bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pump-Out Stage Tool and Pump-Out Float Collar System Enhances Completion Efficiency in Queensland Coal-Seam Gas Project: A Case Study
Authors: Zaman Mohammad , Dunn Timothy , Tickoo Sandeep 
Published: October 2018

Abstract
This case study highlights the field-trial of a pump-out stage tool, pump-out float collar, and the annular casing packer. These technologies were integral to drilling and completing wells in the Santos coal-seam gas (CSG) development of the Roma field in the Surat Basin of southeast Queensland.
Pump-out systems—which allow a primary cementing job to be performed above a slotted casing string using a pump-out stage tool, annular casing packer, and pump-out float equipment—eliminate the need for drill out operations. Once the casing is landed, a ball is deployed from surface to actuate the inflation of an annular casing packer below the stage tool and above the slotted casing. A second ball is deployed to shear and shift a sleeve to open the stage tool and begin the primary cement job. Once complete, a cementing wiper plug is released from surface and pumped behind the cement slurry to shift the stage tool into the closed position. The internal pump-out casing components are displaced to the bottom of the well and require no further intervention.
This case history includes results of the initial field-trial runs and technical details on well configurations, slotted liner placement across the coal-bed intervals, pressure charts, cement-job data, shear information on the ball seat, detail on the stage-tool operation, pumping out the float collar, and displacement of the internal equipment downhole. These jobs planned to eliminate the need to run a dedicated drillout trip during initial completion and also the need to change out the pipe rams in the blowout preventer (BOP).
Ultimately, the pump-out system provides a full-bore casing geometry with no internal restrictions and is expected to reduce completion costs by 15%.
Injectivity and Well Deliverability Test and Analysis in an Offshore Complex High CO2 Gas Carbonate Asset
Authors: Masoudi Rahim , Abd. Wahab Muhammad Afiq , Motaei Eghbal , Ataei Abdolrahim 
Published: October 2018

Abstract
Among the key uncertainties and risks as part of development of a high CO2 offshore gas carbonate field; production well deliverability, produced CO2 management, and cap rock integrity have been identified as potential techno-commercial showstoppers that need further appraisal and studies. CO2 storage and sequestration in the aquifer of the same field was identified as the most feasible and economic option for the Produced CO2 management and hence the injectivity within the targeted intervals and aquifer become part of the appraisal and study scope.
An extensive over 200 m coring program covering various intervals including overburden, caprock, carbonate hydrocarbon intervals and aquifer has been designed as part of data acquisition and surveillance plan. The main plan scope were designed as:To establish reservoir properties & characterizationTo measure formation pressure and acquire fluid sampleTo establish reservoir injectivity and productivity at the prospective intervalsTo acquire data for flow assurance analysis, facilities design and well material selection studies for development planning.
The test and analysis has been successfully conducted covering the intended scope of the plan. Based on the Well test and PTA, the reservoir permeability is calculated and is more or less aligned with the core permeability with the total high skin which the majority comes from geometrical/limited-entry skin. The productivity index is calculated to be 21 STB/day/psi. There is difficulty to analyze the Injectivity test due to non-isothermal effects during injection and fall-off test where the fluid property of both injected water and reservoir water is a function of temperature and time. An approximate method is applied using the average temperature during the fall-off to simplify the case by considering a constant fluid property. Injectivity Index is estimated from rate and pressure data to be around 26 STB/day/psi. However, it declined by time to reach a value close to 13 STB/day/psi. In the second test, Based on pressure transient analysis the homogeneous, vertical well with limited entry, and infinite boundary model with underneath aquifer was accepted as representative for S2 reservoir. To capture the non-Darcy effect, the rate dependent skin model is selected. Non-Darcy coefficient is extracted from well model for IRP in well model (1.0073E-4 (Mscf/day)-1.
Generally, the well test and injectivity and productivity analysis objectives are achieved as the fluid type is also confirmed. The paper will detail out the actual test results, methodology and evaluation approaches in this surveillance plan.
A Priori Scenario Modelling with LWD Seismic for Successful Well Placement
Authors: Tan Aaron , Lee Bor Seng , Van Voorst Vader Herman , Holleman Nico , Spiteri Richard , Ahmed Aqil , Maula Fahdi , Shamsuddin Shanaz , Heng Elijah 
Published: October 2018

Abstract
A Vertical Seismic Profile acquired while drilling and which utilized an a priori velocity model template to facilitate accurate well landing in a constrained drilling section is presented. The results were compared to original predictions based on surface seismic and actual formation depths taken from log data.
The approach used actual checkshot velocities acquired in real time using VSP lookahead imaging while drilling to reduce spatial and depth uncertainty. Projections ahead of the well landing utilized the checkshot data to perturb the a priori velocity templates in real time. It was also complemented by the borehole seismic image to check for sub-seismic faults and alternate interpretations. Based on these projections, trajectory corrections were made to optimize landing the well in a key reservoir sand. Initiating early directional changes were critical to land on a short, directionally-constrained open-hole section whilst ensuring the section was within the targeted fault block.
A comparison of the actual wellbore velocities against the predrill scenarios is provided along with corresponding vertical depth predictions. Lateral constraint was provided by the correlations of the VSP with the surface seismic image at key stages while drilling. Mapping of the drilling data to the velocity templates showed a deep case scenario for well placement. Details of the two resultant trajectory changes initiated after 2 and 5 stands of drilling respectively are explained. The approach allowed for accurate well placement, reducing depth uncertainty from 60-100 ft. predrill to within 5 ft from final while drilling prediction to actual depth. Final depth confirmation utilized Gamma Ray and Resistivity at Bit Inclination (GABI and RABI) for the key sand. The sand was found to be 18 ft. deeper than initially expected based on the pre-drill model. This method saved the drillers a potential side track.
Conventional Electromagnetic well placement techniques can be limited in short open-hole sections where early time information is required to facilitate trajectory changes to allow for correct spatial landings. By using VSP while drilling in conjunction with a priori modelling, data can be acquired early enough to successfully, address this challenge.
Facility Operations Readiness and Project Start-Up Support and Integration
Authors: Maher Michael 
Published: October 2018

Abstract
The Australia Pacific LNG (APLNG) Downstream Project comprised construction of a two-train LNG plant, two 160,000 m3 LNG storage tanks, a LNG loading jetty, and associated infrastructure on Curtis Island, near Gladstone, Queensland. The facility utilises ConocoPhillips’ proprietary Optimized Cascade ® process to liquefy natural gas. Project planning began in 2008 and construction commenced in 2011. LNG production from Train 1 began in December 2015 and Train 2 came on line in October 2016. In August 2017, the final 90-day two-train lenders test was successfully concluded and included an operational component in which the LNG Facility operated at ten per cent above nameplate capacity for the 90-day period. This successful outcome was achieved through collaboration, integration and robust execution plans by the APLNG Operations, APLNG Project, ConocoPhillips LNG Technology and Licensing and Commissioning and Start-up work teams. In an effective strategy to support the drive to APLNG first cargo, the combined teams formed a fully Integrated Completions Team in 2015. This team worked together enabling rapid development of the operations workforce capability and resulted in both trains achieving performance tests at first attempt.
The APLNG Project operability assurance and operations readiness program commenced with a collaborative workshop, attended by Operations, Projects and Commissioning and Start-up representatives. A focus on high collaboration and integration between the teams backed by ConocoPhillips’ Operability Assurance (OA) and Operations Readiness (OR) principles identified 370 critical business deliverables. Learnings were leveraged from across ConocoPhillips assets (including Darwin LNG) as they pertained to readiness best practice. APLNG Readiness Assurance guidance was established to create specific functional readiness trackers to measure every action supporting the 370 deliverables. A simple and effective tool was developed and supported by robust monthly review forums where each action was tracked and rolled up to S-Curves. These deliverables translated to over 7,000 unique line items tracked over the entirety of the readiness implementation. This work was leveraged by the Integrated Completions Team which implemented robust lessons learned from Train 1 to realize immediate results, delivering a 33% reduction in the Train 2 start-up schedule.
The combined efforts of the teams delivered two highly operational trains within the 2016 calendar year resulting in the production of additional cargoes. The successful execution and implementation of OA/OR principles combined with strong integration of APLNG Operations into the APLNG Project phase laid the foundation for exceptional first year operational and production performance. This meant the APLNG Operations Team moved from a newly formed team to a high functioning and critically evolving team in support of the APLNG Downstream LNG Facility.
Integrated Modelling Workflow for Life Cycle Development of a Large Scale Coal Seam Gas Field
Authors: Sharma Vikram , Davies Josh , Vella Benjamin , Jiang Jesscia , Sugiarto Isan , Mazumder Saikat 
Published: October 2018

Abstract
Development of coal seam gas fields is conceptually simple but complexity arises with: the stochastic nature of coal reservoirscontinually changing work scopethe large number of wells required to meet gas contracts.
In the current environment, the cost of developing thousands of wells and hundreds of kilometres of associated gathering is a key driver to the success or failure of CSG projects. Continuous reduction in cost/funding with limited resources drives companies to derive an integrated approach to the field development.
Subsurface models now form an integral part of production forecasting and decision making. Companies have benefited from the computation technological advances in the recent past, whereby it is possible to run large-scale models in a reasonable timeframe. Several tools and approaches are available today to integrate complex 3D reservoir models with surface networks to generate an integrated production forecast. In this paper we focus on using advanced geospatial applications with integrated system models to derive a development concept which is optimal, realistic and capable of adapting to changes in work scope as the development progresses. Gathering routes and associated material take off (MTO) points are generated in geographic information system (GIS) tools, using constraints and criteria such as: access and approvalssub-surface data (scope of recovery maps, net coal and permeability)maximum use of existing infrastructure (Roads, Tracks, etc.)environmental constraints (overland flow, vegetation, etc.)well spacing.
Seamless integration of GIS tools and sub-surface modeling tools is what makes this workflow unique. GIS tools acts as a key integrator, forcing different disciplines and departments to work together in a common platform. It also functions as a common database used across an entire organisation. GIS toolbox gives a significant head-start to the project by first defining what is achievable. It is then finessed with the best value sub-surface outcome and a final forecast is derived in a significantly shorter time scale. With the approach presented in this paper, the forecasting cycle, involving full economic run, is substantially reduced– from several months to just weeks, if not days. The final outcome is an achievable well sequence which is derived along a realistic gathering route. With this, the MTO and the production forecasts are aligned and the associated costs can be easily traced to source. This workflow is automated and can be easily repeated if scope or project premise changes. Last but not least, this approach can be applied to any onshore unconventional or conventional plays.
Successful Hydraulic Fracturing Optimisation in KS Field through Fracture Height Growth Identification and Mitigation
Authors: Kamal Hamzah , Noke Fajar Prakoso , Geraldus Yudhanto , Luciana Soetikno , Ricki Daniel Marbun , Reza Vitali , Areiyando Makmun , Apollinaris Stefanus Leo Anis 
Published: October 2018

Abstract
Hydraulic fracturing in the tight sandstone of the KS Field has been implemented in more than 200 wells since 2002. Year by year, it gets more challenging due to limited well candidates with good properties and a decreasing trend in production result. Thus, hydraulic fracturing optimization both in design and execution are critical to increase success ratio and to contribute more oil production. One of the efforts is delivering fit-to-purpose design through fracture height growth identification and mitigation.
A mechanical earth model (MEM) is constructed to obtain elastic properties and stress profile as an input for fracture geometry simulation as a preliminary tool for height growth prediction. The MEM is generated using triple combo and sonic logs and validated with wellbore stability analysis. A pre-treatment mini-frac was performed and analyzed before the main fracturing operation to calibrate and update the MEM stress profile. For final validation, the profiles of MEM, MEM optimized fracture simulation and temperature log results are compared to evaluate the fracture height growth issue. Last, fit-for-purpose strategies are applied to optimize the fracture geometry result and maximize oil production.
Previously, hydraulic fracturing with high proppant volume has been used to create long fracture half-length providing large reservoir contact and thus improved productivity. Unfortunately, production after fracturing in some wells shows no significant change and occasionally yields high water cut. Currently, detailed pre-fracturing evaluation is applied. Comparison plot results show fracture growth consistency between the MEM-optimized hydraulic fracturing simulation with temperature log profiles, validating the suspicion of fracture height growth to and through the upper and lower barriers of the fracturing target.
Two design changes were then proposed to control fracture height growth: Applying lower-viscosity fracturing fluid by decreasing gel loading or changing to viscoelastic surfactant fluid; and applying an artificial barrier technique. These changes are designed to reduce fracture height growth and increase effective fracture half-length in the pay zone. The result is increasing fracturing success ratio, from 40% to 70%, which contributes to arresting the production decline of the KS Field.
Integrating geomechanics analysis (in the form of MEM) into hydraulic fracturing design simulation and profile comparison, MEM-optimized hydraulic fracturing simulation and temperature logs have validated the issue of fracture height growth problems in the KS Field and justified the application of fit-for-purpose strategies to mitigate the issue.
Integrated Operations for Gas Lift Optimization: A Successful Story at Peninsular Malaysia Field
Authors: Anuar Wan Mohamad , Badawy Khaled , Bakar Khairul Azhar , Aznam Mohd Razik , Salahuddin Siti Nur , Mail Morris , Bakar Afdzal Hizamal , Trivedi Rajesh , Tri Nghia Vo 
Published: October 2018

Abstract
Gas Lift Optimization solutions have improved significantly over the past decades with the introduction of Integrated Operation (IO) in the Oil and Gas industry.
Big fields that consist of hundreds of strings, gas lift injection system, water/gas injection system and complex surface facilities (compressors, pumps, choke and valve, etc.) could establish numerous cases from different scenarios to identify production bottlenecks via simulated network models.
Using available tools, the user could model the full production system including well, surface network, reservoir, gas/water injection models, gas lift injection networks and process plants to identify bottlenecks and opportunities for optimization. The model is updated continuously using live data feed and automated technical workflow to establish an end to end solution in providing various optimization scenarios e.g. Gas Lift Optimization.
This paper discusses how the methodology works and reviews the results of gas lift optimization from four platforms consisting of over 200 strings of which 95% are gas lifted, operated using a new approach that includes live link to field data, integrated model management, and automated technical workflows to identify potential strings and gas lift supply facilities for production enhancement. This paper reviews the setup required to ensure all the necessary inputs are aligned to publish the desired outcome.
The approach has resulted in prevention of 480bopd potential deferment at platform level that can be further improved with future field implementation. In addition to gas lift optimization, the workflows have potential to expand to other business needs such as defining an accurate gas demand requirement, determining daily liquid or sand production limitation identifying underperforming wells, optimizing choke configuration, studying the feasibility of low pressure system, water treatment system, and condensate recovery system.
This paper should be of interest to those who are planning to implement Integrated Operations to their field with the aim in maximizing its value. It will provide information on the requirements, challenges, ways to overcome, and effective approach during the implementation.
An Efficient Approach for History-Matching Coal Seam Gas CSG Wells Production
Authors: Chang Gladys , Gizat Aibassov 
Published: October 2018

Abstract
QGC's current full-field reservoir model comprises hundreds to thousands of CSG wells. This presents a considerable challenge from a history-matching standpoint compared to a conventional workflow where well-level adjustments may be made on one well at a time. In QGC, a model with an improved well-level match is desired as the resulting well forecast will enable decisions on a well-level to be made more confidently, such as the prioritization of well workovers. Previously a field-level history-match was deemed acceptable when the model was only used for field development planning.
The method parameterizes the well-level relative error in simulated production from the model versus observed production. The workflow utilizes this data, known as well-level modifiers, to alter subsurface properties. This has been achieved with a semi-automated workflow to make the process efficient and repeatable, but also to enable engineering judgement to be incorporated in the history-matching process. The feedback loop is also an essential component of the workflow as it allows the well-level modifiers to be sense checked against the regional geological trends. This further encourages collaboration within a multi-disciplinary team.
These well-level modifiers can also be used to create history-match metrics, which can be spatially mapped to help target specific areas for improvement in history-match quality. Some powerful use of visualization techniques discussed in this paper has not only minimized the mismatch but ensures the characteristics of the production history and geological trends are honoured to assure the robustness of the history-match and the resulting model predictability. The workflow has significantly reduced the time and efforts spent in delivering an improved well forecast when required. The technical development community in QGC has actively nurtured a culture of ideas sharing and innovation, which made the development of this workflow possible.
Optimising Horizontal Coal Seam Gas Wells by Combining Reservoir Simulation and Transient Well Modelling
Authors: Nuralishahi Turaj , Vahmani Maryam , Dharma Putra Erni , Hsiao Wun Moh , Kumar Thakur Kapil , Wai Aung Phyoe , Coman Chris , Delfani Saba , Wimbridge Kyle , Rodriguez Nelson , Samaan Johny 
Published: October 2018

Abstract
In 2017, APLNG drilled the first horizontal wells within the Surat Basin targeting the Walloon coal seam gas (CSG) measures. This reservoir is quite shallow with the potential for relatively low pressures. To address this uncertainty, a study was performed to identify an optimum operational strategy to maximise the cumulative gas production of a well over the first five years of production.
This was achieved by using a Latin Hypercube sampler and a Genetic Algorithm optimiser to identify optimum reservoir simulation scenarios. The optimized simulation scenarios were then modelled within a multiphase transient simulation model, to better understand the flow regime behaviour within the wellbore. This predicted the flowing potential of the well whilst modelling flow assurance risks such as wellbore slugging. The result was an innovative workflow that identified optimum operational strategies whilst accounting for the uncertainties in reservoir pressure and the fluid hydraulics in the wellbore.
After completing the reservoir optimisation studies, the optimised cumulative gas production showed increases between 3% – 6% compared to the base case. Other improvements included; higher peak gas production, higher peak water production resulting in earlier desorption of gas, shorter time to initial gas, and shorter time to peak gas. After running the optimised reservoir simulation cases through the transient models, it was found that the days to peak gas was reduced by 80-90%, whilst the slugging periods were reduced by 90-100%. The models were also used to quantify the impacts of changing operational/design parameters such as horizontal well length, casing sizes, pump speeds, and choke settings. APLNG used these results to design their well start-up and ramp-up strategies, and successfully kick off their horizontal wells.
The results of this innovative workflow for reservoir and wellbore modelling in a CSG field highlights the new insights that can be gained by combining traditional reservoir simulation with mathematical optimization and transient well flow modelling. These workflows enhance our understanding of how to improve efficiencies and maximise production volumes within CSG fields.