bluuebunny/crossref_metadata_2025 huggingface dataset:
An Integrated Approach for Fracturing Evaluation and Optimization using Rate-transient Analysis and Dynamic Drainage Volume
Authors: Yuan Bin , Moghanloo Rouzbeh Ghanbarnezhad , Wang Kai , Zheng Da , Li Jin
Published: October 2016

This study presents an integrated approach to evaluate and optimize the efficiency of fracturing stimulation using early production data in Niobrara shale oil play. The proposed integrated method adopts an analytical equation of dynamic drainage volume (DDV) into the weak (integral) form of mass balance equation for long-term transient problem with moving boundaries. Multiple factors controlling the propagation of DDV and production data analysis have been considered, including: fluids and rock compressibility, stress-dependent reservoir permeability, diffusivity difference within both stimulated-reservoir volume (SRV) and unstimulated reservoirs, fracture-cluster length and spacing.

The size of DDV and associated average reservoir pressure, recovery factor (RF), and phase saturation (oil/gas/water) are calculated. The half-length of primary fractures and diffusivity within SRV are considered through a correlation; moreover, the ultimate drainage volume (used to estimate ultimate recovery, EUR) can be approximated at condition, using the proposed method.

The results suggest a better method compared to existing IPR models to characterize the well performance. Plotting the ultimate drainage volume calculated for each well as a function of fracture spacing of the same well, the wells were grouped into distinct groups in terms of performance. Next, the different characteristics of DDV obtained from previous steps are used to determine the optimal fracture spacing for the case study used here.

In practice, this method can be used by providing additional insights required to determine the optimal fracture spacing. Some of the features of the proposed method is as follows: (1) capability to ascertain DDV, associated average reservoir pressure, and thus recovery factor while accounting for compressible of fluid and rock, and multi-phase flow; 2) simplicity and efficiency: it does not require comprehensive inputs (including early production data) and yet can estimate the necessary design parameters for multistage fractured horizontal wells (MFHW).
Code of Practice for the Construction and Abandonment of Petroleum Wells in Queensland - As Mandatory Safety Requirements
Authors: Lee Peter , Porter Mika , Maggiori David
Published: October 2016

Objectives/Scope: In Queensland, petroleum safety legislation is enforced by the Petroleum and Gas Inspectorate. Onshore petroleum well integrity is fundamental to ensuring sustainable production, and ensuring safety outcomes and protection of aquifers during the well life cycle.

Methods, Procedures, Process: This Code of Practice has been developed to help ensure that all onshore petroleum wells are constructed and abandoned to a minimum acceptable standard resulting in long term well integrity, containment of petroleum and the protection of aquifers. This Code identifies industry standards and good oilfield practice for oil and gas well design.

Results, Observations, Conclusions: This Code addresses safety and environmental issues in the construction and abandonment (decommissioning) of petroleum wells and associated bores. This Code provides a way for petroleum tenure holders to comply with their obligations under the onshore Petroleum and Gas legislation in Queensland Australia.

Novel/Additive Information: This Code is designed to complement the petroleum operator's own internal risk assessment processes, operating standards and procedures by outlining a recommended process to ensure that: the environment and aquifer systems are protected;risk to the public and workers is managed to a level as low as reasonably practicable;regulatory and applicable Australian and international standards and requirements, as well as the petroleum tenure holder's standards, are understood and implemented where appropriate; andthe life of a petroleum well or associated bore is managed effectively through appropriate design and construction techniques and ongoing well integrity monitoring.
Field Trial Analyzing of Rodless PCP Technology: Problems, Improvements and Results
Authors: Zhongxian Hao , Peng Huang , Shijia Zhu , Lixin Zhang , Dianfeng Liu , Cai L..
Published: October 2016

Currently, rod-tubing wear and suck rod failure are two serious problems in many oil fields in China. Because of the problem, in some area, the average mean-time-between-failure is only 200 days. The workover costs lots of money, not including the loss of oil production. In view of the low daily output situation of CNPC, problems have not been solved effectively until the development of the innovative ESPCP system.

A permanent magnet synchronous motor (PMSM) was developed and deployed in the bottom of the system, allowing adjusting the rotation speed between 50-500 rpm, which could satisfy the requirement of the PCP. The system included a motor protector, a cardan joint and a PCP from bottom to top.

In the initial field trial, we met many problems, such as the motor protector didn’t work suddenly, the shaft of the cardan joint broken, the system couldn’t run because of the tubing full of heavy oil. According to the specific problem, we improved the design of some components.

More than 10 systems have been deployed and the longest working life is over one year. The system saves 20% energy in average comparing with the pumping unit. It results in fewer operations and reducing the total cost of ownership. The configuration reduces the surface footprint and environmental impact of the oil field. It also reduces deployment and workover and results in fewer and safer operations.

This paper presents some problems and improvements of the system, and analyzes the advantages of the technology.
An Improved Grid Generation Approach for Discrete Fracture Network Modelling Using Line Fracture Concept for Two-Phase Flow Simulation
Authors: Wang Keke , Peng Xiaolong , Du Zhimin , Haghighi Manicher , Yu Lu
Published: October 2016

In traditional Discrete Fracture Network (DFN) method for fractured porous media simulation, fractures are modelled in different scales and orientations using single computational grid. However, a large number of small grids near both ends of fracture are generated, which substantially reduce the computation efficiency. In this paper, a new line fracture approach is presented to avoid generation of small grids. Combined with Multi-Point Flux Approximation (MPFA) algorithm, the simulation efficiency is highly improved without losing accuracy.

We present a modified mesh generation algorithm in which the volume of large fractures is set zero by neglecting the fracture width. The fracture aperture (very short line) is treated as single node during mesh generation using the paving method. Therefore, the number of small grids around the fracture is significantly decreased. In this paper, a quadrilateral unstructured grid system is generated using the proposed paving method. Then, by taking the median dual of quadrilateral mesh as the control volume, all fracture properties such as the aperture and permeability are accounted for as independent parameters in discrete fractures. The governing equations of DFN model are derived and solved using MPFA algorithm for oil-water two-phase flow.

A new discrete fracture network model using line fracture approach is developed. To show the efficiency and accuracy of the new model, the proposed method is applied to a case study of two separated and two crossed fractures, in the computation domain with the scale of 50 by 50 meters. Compared with the standard DFN model including the width of fractures, the computation efficiency of the new model is highly improved (by 2.5 times), due to the large reduction of grid numbers (20%). Good agreement in water and oil saturation distributions resulted from the two models validates the newly developed method.

Simulation of naturally fractured reservoirs has been a challenge for decades. Discrete fracture network modelling is a promising approach. However, without an efficient grid generation method, DFN model is not feasible and practical due to the large amount of computational time. The novelty of the present work is the improved model using line fracture approach. The new grid generation algorithm is coupled with multi-point flux approximation approach for flow simulation in fracture network system. High efficiency and accuracy of the developed method is readily applied to fractured reservoir simulation.

Sponsored by NSFC (Natural Science Fund of China - "the numerical simulation of natural fractured reservoir based on the unstructured hexahedral grid system and concurrent computation") (No. 51474179)
Field Scale Co-Optimisation of CO2 Enhanced Oil Recovery and Storage Through Swag Injection Using Laboratory Estimated Relative Permeabilities
Authors: Kamali Fatemeh , Hussain Furqan
Published: October 2016

Numerical simulations are widely used to investigate the performance of simultaneous water and gas (SWAG) injection in the field scale. However, they usually use two-phase water and gas relative permeability functions (kr) and one of the existing correlations (e.g., Stone, Baker) to calculate oil relative permeability in a three-phase displacement. Moreover, the same krg is used for all SWAG injections at different miscibility conditions and fraction of gas injected (FGI).

The recent experimental work has shown that gas relative permeability functions in three-phase SWAG are significantly different from the conventionally used two-phase functions. This paper presents a field scale simulation study to investigate the co-optimization of CO2 storage and EOR using experimentally estimated gas relative permeability functions.

A three-dimensional, layered reservoir model initially saturated with oil phase and connate water is used to examine different injection schemes for co-optimizing oil recovery and CO2 storage efficiency. A mixture of hexane and decane (0.65 and 0.35 mole fraction hexane and decane, respectively) is used for the oil phase. Numerical simulations are run at 70°C and three different pressures (1300, 1700 and 2100 psi) to represent immiscible, near-miscible and miscible displacements for the given fluids. A FGI of 0.5 is used for SWAG displacements run at immiscible, near-miscible and miscible displacements. Then the effect of FGI dependent relative permeability on co-optimization of CO2 storage and EOR is investigated in the near-miscible condition for FGI values equal to 0.25, 0.5, 0.75 and 1.0.

The field scale simulation results, run using experimentally estimated three-phase gas relative permeability are compared with the results when two-phase gas relative permeability is used. The numerical simulation results show that oil recovery rate is underestimated if two-phase relative permeability is used. This effect is more prominent in near-miscible and miscible displacements than immiscible. CO2 storage efficiency and therefore co-optimization function is significantly increased when estimated three-phase gas relative permeability functions are used. Therefore, the accurate description of co-optimization of CO2 storage and EOR in SWAG requires laboratory estimated three-phase relative permeability functions.
The Downhole Transmission Characteristics of Vibration Waves — An Experimental Study in the Daqing Oil Field
Authors: Jiaqing Yu , Lichen Zhen , Fuchao Sun , Zhenkun Zhu , Xiaohan Pei , He Liu
Published: October 2016

The downhole communication is the key technology of reservoir exploitation and downhole remote control. The vibration wave communication method provides a new way for the downhole data transmission. Using this method, control commands can be modulated and transmitted through the tubing or casing by the vibration wave. To analyzing the downhole transmission characteristics of vibration waves, a field test was implemented in the Daqing oil field. The vibration signal generator, located on the wellhead, can convert the electricity into the vibration wave by using the magnetostrictive material. The vibration wave signal is transmitted through the casing. To receive and test the signal, a signal detection device is developed. The signal detection device can be fixed on the casing firmly at any depth by a motor-activated-ram mechanism. A cable is plugged into the signal detection device, with which the detected vibration wave signals and the decoded signals can be transferred to the computer on the ground. By analyzing the received signals, the following conclusions are drawn: (1) At the depth of 900 meters, the vibration wave signal can be received and decoded correctly, which verifies the feasibility of the vibration wave downhole communication method. (2) Detection failure of vibration waves of certain frequencies occurs at specific depths. This phenomenon proves the characteristic of alternating passband and stopband in vibration wave transmission, which also validates the reliability of the multi-fundamental-frequency transmission strategy. (3) The attenuation characteristic of the vibration wave is obtained. With its low cost, convenient operation and high reliability, the vibration wave downhole communication technology can be widely used in hydraulic fracturing, water flooding and zonal production.
An Investigation on the Optimal Definition of Projects Scope, Facilities Sizing and Design Life for Truly Sustainable Deepwater Field Development: Technical Aspects and Economic Considerations
Authors: Beltrami Francesco , Gifford Andrew , Basu Shiladitya , Berardi Andre'
Published: October 2016

Notwithstanding the great technical changes that occurred in the offshore industry over the past decades, and the undeniable success of the subsea technologies, deepwater project sanction appears to remain rooted in traditional CAPEX minimization and NPV maximization. This paper investigates how decisions made by reservoir evaluation, and drilling and completion planning affect the design of subsea production systems and, in turn, the design of production hosts. Challenging the current approach to project framing and definition, practical alternatives are explored with a conceptual case study designed to test the ideas here presented.

Deepwater production is expected to play a significant role in meeting the future oil and gas demand of the world. To do so, new fields need to be developed in challenging environmental conditions, and existing fields will undergo brownfield modifications to sustain acceptable production levels. OPEX will reflect the increasing costs for inspection, maintenance and repair. Rethinking the requirements of deepwater field development will help to define the proper size of the subsea and surface facilities, the optimal design life and the possible need for staged developments.

A case study has been created to observe how changes in facility size, design life and development time-line (stages) result in changes to the overall subsea CAPEX and OPEX. These costs have been discussed with respect to drilling and completion costs and host facilities costs to identify possible opportunities and criticalities. Given the possibility of protracted low oil price environment, new ways of developing deepwater fields is worth considering. Greater integration of the various disciplines (subsurface, subsea, topsides, platforms, etc.) involved is also suggested in order to maximize the project objectives.

Abundant scientific literature exists on deepwater field development, but limited information appears to be available on the optimal definition of project scope, facilities sizing and design life for a deepwater project that aims to be profitable and sustainable long term. This paper is a contribution to a wider discussion that the industry needs to have on the way deepwater projects are conceived, planned and executed.
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

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

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

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

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

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

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

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

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

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

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

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?
The Importance of Collaboration, Integration, and Relational Database Management for Vast Corporate Data: A Case Study in Indonesian National Oil Company
Authors: Susanto Adeline , Satria Andrean , Octora Ade Veria , Desiani Nora , Alam Nur , Yulisasongko Freddy
Published: October 2016

The asset management of an Indonesia's national oil company (NOC) has become complex and challenging because every field acquisition and takeover becomes a new asset (subsidiary). Challenges, such as standard corporate database (e.g., cataloguing), seamless workflow in retrieving massive data, data retention ability, and cartographic reprojection lead to a need for data management optimization and integration, which needs to be securely and reliably managed.

The smart vision methodology migrates architecture from an existing system to a new integrated system. The workflow consists of steps designed to gather information, engage the customer in a collaborative manner, and assemble opportunities into an orderly plan that has strategic alignment and cost-benefit justifications for each case. The approach used by the company refers to the professional petroleum data management (PPDM) data model, which helps move collaboration, integration, and relational database management forward. Deployment of this model results in the standardization of a corporate database. As such, previous different data configurations have a standard cataloguing system, which results in consistent data retrieval.

The smart vision methodology is applied to capture and study the company's existing architecture. A major finding is tremendous data from each of its subsidiaries have their own standards and contain structured and unstructured data, which makes it troublesome for analysis to further determine best business decisions. History data, data retention, and data permission management are arduous and implausible. Distortion of cartographic projection data makes the data nonscalable. To overcome these challenges, the PPDM data model is deployed. Data mapping was performed on 18 of the NOC's subsidiaries' data. Company preference, policies, and regulations are standardized at the corporate level. As a result, an integrated database is being established. Corporate can observe all assets in a single project database, which allows further technical analysis and eliminates data duplication problems, making the data easy to manage. From a user management point of view, the presence of the interpreter source priority (ISP) concept allows user collaboration without disrupting either corporate data or other user's interpretation. Another result is the user's ability to track historical data. This is important for corporate; thereby, users can access not only interpretations results but also other users' knowledge content.

The deployment of this model provides the ability to manage all the seismic, well, and interpretation-related data into one consolidated project regionally in a scalable geographical area and complexity. This allows the company to perform various analytics processes related to all data owned by the company.
Hybrid Downhole Microseismic and Microdeformation Monitoring of a Vertical Coal Seam Gas Well
Authors: Durant R. , Francis T. , Braikenridge R. L. , Roy M.
Published: October 2016

The operator’s exploration of natural gas in coal seams within the Gloucester Basin, New South Wales (NSW), Australia presents technical challenges accessing and producing the gas economically while meeting stringent environmental standards. These standards are more stringent than those applied to petroleum exploration and production in other states of Australia. This paper presents hybrid downhole microseismic and microdeformation monitoring technologies applied in a vertical CSG well.

The Gloucester Basin is an area of complex geology with high horizontal stresses, some faulting/compartmentalization, dipping bedding planes, and multiple thin bands of coal strung out over hundreds of meters. Regulations have all but stopped some companies exploring for CSG in NSW. This is despite large identified petroleum reserves, importation of gas from interstate to supply the local market, and a NSW chief scientist and engineer report stating CSG carries risks no greater than any other of the extractive industries and that those risks are manageable (O’Kane 2014).

Providing confidence that hydraulic fracture geometries are relatively confined to target coal seams and do not grow upward into beneficial groundwater aquifers is a primary concern. A hybrid downhole microseismic and microdeformation array was deployed to monitor fracture stimulation of a vertical CSG exploration well at Gloucester to provide more accurate insight into overall fracture height coverage. Downhole microseismic and microdeformation technologies complement one another by providing unique, far-field determinations of hydraulic fracture geometry. This is one of the first times downhole tiltmeters have been used to monitor microdeformation caused by hydraulic fracturing of a CSG vertical well in Australia and the first time either technology has been used in NSW. Results from work performed in November 2014 show relatively confined fracture height growth with good agreement between microseismic and microdeformation data. Low microseismic event magnitudes (-3.9 to -2.1 Mw) recorded indicate no interaction with faulting in proximity to the target well. In addition to a vertical fracture component, microdeformation data indicated presence of steeply dipping fracture components on all zones. This data, combined with high fracture gradients (well above overburden) observed with each stage, and increasing in shallow intervals, confirmed the prediction of complex fractures, especially for fracture zones shallower than 600 m.

Hybrid diagnostic results confirmed the 1D mechanical earth model (MEM) built for the target area and both fracture complexity and main fracture azimuth were generally as predicted. The complex nature of the fracture propagation prevents uncontrolled vertical growth, which gives confidence that hydraulic fractures are not growing into the vicinity of shallow beneficial aquifers.
A Review of Recent Safety Research Activities on LNG Operation
Authors: Shahri Hamid Reza , MahdaviNejad Ramezan Ali , Abedini Sanam
Published: October 2016

Since LNG (Liquefied Natural Gas) is a combustible cryogenic liquid and as such presents specific safety hazards, the safety of LNG utilization has become an issue that requires a comprehensive study on the risks. Hence, various safety aspects connected with the operation of LNG need to be analyzed. The purpose of this paper is to review recent researchers' LNG safety studies and analysis. Specific safety characteristics of the equipment involved are incorporated in the analysis. The analysis of important risks show that at pressures near atmospheric, the hazards of LNG are comparable to those of conventional liquid fuels such as gasoline. At higher pressures, it behaves more like a combustible gas liquefied by compression. Also reviewed in this paper is the state of the art in modeling important LNG Hazards (like pool and vapor fires modeling). Totally, this paper identifies different possible risks in and out LNG plants and describes the results obtained from modeling of identified issues.