors: Winterfield C. D. , Missikos J. , Tio R. , Dalgety B. 
Published: September 2014

ABSTRACT
The Moomba North gas field is situated in the Cooper Basin in central Australia. Production commenced in 1969 and as the field has matured, liquid loading of wells has become more prevalent. In order to maximise recovery from wells nearing end of life whilst minimising the cost of deliquification methods, a well cycling technique has been implemented. Alternating pressure build-up periods with subsequent flowing periods of flush production allows increased bottom hole flowing pressure to sweep liquids accumulated in the well bore.
Parameters dictating desired build up pressure and low-flow shut-in rate have traditionally been calculated and/or determined empirically, requiring regular monitoring and updating to maintain optimal flow rates in line with changing system conditions. Improvements to this methodology have been achieved through implementation of an ‘intelligent’ closed loop control logic code which iteratively monitors and adjusts set points based on historic well performance. This represents an application of technology which mimics engineering input without the need for human intervention. Trial operation on several wells has exhibited the ability of the code to respond to field conditions and operational issues – in some cases increased average flow rate has been observed when compared with parameters manually determined by field engineers.
This paper will outline the well control philosophy and development of the control logic. System implementation and additional logic built in to address irregular system conditions and equipment faults will also be included along with field data from trial results.
The implementation of closed loop control logic for well control has exhibited improved business outcomes via collaboration between production engineering, process and control engineers and information technology. The use of an automated closed loop system for mature field well control represents progress in intelligent field control in Australia and provides potential for adaptation to further applications in multi-well control.
World's First Deepwater Propellant Perforation for a Depleted Carbonate Subsea Gas Well in Malampaya
Authors: Rao K. V. , Brinsden M. S. , Gilliat J. , Tan K Y. , Bhagwat M. , Harvey N. , Bhushan V. 
Published: September 2014

Abstract
This paper describes the operational planning and process safety due diligence performed to ensure safe and successful operations in the world's first deepwater propellant perforation in a carbonate reservoir. The Malampaya gas field in the Philippines is a depleted carbonate reservoir with five subsea development wells. The Malampaya Phase 2 Project that concluded in Q2 2013 involved drilling two new infill wells MA-11 and MA-12. Given the uncertainty in prognosis (Carbonate K-Phi) and the greater risk of not securing wells with high deliverability as per the well objectives, it was decided to use some form of near wellbore stimulation to bypass the near well bore damage zone caused by cement losses and cuttings lost to the formation while drilling the 300 m reservoir section. Propellant perforation technology solution was selected based on optimization of rig time, ineffectiveness of acid jobs in a karstified, fractured carbonate and process safety considerations of acid handling on a dynamically positioned rig. 200 m reservoir section was perforated safely and successfully with 3–3/8″ propellant perforation gun with 30% propellant loading on a 2″ coiled tubing in each of these two subsea wells. A standard 6 SPF shot density and 60 degree phasing was adopted with deep penetrating charges to bypass the damage zone suspected from drilling and cementing losses in this depleted carbonate. Both the wells delivered finally in excess of 100 MMscf/day during the well test on the rig as expected. This paper outlines the expected vs. actual well performance; process safety due diligence with an elaborate modeling focus on the worst case scenario (i.e. no cement behind the 7″ liner). Static and dynamic coil modeling results are shared along with an overview of the transient modeling conducted to optimize the final perforation interval on both the wells based on the actual lithology information.
Wettability Alteration during Low-Salinity Waterflooding in Carbonate Reservoir Cores
Authors: Alameri Waleed , Teklu Tadesse Weldu , Graves Ramona M. , Kazemi Hossein , AlSumaiti Ali M. 
Published: September 2014

Abstract
Production enhancement by low-salinity waterflood in carbonate formations is a subject of intense speculation. Several mechanisms are attributed to enhanced oil recovery by low-salinity waterflooding in carbonate formations. Review of experimental data in the literature indicates that the main mechanism involves interaction of Na+, Cl−, Ca2+, Mg2+, SO42− and crude oil carboxylate ions (R-COO−) with the rock in the electrical double layer (EDL) near the surface of carbonate pores, leading to wettability alteration.
In this study, we performed four seawater floods in heterogeneous low-permeability carbonate cores followed by low-salinity floods. The core permeability is between 0.5 to 1.5 md, and porosity in the range of 18 to 25%. Cores were aged for eight weeks at reservoir pressure and temperature. We also conducted pendant drop oil-brine IFT measurement, and captive oil-droplet contact angle at different brine salinity, with and without the presence of surfactant.
The carbonate core flood results show that removing NaCl from seawater or diluting the seawater twice and four times yielded about 8% incremental oil. In one experiment, the change in the effluent ionic concentrations was measured, and it was observed a decrease in Ca2+, Mg2+, Cl−, and SO42−. Using pendant drop IFT measurements, oil-brine IFT increased with decreasing salinity both in presence and in absence of 1,000-ppm surfactant. From captive oil-droplet contact-angle measurements, it was observed that cleaned un-aged carbonate core slabs were water-wet, and became more water-wet as salinity decreased (both in presence and in absence of 1000-ppm surfactant). The wettability of crude-aged carbonate core slabs altered from oil-wet to intermediate-wet as salinity decreased. And, the wettability changed from intermediate-wet to water-wet with decreasing salinity in presence of 1,000-ppm surfactant. Moreover, addition of small amount of surfactant alters the wettability of crude-aged or cleaned un-aged carbonate core slabs towards water-wet. The degree of water-wetness achieved by surfactant solution depends on salinity level.
Synergy and Emergence in Energy Policy Design
Authors: Blaskovich Frank 
Published: September 2014

Abstract
Effective energy policies should address the needs of all interested stakeholders. We used computer modeling to describe the interactions between energy production and economics. Policy solutions were based on regret analysis. Model results were generated for many possible futures to deal with uncertainties in future oil prices, producible oil reserves and maximum well rates, which were identified as the primary drivers of future revenues for both the state and producer in our model. We investigated the impacts of various tax and royalty policies (levers) individually as well as collectively. The results clearly define the limits of possible policies as well as those that might impact all stakeholders fairly. It was also clear that the best energy policy could not be predicted from the best solutions for each tax and royalty policy individually.
Our modeling approach can used to meet the needs of both the state and producer working together to find solutions that benefit all. It can also measure the relative benefits of existing energy policies and find ways to improve them.
This technique encourages the inclusion of many factors that are not normally studied in traditional approaches where production, economics and policy levers are treated separately. Our goal is to explore ways to improve the policymaker's ability to meet the needs of all stakeholders.
Our work shows that (1) even simple models can create unexpected policy results; (2) model synergy can have a great impact on results, and (3) regret analysis techniques can be very effective for defining policies. Except for our previous work, this type of policy exploration has not been reported in the petroleum literature.
Dynamic Behavior of a Multi-Layered Coal Seams Gas Reservoir in the Bowen Basin
Authors: Gouth F. , Belushko I. , Herwin H. 
Published: September 2014

Abstract
Fairview field is located in the Bowen Basin in South East Queensland and covers an area of approximately 1600 km2. It has been in production since 1994, from the 6 main coal seams of the Bandanna Formation. Presently, about 150 wells are on-stream feeding the domestic gas market. Further development is in progress to supply the Gladstone LNG plants on Curtis Island in 2015.
This paper focuses on a developed zone in the North of the field where extensive production and pressure data; more than 15 years, are available. The majority of the wells in the area are commingled and target the sweet spots with permeability ranging from tens to a few hundreds mDs.
Material balance analysis observed a typical layered reservoir behavior which is consistent with permeability discrepancies measured between seams. It also provided a comprehensive large scale calibration of the gas accumulation split between well connected and poorly connected areas. This split tightly controlled the gas production performance and recovery.
A strong permeability increase over reservoir pressure depletion was also identified after the two-phase flow production period. The magnitude was a 10 fold increase over 300 psi of depletion which is likely related to the well known coal shrinkage effect. This observation is consistent with previously published data from the San Juan Basin in the US. Within the high quality seams, this phenomenon had limited impact on long-term production recovery; however the impact on expected-ultimate-recovery (EUR) was more significant in the poorer seams.
These two phenomena show that permeability characterization, including its relationship with reservoir pressure depletion, is a key element for better production forecast.
Nanofluids Application for Heavy Oil Recovery
Authors: Alomair Osamah A. , Matar Khaled M. , Alsaeed Yousef H. 
Published: September 2014

Abstract
The application of nanotechnology in the oil industry has become a useful approach in oil production. The main objective of this study is to investigate the effects of nanofluids on the recovery of heavy crude oil compared to water flooding. The nanofluids are prepared by the addition of pure and mixed nanoparticles; Silicon oxide, Aluminum oxide, Nickel oxide, and Titanium oxide at different concentrations to the saline water. The prepared nanofluids were screened to determine the suitable type for the heavy oil and rock samples subjected to the study. The effects of nanofluids on the interfacial tension and emulsion viscosity were also investigated. Nanofluids flooding tests were performed on heavy oil sample of 17.45 API using Berea Sandstone core samples with an average air permeability of 184 mD, a liquid permeability of 60 mD, and a porosity of 20%. After selecting the recommended type of nanofluid, additional tests were performed including the effects on asphaltene precipitation using a flow assurance system. The experimental results show that, the Aluminum oxide nanofluid at a concentration of 0.05 wt.% reduced the emulsion viscosity by 25%. The mixed nanofluid of Silicon and Aluminum oxide at 0.05 wt.% showed the highest incremental oil recovery among the other nanofluids. This nanofluid is expected to be the best type of chemical flooding due to its performance under reservoir condition (high pressure, temperature, and water salinity) and its capability to oppose asphaltene precipitation.
History Matching CSG Production in the Surat Basin
Authors: Howell S. , Furniss J , Quammie K , Norman K , Erriah L 
Published: September 2014

Abstract
In 2009, QGC (a BG Group business) first planned to produce coal seam gas (CSG) in the Surat Basin as feedstock for a new Liquefied Natural Gas (LNG) plant. Subsurface models and associated field development plans were generated to underpin the investment case for the Queensland Curtis LNG (QCLNG) Project. This paper discusses history matching experience from QGC's Surat Basin reservoir simulation models, the challenges involved, and how these challenges have been overcome.
Similar to conventional reservoirs, full-field numerical simulation is necessary to accurately account for well interference and broader reservoir connectivity. Simulationalso fully integrates modelled 3D static property variations and honours the physics of multi-phase flow through porous media. CSG reservoirs possess unique characteristics which differ from conventional reservoirs and tend to increase the challenge of history matching. Some of these challenges include the physics of diffusive flow from the matrix into fractures that combines with relative permeability to create a more complex multi-phase flow problem. Another challenge is the requirement to de-water the coal before gas production commences and the associated stress dependency of coal properties. At the same time, the nature of CSG developments makes conventional history-matching approaches impractical given the large number of wells and the need for quick turnaround and fast-cycle decision making, especially during development ramp-up. These demands are set against a lean business environment where cost efficiency is paramount.
The properties of Walloon Subgroup (WSG) coals in the Surat Basin are unique compared to other CSG basin plays worldwide. The WSG is characterised by low to moderate coal rank, highly interbedded seams distributed through an extremely low permeability inter-burden, and highly variable coal permeability throughout the basin. Some of these differentiating properties of the WSG make history matching these reservoirs very challenging.
This paper presents guidelines for overcoming these challenges and history-matching CSG production in a dynamic simulation model of the Surat basin WSG. Handling of uncertainty is discussed to consider a range of possible history-matches for 345 wells with 9 years of production history. The history matching guidelines that have been developed are enabling a faster turnaround of model predictions, capturing key uncertainty parameters and informing field development decision-making.