bluuebunny/crossref_metadata_2025_split huggingface dataset:
Barrow Island Oil Field – A Case Study Into Mature Oil Field Management to Mitigate Low Oil Price Impacts
Authors: Goff Bree , Scott Michael , Mitisek Bryan 
Published: October 2016

Abstract
The Barrow Island Oil Field lies 56 kilometres off the north-west coast of Western Australia and has produced oil since 1965. The field is located on Barrow Island in a Class A Nature Reserve and currently produces around 5,000 barrels of oil per day from 468 oil producers and injects 80,000 barrels of water per day from 268 water injectors, which in the 2016 oil price environment creates some significant business challenges.
A change in the Operator’s asset leadership team coupled with a falling oil price environment through 2014 and 2015 provided an opportunity to change the way the asset was being managed.
Change was facilitated by two key factors: the new asset personnel brought new perspectives, experiences and skills to the asset and the falling oil price provided a case for urgency. These two factors resulted in an enhanced focus on business purpose, minimum business needs/work scope and execution focus.
Commencing in 2014, the Asset team developed a two year strategy with a clear mission to focus on the following key areas: Team focus to develop a strong sense of "we" and "together" to ensure delivery of asset strategies.Personal and process safety to protect our people, the asset and the environment.Cost management to ensure that all expenditures are owned and stewarded and the Opex curve is adjusted downwards.Production delivery by ensuring perfect execution (delivery of the expected outcome) of all activities that contribute to field operations thereby maximising volumes and revenue.
This paper focusses on the team, cost and production elements of that rejuvenated strategy.
Through focus on a clear set of business objectives the Asset Team has delivered a substantial change in the way the field is being managed, which has assisted in mitigating negative business impacts.
Integration of Subsurface and Surface Models to Evaluate Field Development Strategies for Three Australian Gas Fields
Authors: Sankararaj Rubakumar , Bracho Andres , Jagadip Priyanka , Mirzaee Farnoosh 
Published: October 2016

Abstract
The case study presented in this paper will demonstrate the efficiency of an integrated subsurface and surface model running numerous what-if scenarios in a timely manner. It will also compare the results and the time taken to run the same scenarios with current conventional methods of having separate subsurface and surface modelling packages.
Surface network configuration of a field depends on the field development strategies. As fields mature and reservoir conditions alter, these strategies change. This leads to changes in the configuration of the surface facilities, such as re-adjusting the facilities target rate, rerouting gas and products to different branches etc. Most of the current commercial Integrated Asset Modeling (IAM) tools, model reservoirs as a material balance tank. However, in cases of complex reservoirs, the material balance solution may not be able to model the full complexity in the behavior of the reservoirs. In such cases using a reservoir simulator to model the reservoir is a better option. Performance of the reservoirs depends on the pressure and capacity constraints of the facilities and also the configuration of the surface network. This demonstrates the importance of coupling a reservoir simulator and a network modeler to accommodate the changes to the surface network while accurately meeting the criteria of reservoir management. An integrated subsurface – surface model enables the user to evaluate the impact of changes in production policies while honoring all reservoir management constraints.
In this paper we present the results of a fully integrated gas planning system coupled with a reservoir simulator, for guiding field development. We defined multiple scenarios for bringing up gas from reservoirs, through the facilities and delivery point to meet the market demand. The case study deals with a market-based approach for modelling 3 gas-condensate reservoirs.
The unique, fully integrated reservoir to market approach we demonstrate in this study provides the ability to model and run scenarios against their complete gas network in a relatively very short time. In particular, the back-allocation from the market provides confidence in the ability to meet contractual sales obligations.
The Safety Transition
Authors: Saville Kirsten 
Published: October 2016

Abstract
Imagine you are standing on a mountain 2,400 metres (8,000 ft) above sea level surrounded by thick scrub in the highlands of Papua New Guinea. Your team of 500 employees consist of 70 percent of Papua New Guineans that form you base team to include HR, administration, equipment operators, and field trade skilled and unskilled tradesmen.
Your challenge? To perform both greenfield and brownfield operations across an unforgiving terrain, simultaneously keeping your team safe from all injuries from day one. A team – located quite literally above the rain clouds – providing EPC and maintenance services in support of major liquefied natural gas operations.
What a magnificent test for a company’s safety framework!
As the oil and gas industry continues its gravitation towards Asia Pacific, or seeks to release new investment for existing in-country operations, a true multi-level approach to safety is becoming an essential tool. While companies expect their employees – regardless of location – to perform duties without incident, many have yet to achieve a true safety culture that transcends borders and resonates with a global workforce.
This paper examines safety and safety leadership in Papua New Guinea; a truly challenging, potentially high risk environment. Wood Group details their intelligent safety management tool, the ‘Safety Cocoon’, rolled out across the business including large teams of Port Moresby and PNG highland employees.
Sand Control in Corrosive and Erosive Downhole Conditions at High Temperatures
Authors: Jackson S. R. , Gundemoni B. , Barth P. 
Published: October 2016

Abstract
In many sandstone reservoirs, the production of sand presents a major obstacle to well productivity. The petroleum industry spends millions of dollars each year to prevent and repair sand control problems including reduced production rates, sand bridging, erosion of equipment and sand disposal and removal.
Conventional Sand Screen Systems currently available on the market and manufactured mostly by service providers and are predominantly metallic in construction; these conventional screens have limitations on sustaining high downhole velocities resulting commonly in downole erosional failure and premature loss of downhole sand control. Erosional failure can commonly be associated in applications where high gas rate are anticipated. Commonly, these applications also combine with these higher gas rates, higher downhole temperature, pressure and sour well enviroments which magnify the corrosion-erosional issue with time.
Lower erosion resistance leads to premature failure of sand screen resulting in sand production and frequent workovers/intervention. A higher cost and deferred production ensues for the well owner. Worse still, wells with failed sand control can become marginal or uneconomical to produce at these lower rates. Sand production can at times result in operational failure of well control equipment resulting in a higher HS&E risk. Well intervention especially offshore/subsea provokes a higher risk and cost associated and should be avoided through competent technical specification of technology equipment suitable for these applicational environment.
If a material change from metal can be made to offer the resistance to erosional and corrosional failure, risk from loss of sand control and reduced economic return on well investment can be mitigated. Ceramic Sand Screen Systems which offer a material change where brought to the market in 2010 and offer a unique sand control solution which are ideal for such well conditions. Ceramics are more than 50 times harder than steel and are universal corrosion resistant to various acids and bases even at higher temperature.
This paper introduces the material change from metallic to ceramic technology, testings, and some successful field case studies.
The Optimisation Design of Buffer Vessel Based on Dynamic Balance for Liquid CO2 Fracturing
Authors: Meng Siwei , Liu He , Xu Jianguo , Duan Yongwei , Yang Qinghai , Yao Zixiu 
Published: October 2016

Abstract
In liquid CO2 fracturing, liquid CO2 is injected into reservoirs to crack open the formation, providing highly conductive paths for hydrocarbons. It's superior to water-based fracturing, because water is excluded during the whole process, resulting in formations free from water damage. Many field tests have been conducted in Jilin oilfield, with some problems exposed. The uncontrollability of fluid feeding due to the pressure difference among storage tanks, the liquid CO2 vaporization in low pressure fluid feeding stage, and the slow-dissolving of additives are three main issues.
To solve the above problems, a pressure-bearing inclosed tank is designed as the buffer vessel, which is placed between the liquid CO2 storage tanks and the boost pumps. Meanwhile, the additive adding system, which used to be located at the discharge connection of blender, is moved forward to the place near the discharge connection of the buffer vessel. A heat exchanger is added to the process too, to eliminate the vaporization. At last, a static mixer is installed after the blender.
During construction, liquid CO2 of different storage tanks is firstly driven into the buffer vessel, discharged into the boost pumps, mixed with the proppants in blenders, and at last subcooling using the heat exchanger before driven into the pumps. In this case, the pressure of low-pressure fluid feeding system become stable, the residual volume of liquid CO2 in a single tank is reduced, and the vaporization is eliminated. Meanwhile, the one-time storage of liquid CO2 is somewhat increased. After discharged from the buffer vessel, liquid CO2 is mixed with the additives immediately, which greatly prolongs the mixing time. The mixer also aids to the dissolving of additives. The additives dissolve in liquid CO2 earlier, thus the proppant-carrying capacity and friction property of fracturing fluid are greatly improved both in the surface pipeline and in the wellbore segment.
The technological process of liquid CO2 fracturing is adjusted, which realizes the optimization of fluid feeding system and additive adding system, improves the construction stability, and greatly enhances the stimulation effect.
Prevention of Water-Blocking Formation Damage in Gas Reservoirs Wettability Alteration, Analytical Modelling
Authors: Naik Saurabh , You Zhenjiang , Bedrikovetsky Pavel 
Published: October 2016

Abstract
Water blocking is a widespread formation damage mechanism in oil and gas reservoirs. The end effect on the well sand-face or fracture results in the creation of a water film which significantly reduces gas permeability. The removal of the water film by changing wettability near to the wellbore or hydraulic fracture is the traditional method of well stimulation. We describe inflow performance by two-phase steady-state flow towards well. The wettability affects the relative permeability and the capillary pressure. Treatment of the well neighbourhood by nanoparticles or surfactants results in a reservoir with non-uniform wettability. We present a steady-state solution for inflow performance and show how the alteration of the contact angle and the treatment depth affects the well productivity index. The model is verified by comparison with coreflood data. The developed analytical model can be used for the prediction of gas well productivity, and for the planning and design of wettability-alteration well-stimulation. The main result of the paper is the existence of the optimal contact angle.
Optimisation and Performance Evaluation of Liquid CO2 Fracturing Fluid Formulation System
Authors: Meng Siwei , Liu He , Xu Jianguo , Duan Yongwei , Yang Qinghai , Yao Zixiu 
Published: October 2016

Abstract
Liquid CO2 fracturing is an outstanding stimulation treatment for unconventional reservoirs. It has several advantages including high flowback, small damage in reservoir and outstanding stimulation effect. However, as liquid CO2 suffers from its low viscosity and high friction, many problems arise in liquid CO2 fracturing operations, such as high operating pressure, poor proppant-carrying capacity and high filtration loss.
Two kinds of additive systems are tested in the liquid CO2 fracturing operations in Jilin Oilfield. One system is a single fluoropolymer, while the other is composed by a surfactant thickener and another agent. Laboratory experiments show that both systems dissolve easily in liquid CO2 under construction conditions, and can enhance the viscosity to the level of slickwater. Two fluids are separately applied in tubing and casing fracturing cases. All treatments are conducted in neighboring blocks. The discharge, sand ratio and operating pressure are recorded, and then the proppant-carrying capacities and friction properties of two fluids are compared.
Results show that for tubing fracturing technique, two fluids perform similarly, with a discharge of 3.8m3/min, sand ratios around 5.5%, and average operating pressures range from 46 to 48 MPa. For casing fracturing technique, with a discharge of 7.9m3/min, the sand ratio and average operating pressure of construction using the first fluid is 6.4% and 21MPa, respectively. For the second fluid with a rate of 7.4m3/min, the two values are 6.2% and 23 MPa, respectively. Obviously, the first fluid system is superior to the second one under large discharge, since the sand-adding process is more stable and its friction loss is smaller. Considering that the proppant-carrying mechanism of liquid CO2 mainly depends on turbulence, the friction property is crucial. It is concluded that the first fluid is more suitable for liquid CO2 fracturing.
An applicable fluid system for liquid CO2 fracturing is selected via the comparison of field test performance. It could solve the problem of poor proppant-carrying capacity of liquid CO2 to some degree, which can greatly enhance the stimulation effect and expand the application scope of liquid CO2 fracturing.
Integrating Design of Experiments, Proxy Modeling, and Monte-Carlo Simulation for Combined Uncertainty Quantifications of Geological and Production Data in the Cyclic GAGD Process
Authors: Al-Mudhafar Watheq J. , Rao Dandina 
Published: October 2016

Abstract
Uncertainty assessment in reservoir simulation studies is a crucial issue to quantify future planning risks through the field development scenarios. The uncertainty comes from the lack and sparseness of geological and reservoir data that negatively affect capturing the most realistic geological environment for the reservoir flow simulation. Therefore, the uncertainty should be quantified for more plausible and convincible procedure to make a trustful decision regarding future production plans. In this paper, the uncertainty was quantified with respect to the geological and production parameters through the cyclic implementation of the Gas Assisted Gravity Drainage (GAGD) process in heterogeneous sandstone oil reservoir.
The geological uncertainty assessment includes generating multiple stochastic reservoir models for horizontal permeability and anisotropy ratio. In a successive step, the production uncertainty was assessed with regards to the decision parameters of the cyclic GAGD process simulation. The cyclic production parameters are durations of injection, soaking, and production in addition to the minimum bottom hole pressure in production wells.
To quantify the geological uncertainties, a large number of stochastic reservoir models (realizations) were created honoring geological constraints. Since it is impractical to simulate all these realizations, ranking was applied to select the nine quartiles of P10, P20, and P90 of permeability and anisotropy ration models that represent the overall reservoir uncertainty. The selected realizations were evaluated in the compositional reservoir model to calculate the field cumulative oil production. The full factorial design was implemented to produce 81 reservoir models to quantify the geological uncertainty. After that, the most likely reservoir model was adopted for the production data uncertainty assessment to determine the least uncertain space of the cyclic parameters that leads to true optimal solution. In the production uncertainty assessment, the proxy-based Box-Behnken Design and Monte-Carlo simulation approach was adopted to create and evaluate the training and validation jobs through the compositional reservoir simulation.
The presented successive uncertainty quantification workflow has led to obtain higher field flow response than the base case of default settings of the decision parameters. That was achieved after minimizing the uncertain space of the geological and production data that highly impact the cyclic GAGD process performance.
Improving GRV Estimations by a Streamlined Approach Capturing Structural Uncertainties When Updating an Existing Seismic Interpretation
Authors: Nasibullin R. , Willuweit M. , Yang W. 
Published: October 2016

Abstract
Recent developments in integrating seismic interpretation and geological modeling are aiming at removing common industry bottlenecks such as the often cumbersome updating process of existing models.
This paper will demonstrate a streamlined application of maintaining existing structural and hence geological, models live and with it improvements in risk analysis by applying flexible uncertainty assessment to such existing models without having to re-model the entire structure. This can be either local updates or applying uncertainty onto existing interpretations.
This approach of assessing seismic interpretation uncertainty is based on the uncertainty associated with an individual interpreted point and can be carried throughout a full modeling workflow. Such flexible uncertainty envelopes can be applied onto new seismic data or, in this case, onto an existing interpretation of structural elements for capturing and re-assessing structural uncertainty. Flexibility is present by a choice of applying this methodology either over the entire reservoir or to be used for local updates with locally improved interpretations.
In addition to capturing the structural uncertainty either during the interpretation or on updates of the interpretation, uncertainty in both the velocity model and the following time-to-depth conversion processes is a part of structural uncertainty.
The methodology is demonstrated on a seismic data set within the Taranaki basin of New Zealand. By applying flexible uncertainty envelopes on an existing horizon and fault interpretation and an associated structural geological model, this methodology utilizes the existing data and adds additional information delivering a range of GRV results instead of only a base case structural model with deterministically applied high and low cases. Having access to the flexible uncertainty provides access to a better understanding of volume ranges in the reservoir without having to decide on one single base case dependent on one interpreter's opinion.
The methodology has been applied incorporating all existing wells where the structural model was adjusted to the well pick position. The modified horizon remains within the uncertainty band.
The results show an updated integrated structural model with the benefit of this approach keeping the model consistent with a smooth existing workflow.
At a later stage, the uncertainty assessment can take property uncertainty into consideration and hence improve the in-place hydrocarbon volume ranges. This benefits risk assessment processes and can assist in improved field optimization and reservoir management decisions.
Ensuring Communication Across Software Systems
Authors: Ponsonby Miles , Mathisen Petter , Andersen Øystein 
Published: October 2016

Abstract
The amount of information generated when each well is drilled has increased in volume over the years. Integrating these different forms of information so they may be compared and used when planning new wells has become a challenge. Additionally there are different companies that capture the same data type but present it in different formats, adding to the communication complexity. There is the aded challenge of how to utilise old data that is not in the new formats, this data may be in the form or spreadsheet databases, word processor documents or sometimes in hard copy that cannot be searched electronically unless it is in good enough condition that it may be scanned and then Optical Character Recognition (OCR) may be used.
These challenges increase when companies take over assets from other companies that have used different software to capture their data. The company that has taken on the new asset must now take on new software if it wishes to analyse the well information that it has received. This requires the generation of new workflows or attempting to export information across different software systems, which can be very challenging.
Two approaches are available, either ensures that all companies work to a common format for the information, of use bridging software that can read all of the different types of data and then present it in a simple format that is makes the data usable.
This paper looks at the use of an overarching Data Management system that can accommodate many different forms of data and then present that in a format that allows the faster and more accurate quality control and decision making.
Identifying and Quantifying Risk in Well Abandonment Using Flow Charts and Probabilistic Planning
Authors: Ponsonby Miles , Mathisen Petter , Andersen Øystein 
Published: October 2016

Abstract
The use of a probabilistic estimation analysis system that applies Monte Carlo simulation techniques to generate a deeper understanding of the risks inherent in well operations. The software and the process associated with its application represent a step forward in providing operators with a tool for identifying, quantifying and managing risk.
A process flow map is generated that shows all the risks that have been addressed along the probabilities and options. This ensures that the team understands what they are addressing and all contingency materials services etc. are addressed. With a flexible process new information leads to a need for the steps to be easily added or adjusted. By producing reports to an industry standard spreadsheet that show all inputs and output information, there is no confusion as to what assumptions have been made, and they are all captured.
Whilst probabilistic estimation techniques are used routinely to characterise risks associated with geological and reservoir uncertainty, these techniques have not been routinely applied to well activities.
For many decision-makers, the traditional deterministic cost estimate has produced satisfactory results. However, in an increasingly competitive business environment, project decisions need to be made in a more informed manner for organisations to become "Best in Class". The application of a risk-weighted probabilistic cost and schedule estimation tool that can provide a comprehensive understanding of the time-cost risk spread in well abandonment projects represents a significant progression and can help provide detailed answers to the three basic questions in managing project costs: What is the likelihood of overrunning the project budget?What is the level of exposure associated with any overrun that may occur?Where do the individual risks lie that need to be mitigated against in order to avoid overrun?
If the risks can be mitigated, then the level of exposure can be reduced and projects can be delivered with greater budgetary certainty, conversely if the risk cannot be mitigated, how can it affect the total budget, and is it wise to carry through the operation?