bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysing Critical Elements in Openhole Gravel Pack Treatment Design Cycle: Case Study in Indian Ultra-Deepwater
Authors: Gupta Vaibhav , Jeanpert Julie , John Colin , Bose Ramen , Agrawal Vivek , Patowary Markandeya , Banka Raushan 
Published: November 2020

Abstract
Openhole gravel pack is the preferred completion method of sand control in unconsolidated deepwater formations with sanding tendencies. The design phase of an openhole gravel pack treatment spans drilling of the reservoir section, wellbore preparation, sand screen installation, gravel placement, and well flowback. This paper discusses several ultra-deepwater wells of India, where openhole gravel packs were performed by integrating drilling, wellbore cleanout, wellbore displacement and gravel pack methodologies to achieve a holistic approach towards openhole gravel pack completions.
The reservoir sections were drilled with streaks of shale and dolomite sections, the liner shoe often landing in shale, exposing a shaly rat hole. Next, the wells were displaced to dedicated production screen testing (PST) mud prior to running in screens. Screens were then placed across the openhole with memory gauges to capture downhole events during the gravel pack. The displacement pills train was engineered to displace the open hole with water-based fluid prior to starting the gravel-pack treatment. Extensive lab testing and displacement simulations for efficient spotting of pills and optimal sweeping effect were performed. The gravel-pack treatment was executed using Alternate Path technology and a high-temperature viscoelastic surfactant (VES) carrier fluid system.
11 ultra-deepwater wells off the east coast of India were completed. Displacement of open hole from drilling fluid to water-based system was done with direct displacement and reverse displacement methods. Due to the narrow fracturing window of 200-300 psi in all the wells, bottomhole pressures were managed by deploying multiple techniques such as using a lighter VES-based brine, optimizing the rheology of the fluid and taking returns through the riser. Roping behavior of the pre-pad and slurry have also been studied, and results presented to correlate with design. All open-hole gravel packs were executed without losses and achieved complete packs. Finally, flowback and well test data were analyzed by the operator and found to be as expected with no sand ingression. A holistic approach toward open-hole gravel-pack treatments has been developed, analyzing all the interlinked elements and the efficacy of the design process verified against surface and downhole data gathered for each well.
This paper discusses the approach, simulations, lab testing, and evaluation, analyzing captured data from drilling phase of the open hole to completing the well by placing gravel across the screens and flowing back. The design approach, integration strategies, and lessons learned in these wells offshore India can be applied to improve success rates of sand control completion wells around the world.
Numerical Simulation Workflow using Carbonate Digital Rock Built from Integrated Lattice Boltzmann and Kriging Method
Authors: Han Yifu , Liu Kailei 
Published: November 2020

Abstract
Formation evaluation including porosity and directional permeability assessment in complex carbonate formations is challenging due to the anisotropic and heterogeneous nature of the formation. The pore structure can be captured by digital rock technology, which makes the constriction of numerical whole core, and the numerical simulations of chemical enhanced oil recovery on digital rock possible.
We introduce a new workflow to construct the digital rock based on micron-CT scanned sequential images of the carbonate sample. Firstly, we apply the modified Otsu's global thresholding method to convert the grey-scale micron-CT scanned images to binary images, and we systematically divide the whole core 3D segmented image into small blocks or representative elementary volume (totally 10143 blocks including inactive blocks). Then we estimate the porosity of each block, and use Lattice Boltzmann Method (LBM) to simulate fluid flow in randomly selected blocks and accurately compute the directional permeability of these blocks by simulating Darcy flow through them. The permeability tensor of other blocks is estimated by applying Kriging method based on the estimated porosity of all the blocks and the accurately calculated permeability tensor of the selected blocks. Then we simulate the polymer flooding on the constructed digital rock and show that the simulation process is computational efficient.
We calculate the porosity and permeability of the constructed digital whole core and compare them with laboratory measurements. The image analyzed porosity of whole digital rock is comparable with laboratory measurements by only 1% difference. The simulated permeability value with calibration of the whole digital rock is also in good agreement with experimental result by 3.5% difference. Then we simulate the polymer flooding on the constructed digital rock and show that the simulation process is computational efficient. The proposed digital whole core construction workflow integrates the accuracy of LBM simulation and the efficiency of kriging method. The accurately constructed digital whole core only have 10143 blocks including inactive blocks, which greatly reduces the heavy computation time of chemical enhanced oil recovery simulation on digital rock and makes the proposed method more practical in routine analysis and modeling.
Quantifying Flow Behind the Liner during a DST using High Resolution Thermal Array Technology and a Novel Thermal Model
Authors: David Lavery , David Fyfe 
Published: November 2020

Abstract
In this case study, high resolution temperature array data, acquired during a Drill Stem Test (DST), were able to identify and quantify flow behind the liner. Quantifying the flow rate behind the liner between the production zones was of significant value to the operator to reduce the uncertainty in the Pressure Transient Analysis (PTA).
The high resolution temperature array was deployed clamped to the outside of the Tubing Conveyed Perforating (TCP) guns, which were used to selectively perforate multiple zones. Using wireless acoustic technology the temperature data were transmitted to surface to enable real time feedback during the DST. A novel thermal heat exchange model was built that could take advantage of the high resolution temperature array data acquired during the entire test. The results of the model were compared to the real data to validate the results and provide accurate flow rate measurements of the flow behind the liner in real time during the test. A sensitivity study on the various model input parameters was also carried out to reduce the uncertainty in the thermal model, the results of which are detailed within the paper. Being able to quantify the flow behind the liner allowed the operator to adjust their PTA results and provided a more robust reservoir model.
Typical thermal models in the industry are unable to quantify flow behind the liner in this environment. A new thermal model had to be developed that could take into account the complex heat transfer processes and take advantage of the high resolution thermal array data acquired during the DST. Despite the challenging wellbore environment during the test, the high resolution temperature data were used to provide a robust zonal flow confirmation and rate allocation during the flow periods.
Whilst Distributed Temperature Systems (DTS) are gaining popularity in the oil and gas industry, typically the current technology does not provide the high resolution required to be able to quantify flow behind the casing. This new model, when combined with high resolution thermal array data, has wide ranging applications not only during the DST but also in long term completions where monitoring well integrity is a real industry challenge.
Gas Rate Prediction in an Openhole Multi-Stage Fractured Well with a Revised Thermal Model
Authors: Sui Weibo , Zhang Di 
Published: November 2020

Abstract
The fiber-optic distributed temperatrue sensor (DTS) has been used for flow profiling in horizontal multi-stage fractured wells, and there were some reservoir/wellbore coupled thermal models presented by researchers. Although current theoretical models are developed for some certain application scenarios, the industry have realized the great potential of DTS for production prediction in unconventional resources. This paper presents a DTS flow profiling case for a horizontal multi-stage fractured well in tight gas reservoirs with open-hole packer completion scenarios by applying a newly improved theoretical model.
In this paper, we started with the conventional semi-analytical wellbore-fracture-reservoir coupled flow/thermal model which have been developed for cased, perforated, and multi-stage fractured wells, and revised it to consider the special feature of openhole packer completion scenario. Since the formation fluid firstly flows through the fracture into the open-hole annular space between formation and the packer liner, then flow along the annular space until meet the frac port on the production pipe, we add a simulation sub-region representing open-hole annular which helps to understand the flow and heat transfer inside it. The presented model successfully simulated the two-fold flow regime caused by the simultaneous flow and heat transmission in the annular space and the production pipe. In each stage, the DTS temperature data possibly show double drops due to Joule-Thompson cooling effects at the fracture and frac port locations if they are not consistent.
With the improved mathematical model, DTS monitoring data during a three-rate production test in a horizontal multi-stage fractured well in Erdos Basin of China was simulated and analyzed. The improved model with open-hole packer completion was applied and then the gas rate prediction was accomplished.
CO2 Storage with Enhanced Gas Recovery CS-EGR in Conventional and Unconventional Gas Reservoirs in Australia
Authors: Wang Hongcai , Rezaee Reza 
Published: November 2020

Abstract
Excessive greenhouse gas emission and natural gas shortage need to be tackled urgently nationally and globally. In this context, Carbon Capture Storage and Utilization (CCUS) has been proposed to: (1) mitigate the global warming by removing carbon from the atmosphere and, at the same time, (2) create value/reduce the cost by utilizing them for production. CO2 Storage with Enhanced Gas Recovery (CS-EGR) is well fit for the purpose of CCUS. This paper analyses the feasibility of CS-EGR in Australia by characterizing reservoir rock and fluid properties from both conventional and unconventional gas reservoirs, and by modelling the process of CO2 injection, gas production, and CO2 storage.
This paper discusses technical aspects of injection and storage of CO2 and the behaviours of CO2 and methane together with enhancement of gas production. Although both conventional and unconventional gas reservoirs are covered, the emphasis is given to the unconventional gas. CO2 is more preferentially adsorbed to shale or coal than CH4, so the injected CO2 will displace CH4 which then can be recovered. It is also miscible with natural gas and is good for re-pressurizing reservoir. However, these processes are highly influenced by many factors, such as reservoir temperature and pressure, total organic content (TOC), porosity, permeability, pore size (distribution), injection operation, mineralogy, fracture, fluids and so on. Numerical simulation is a perfect tool to study how different parameters interact with each other and eventually affect the efficiency of CS-EGR.
The authors undertake geological and petrophysical characterization of target formations in Australia. It is then followed by numerical modelling which takes consideration of reservoir characterization data and interaction between CO2, CH4, H2O and rock. The sensitivity analysis investigates the performance of CS-EGR at different scenarios and identifies the critical factors. It is worthwhile to mention that two gas injection methods, gas flooding, huff'n'puff, (or cyclic gas injection), are studied and compared.
Based on previous studies, this paper moves a step further by: (1) incorporating reservoir characterization data from Australia gas field in numerical modelling and exploring the feasibility of CO2 Storage with Enhanced Gas Recovery in Australia; (2) investigating both unconventional gas reservoirs and conventional reservoirs and makes a comparison between them; (3) comparing two injection methods for all different reservoirs; (4) performing sensitive analysis of multiple parameters identified from analysis and literature. CS-EGR is promising in achieving "net-zero emission" for Australia.
Drilling Performance and Risk Management Optimisation in Offshore Australia: Improving Overall Safety and Efficiency of Well Construction Process
Authors: Kirthi Singam Chandrasekhar , Hafezi Farshid , Rebello Clyde , Bartul Miroslav , Ali Anis , Naveed Muhammad 
Published: November 2020

Abstract
The emergence of Real-Time Well Construction Performance Monitoring Centers has significantly improved the service delivery for Operators across numerous offshore oil fields in Australia. New technologies and workflows were implemented for 3 Australian offshore wells, with the primary objective being to improve drilling efficiency while managing the associated risks. Additional objectives included optimizing daily operational performance, thus delivering time savings for the Operator and highlighting areas of possible improvements.
The workflows combined proven technologies, software and wellbore surveillance services, which delivered risk-free wells ahead of Authority for Expenditure (AFE), by targeting the reduction of nonproductive time (NPT) and invisible lost time (ILT), together with risk management.
The workflow began with a preliminary field analysis to identify the main challenges and areas that needed improvement. The key learnings were then consolidated on a comprehensive drilling road map by well section that outlined prevention and mitigation measures, expected rate of penetration (ROP) and recommended drilling parameters. The study also identified performance benchmarks such as average and on bottom ROP and connection time. Key performance indicators (KPI) were developed to monitor progress and track the well with respect to well improvements versus the benchmarks identified. The selection of the monitoring tools and modules required during the Execution Stage were developed based on the risks and KPIs identified during the field study and were further tailored to target specific challenges such as stuck pipe prevention, hole cleaning, shock and vibration and connection time.
The workflows enabled the flawless execution of 3 offshore wells 29.0 days ahead of AFE which saved the Operator USD 15.5M. The closed loop monitoring enabled real time interventions which aided in preventing risks such as stuck pipe, ensured efficient shoe-to-shoe drilling and avoided potential lost-in-hole (LIH) costs. This case study demonstrates the use of a novel approach to increase well construction efficiency by eliminating lost time while enhancing risk control. The main basis for success of this workflow was using existing and cost-effective technologies while capitalizing on the renewed synergy between different departments such as Drilling, Mudlogging and Well Operations analysis.
The workflow was and can be customized based on different needs, by combining specific modules for monitoring, analysis and wellbore surveillance services, to increase the efficiency of any well construction.
An Integrated Approach for Tackling and Resolving Horizontal Drilling Challenges in the Eromanga Basin to Maximise Production Benefits
Authors: McDermott Samuel , Wang Haifeng , Liu Yang , Jiang Xiaohu 
Published: November 2020

Abstract
Eromanga Basin in central Australia was deposited from early Jurassic to late Cretaceous and has witnessed commercial discoveries in different formation units throughout the basin's spatial distribution. Lately, operators have shifted from vertical to horizontal wells to enhance production outcomes. However, there are still many challenges for achieving and enhancing these benefits with horizontal drilling. These include navigating an undulating reservoir structure whilst staying in the target zone and maintaining appropriate vertical standoff from oil water contact (OWC) to avoid early water breakthrough.
In this paper, the author summarizes the experiences and approaches made in tackling and resolving these challenges, by elaborating on the new methods applied during the recent horizontal drilling campaign. These include new drilling technologies, such as the latest rotary steerable systems and new logging-while-drilling technologies, such as the multilayer bed boundary detection services. The methodology of using this data both while-drilling and post-drilling for critical decision making on both geosteering and completion strategies, is also addressed. The author illustrates an integrated approach that was adopted by incorporating new data into the reservoir model for the purpose of referencing and planning future wells.
Case studies from two of the recent wells are discussed in detail to illustrate the operational workflows and the integrated approach. Landing and geosteering practices are examined separately to demonstrate how to achieve best results and avoid both identified and potential pitfalls. The overall drilling and production performance of the recent ten wells are summarized, as are the results of applying these methods. Finally, the author reveals the new insights that the post-job data integration brought for the field.
This new approach has allowed the operator to drill an increased number of wells than originally planned in the same timeframe. This approach has also allowed for longer wells to be drilled. By comparing the production benefits with the cost of drilling, the author shows the viability of these methods in resolving the challenges of horizontal drilling in this region.
Well Inflow Performance Under Fines Migration: Analytical Model, Production Data Treatment
Authors: Loi Grace Ming , Chequer Larissa , Nguyen Cuong Cao , Zeinijahromi Abbas , Bedrikovetsky Pavel 
Published: November 2020

Abstract
Fines migration causes significant formation damage during oil and gas production. The reliable prediction of well performance and extend of the damaged zone allow for planning and design of well stimulation for prevention, mitigation and removal of the damage. We derive a novel analytical model for production well performance during fines migration. The model includes explicit formulae for concentrations of suspended and strained fines, and the expressions for skin factor and well impedance. Ten field cases exhibit close match with the analytical model. Moreover, the tuned parameters belong to common intervals of their variation. The work provides means for reliable well behaviour prediction based on production history and coreflood data.
Probabilistic Assessment of Pressure Depletion and Inflation and its Impact on the Drilling Sequence for the Sangomar Field, Senega
Authors: Gavin Lisa , Jagtenberg Pieter 
Published: November 2020

Abstract
The Sangomar Field Development – Phase1, located offshore Senegal, will consist of 23 wells targeting stacked reservoirs, with horizontal lengths up to 1,500m. Due to the long drilling campaign, wells are likely to be drilled after first production, targeted for 2023. At the time of drilling, reservoir pressure in these wells will be affected by nearby producers and injectors, which will reduce the mud window in the boreholes, affecting the drillability.
Vulnerable wells are identified by a deterministic borehole stability assessment based on mud weight windows and a probabilistic well-by-well analysis of reservoir pressure at the time of drilling. The estimated mud weight windows are unique to each well and a function of completion type, overburden thickness and well azimuth. Capturing reservoir uncertainties within the uncertainty framework results in 216 models which are reduced to a more manageable 20 models for simulation using a distance-based K-medoid algorithm. Maps of maximum depletion and inflation are generated for each of the medoids.
With this work, the importance of probabilistically assessing reservoir pressures is demonstrated in the context of developing a robust drilling sequence, highlighting that results can vary significantly depending on the reservoir models used. Potential magnitudes of depletion and inflation in some scenarios are significantly greater than initially anticipated. The combination of borehole stability assessment and probabilistic well-by-well analysis of reservoir pressure allows clear identification of wells at increased risk of borehole stability problems caused by injection or depletion. Subsequently, the drilling sequence is updated to mitigate borehole stability risks by executing potential problem wells prior to first production and prioritising key water injectors, enabling management of post-production depletion while continuing to meet the other objectives such as maximising early production potential.
This paper outlines an innovative workflow which captures the range of subsurface uncertainties to define probabilistic impact of depletion and injection on borehole stability. Within the literature we have not seen any examples of depletion and inflation being assessed probabilistically on multiple models or using a map-based format. Depletion and inflation are also often discussed in the context of producing fields, not during the first phase of drilling, as is the case for the Sangomar Field.