bluuebunny/crossref_metadata_2025_split huggingface dataset:
Assesing Well Placement in Multi Faulted Reservoir
Authors: Vevakanandan Valsan , Ting Angelina , Zhang Tingting , Maula Fahdi , Ahmad Aqil , Santoso Gagok , Alang Khairul 
Published: October 2018

Abstract
K field is a faulted anticline structure lying in a turbidite environmental setting, which consists of two main sand bodies of 50-100ft gross thickness. Two main challenges during development stages were, 1). The narrow thickness of the fault block requiring accurate landing, well placement and characterization. 2). The low vertical permeability inside the sand which requires the straddling and precision of horizontal placement relative to reservoir boundary. Geosteering was proposed to mitigate those challenges, which is then translated into a directional drilling plan. Hybrid LWD combination of Seismic, Reservoir Mapping, RT-Image and Formation Pressure While Drilling technology were used overcome those objectives and challenges. Seismic was used to update target uncertainty in both depth and lateral coordinates, hence accurate landing inside the target fault block was the main driver. Reservoir Mapping Technology and borehole images were used to update the presence of fault and plan for an accurate placement of the horizontal section. Pressure While Drilling was used to update the reservoir pressure and fault/ connectivity between fault/compartments. Post job subsurface modeling was updated using those measurement for accurate interpretation, which was used for future field development plan.
The drilling workflow was extensively discussed among the stakeholders to make sure it was fit for purpose and could achieve the objectives. Horizontal well landing procedures using Seismic While Drilling technology helped the well penetrate into fault block A at 100m before fault edge. Reservoir Mapping While Drilling technology enabled successful Geosteering inside the desired target zone. Another important application regarding the Reservoir Mapping Technology is the capability of resolving the internal sedimentary bedding feature (higher dip feature) and the delineating of multiple faults including sub seismic fault block B, which helped the team define well TD at the desired fault block position. An integrated interpretation between Reservoir Mapping While Drilling, High Resolution Images and Formation Pressure While Drilling to detect pressure continuity between one block to the other proved to be very helpful for production management and completion optimization. At the end, two horizontal wells were successfully drilled in the desired fault block. Everything worked, ie the technology, the people and the process, resulting in an accurate and well controlled execution of a complex and high-profile project.
The novel approach was successfully demonstrated to ensure well objectives are achieved in an integrated manner. The flawless execution allowed the team to avpid drilling any side tracks which would have been costly.
An Open Approach to Drilling Systems Automation
Authors: Brackel Hans-Uwe , Macpherson John , Mieting Ralf , Wassermann Ingolf 
Published: October 2018

Abstract
The promise of drilling systems automation is to increase well construction efficiency, delivering quality wells in a safe, reliable and predictable manner. This promise is achieved in part by creating a digital infrastructure that extends vertically from the drill bit to the remote enterprise, and horizontally from exploration to production. Critical to the success of automation is the unimpeded flow of quality data through this infrastructure. This paper focuses on studying only drilling systems automation, but the lessons learned can be applied to other disciplines such as completions and production.
Due to the disconnected nature of the well construction business with multiple disciplines and companies involved, data silos and restrictions are numerous. This paper describes the development of a wellsite-based automation system consisting of an open data aggregator, with networked surface and downhole sensors and real-time applications for process monitoring, advice and control. The data aggregator is designed to allow all relevant parties to access and share data in a high-velocity deterministic environment. This access and sharing permits easy implementation of comprehensive drilling system automation, be it monitoring, advising or control, in a controlled, productive and safe manner. The paper also describes the implementation of automation applications using data from the aggregator, covering real-time drilling optimization and hydraulics.
Operation of the data aggregator at the wellsite with connection to rig systems and remote operating centers is described. The data aggregator uses protocols that are international standards, and it is designed to be open and not proprietary. From an implementation standpoint, this allows easy interface of the aggregator to measurement and control systems, and access to copious third-party communication products, reducing development time and increasing reliability. Observations are that many rig instrumentation and control systems use either customized or proprietary protocols; common data information standards are lacking in the oilfield. In addition, data ownership and governance must be addressed at an industry level, as well as secure bi-directional flow of data between wellsite and town. While these topics are, to some extent, being addressed in industry road-mapping and guidance groups, progress is slow and this hinders the adoption of technology.
The paper describes the development and implementation of an open data aggregator for the wellsite. The aggregator allows third-party real-time applications to use and share data, and to collaborate on industry standards. It further describes the development of automation applications riding on the data aggregator, and their use in drilling systems automation. This case study illustrates and examines issues that must be addressed at the company and industry level to move universal drilling systems automation closer to reality.
Successful Infill Realized through Prudent Brownfield Oil Rim Reservoir Management, Offshore Malaysia
Authors: Khalid Aizuddin , Ahmad Tajuddin Nor Baizurah , Dan Hui Xuan , Sapian Nik Fazril , A'akif Fadzil Nurul Aula , Hassan Siti Normaizan 
Published: October 2018

Abstract
Managing an oil rim type reservoir has constantly been a great challenge and understanding the oil rim movement has remained as one of the main subsurface uncertainties. Prudent reservoir management through an active reservoir, well and facilities management (RWFM) plan is key to realizing the uncertainties, optimizing production and reserves of brownfields. Monitoring the oil rim through cased-hole reservoir saturation logging has been identified as a de-risking method, planned and executed for two consecutive years in the field to minimize the oil rim uncertainty. The field studied is one of the brownfields in offshore Sarawak, Malaysia, which has been on production for more than 40 years.
Results acquired from the cased-hole logs have triggered the need to optimize the location of an infill oil producer planned in the Field Development Plan. The cased-hole results indicated that the original oil target in the N reservoir had mostly been swept by water. Through thorough studies and modeling, an opportunity to the western flank in M reservoir, located close to a proposed workover well, was suggested. Furthermore, latest input on the proposed workover well and facilities health check suggested the workover candidate was not favourable due to its location on an aging single well monopod structure with complex well mechanical problems. Thus, the planned infill oil producer was recommended to replace the workover well and recover the reserves.
Integrated studies incorporated cased-hole results with reservoir modeling indicated that the new infill location would yield a total of 5.7MMSTB reserves with initial production rate of 1215BOPD. In addition, through integration of a multi-disciplinary team, revision to the infill location was timely and the infill was also accelerated from Phase II to Phase I of the development plan as a rig filler for cost optimization. Well test result successfully validated the reservoir productivity of 1238BOPD with no water production.
This paper presents the integrated subsurface and surface solutions and criticality of proactive data acquisition, field monitoring and collaborative team work strategies to maximize the recovery from a brownfield.
An Embedded Downhole Conductance Sampling System Based on Adaptive FFT Algorithm
Authors: Yang Qinghai , Fu Tao , Huang Shouzhi , Ming Eryang , Li Ming 
Published: October 2018

Abstract
The salinity measurement of the down-hole water is an important parameter to optimize a production scheme for oil exploitation. However, salinity is generally measured offline by physical and chemical analysis and it has been difficult to implement a real-time measurement. With the online conductance sensor, the water salinity can be obtained indirectly based on prior knowledge. In order to solve the down-hole salinity monitoring problem, this paper proposes an embedded sampling system for real-time conductance measurement. The conductance sampling system is designed with embedded technology to achieve continuously monitoring. Based on an ARM-based embedded kernel, peripheral extended circuits are constructed for the sampling system, including an excitation source, a signal conditioner, an analog-to-digital converter, a memory module, a communication port, and a power supply module. The active excitation source generator can output a sinusoid signal with an adjustable amplitude and frequency to the electrical poles. The voltage signal from measurement poles is then sampled after adaptive signal conditioning. With a simplified Fast Fourier Transform (FFT) algorithm, the effective value is measured and the quality of the sampled signal is analyzed to feedback-regulate the excitation source and conditioner. Therefore, the stability and accuracy can be improved for conductance measurement. The conductance measurement system is tested in a physical testing environment with different conditions of water salinity, oil-water mixing ratio, liquid temperature and flow rate. Testing results show that the sampled conductivity value keeps stable and accurate with the calibrated reference conductance meter. The system has a wide measurement range together with a high accuracy and resolution. When the temperature changes, the measured conductivity value basically does not vary, which shows that the temperature compensation is effective. When measuring different salinities of water, the system can adaptively adjust the output amplitude and signal conditioner gain to get suitable sampling precision. In brief, the system provides real-time conductance measurement and the measuring accuracy can satisfy the requirements of petroleum production optimization. To ensure the system may be run down-hole permanently, the electronic scheme and the power supply circuit are specially designed with low-power consumption.
A Comprehensive Study on Ultimate Recovery and Optimum Production Strategy for Gas-Condensate Reservoirs under Aquifer Support in Nam Con Son Basin, Offshore Vietnam
Authors: Tran Tung V. , Truong Tu A. , Ngo Anh T. , Hoang Son K. , Trinh Vinh X. , Dang Tuan A. , Ngo Hai H. 
Published: October 2018

Abstract
Despite the importance of determining the maximum recovery and optimum production strategy for gas-condensate reservoirs under aquifer support, a rigorous systematic methodology is not available in the literature. Instead, most existing studies relied on running reservoir simulations with fine grids or LGR constrained by simulation runtime, producing great uncertainty in the reliability of the results. In this study, a comprehensive and systematic study of gas-condensate reservoirs under aquifer support was conducted instead.
This study focused on first benchmarking radial simulation models to available analytical solutions to within 1% of pore pressure prediction. Next, Cartesian grids were benchmarked against the calibrated radial model before applying to full field reservoir model. The full field reservoir model was then history-matched for all wells before various production regimes were simulated to determine optimum production strategy. Sensitivity analysis of water-breakthrough and total produced water volume were investigated under various aquifer sizes, formation reservoir properties, and production regimes. Optimum production strategy was selected to maximize the hydrocarbon recovery while reducing the water treatment costs.
The approach focused on the construction of benchmarked models to describe the water breakthrough phenomena and to investigate the impact of aquifer on deliverability and ultimate recovery of a gas-condensate reservoir. Factors that could affect recovery such as withdrawal rate, aquifer size, formation permeability, and vertical-to-horizontal permeability were examined. Different production schemes were then simulated on a history-matched full field model to determine optimum strategy.
It was found that for better reservoir quality (permeability greater than 100 mD), withdrawal rates do not have significant impact on ultimate gas recovery. On the other hand, with increasing withdrawal rate cumulative condensate recovery decreases and total water production increases. Aquifer size has large impacts on recovery factor, water breakthrough time, and total water production. For medium and strong aquifers, it was found that the field water handling capacity could impose a significant constraint on ultimate recovery and upgrading water handling capacity later in the field life may be instrumental in improving recovery.
Laboratory Study of Anisotropic Permeability of Tight Sandstone and Shale from Cooper Basin, Australia
Authors: Pan Zhejun , Heryanto Deasy , Down David , Connell Luke , Camilleri Michael , Tan Yuling , Sander Regina 
Published: October 2018

Abstract
Cooper Basin is one of the most important onshore oil and gas producing basins in Australia. It also has the most prospective unconventional tight gas and shale gas opportunities. As tight sandstones or gas shales have low permeability, understanding the permeability behaviour is important for the production of these gas resources. In this work, tight sandstone and shale samples were obtained from an exploration well in the Cooper Basin, Australia, and they were cut into cubic samples with about 30 mm on each side using a wire saw. The cubic sample was then placed in a 3D printed membrane, therefore, permeability along each directional axis can be measured. Methane was used to characterise the permeability. Effects of gas pressure and effective stress were studied with gas pressure up to 9.5 MPa and effective stress up to 7.0 MPa. The results shows that the shale has strong permeability anisotropy at different direction. The sandstone sample also showed anisotropic behaviour, but not as significant as the shale. Finally, a reservoir simulator, SIMED II, is used to study the gas production from tight sandstone and shale using hydraulic fractured vertical and horizontal wells. The simulation results show that permeability plays a critical role in the gas production behaviour from tight sandstones and shales.
Enhanced Oil Recovery by Nanoparticle-Induced Crude Oil Swelling: Pore-Scale Experiments and Understanding
Authors: Agrawal Devesh , Xu Ke , Darugar Qusai , Khabashesku Valery 
Published: October 2018

Abstract
Nanoparticle (NP) based enhanced oil recovery (Nano-EOR) has been considered as a promising future EOR strategy. However, although many mechanisms of Nano-EOR have been proposed, a lack of direct connections between the pore-scale mechanisms and the macro-scale oil recovery performance makes it hard to determine which mechanisms are dominant. In this work, we discovered a novel phenomenon of nanoparticle-crude oil interaction in pore-scale. Multi-scale experiments were conducted to connect this novel pore-scale phenomenon's role to oil recovery performance.
A microchannel with dead-end pore was used to observe crude oil-NP interactions, on which crude oil can be trapped in the dead-end pore with a stable crude oil-aqueous phase interface at the pore-throat. A glass porous micromodel was used to conduct oil displacement experiments. ASW was used as the secondary flooding fluid, and 2000 PPM negatively charged NP in ASW was applied as the tertiary flooding fluid. Saturation profiles were recorded and analyzed by advanced image analysis tools. A coreflood through the sandstone sample was also conducted with similar conditions to the micromodel-flood experiments.
A phenomenon that has never been reported was observed from the dead-end pore microchannel. It was observed that crude oil can considerably swell when contacting the nanoparticle aqueous suspension. In an ideal case (5 wt% NP in DI water), the oil volume more than doubled after a 50-hour swelling. The possible explanation for the crude oil swelling could be spontaneous formation of water droplets in the crude oil phase. NP can very likely affect the distribution of natural surfactants in crude oil (on the interface or inside oil phase), which breaks the water balance between aqueous phase and crude oil. This view has received support from quantitative experiments. It was shown from 2.5 D micromodel flood experiments that 11.8% incremental oil recovery comes slowly and continuously in more than 20 hours (40 pore volumes). From a saturation profile analysis, swelling of crude oil was found to improve sweep efficiency. Coreflood experiments also showed that the incremental oil was slowly and continuously recovered in about 20 hours during NP flooding. We propose that reduction of local water mobility by oil swelling in the swept region is the mechanism of sweep efficiency improvement.
Swelling of crude oil under a NP environment was observed for the first time, with a systematic theory proposed and examined by quantitative experiments. The micromodel flood and coreflood experiments showed slow incremental oil recovery with a similar time scale to the oil swelling. Image analysis on the micromodel flood demonstrated improvement in the sweep efficiency during NP flooding. The mechanism for this sweep improvement is proposed.
Zonal Isolation of a Fractured and Gravel Packed Water Producing Zone using an Organically Crosslinked Polymer Sealant: Case Study
Authors: Nagar Ankesh , Dangwal Gaurav , Pandey Nimish , Jain Akanksha , Parasher Arunabh , Deshpande Mayur , Gupta Vaibhav , Pande Karan 
Published: October 2018

Abstract
Increasing water cut in oil-producing zones is a common issue faced by operators, particularly for mature fields. Currently, where most of the decisions are governed by economics, incurring additional expenses with activities such as handling produced water becomes extremely undesirable. Depending upon the nature of the zone, one effective solution to this issue is chemical isolation. This paper undertakes this issue, discussing a case study of a successful zonal isolation operation using an organically crosslinked polymer sealant in a fractured zone with a gravel pack and screen completion for a reservoir with a subhydrostatic nature.
This zone was an initial oil producer in FM-01 sand of the Mangala onshore oil field and had been stimulated in 2011 with a fracture-pack completion. The zone was completed with screens and a gravel pack with 16/30-mesh sand and 5.5-in. screens across the producing interval. During a period of time, the zone (FM-01) began to produce a significant amount of water, resulting in excessive water cut. To mitigate the issue, it was decided to completely isolate the zone using an organically crosslinked polymer system as a porosity fill sealant. When prepared in the appropriate concentration, subject to reservoir temperature, this low-viscosity formulation (40 to 80 cp) turns into a permanent rigid gel with time. The particular challenges of this operation were the presence of high permeability streaks because of stimulation by hydraulic fracturing, extra pore space because the perforated interval lay within the gravel-packed screens, and the subhydrostatic nature of the reservoir. Extensive laboratory testing was performed to optimize the formulation at the desired temperature, measuring the time necessary for the viscosity to begin increasing and the minimum total time necessary to form a rigid gel.
The case study discussed in this paper features the successful application of the treatment using the spot-and-squeeze method with coiled tubing (CT) for the isolation of the zone. After allowing the setting time, pressure tests were performed, indicating positive isolation of the zone. After the pressure test, a jet pump was installed, and a drawdown was created to flow the zone. It was observed that production post operation was almost 95% less than production before operation at the same pressure drawdown, indicating approximately 100% zone isolation.
How to Run Casing Efficiently in Extended Horizontal Wells Using Buoyancy
Authors: Rastegar Reza , Munawar Mohammed , Tait William 
Published: October 2018

Abstract
Due to drilling economics, operators prefer extending the lateral section over drilling a new well. It presents a challenge to run casing strings to the target depth in wells where horizontal section is longer than the vertical section. Although alteration of casing weight or installation of liner may present as solutions, they are hardly economical compare to selective buoyancy methods. This paper aims to take an engineering approach on optimizingly palceing a buoyancy barrier which traps lighter fluid in the horizontal section for thepurpose of reducing friction. As seem to not have been presented in SPE conferences before, the aim of this paper is to engineeringly identify the optimum placement of the barrier, measure the efficiency improvement and identify the cases for which running a barrier is essential to run the casing string to the target depth. Operators usually run a torque and drag to measure the improvemet made by placing a barrier in kick off point. In this paper we intended to verify this practice and offer a simple rule of thumb method that can help an operator to decide on weather it is needed to run a barrier.
Referred to in this paper as flotation collar, it is installed as part of the casing string. It employs a mechanical barrier that traps the air or lighter completion fluid in the mostly horizontal section and separates it from the heavier completion fluid in the mostly vertical section of the casing string. Identifying the best position of the barrier is important to achieve the maximum hook-load. In this paper, numerous cases are studied by gradually expanding the air section and monitoring the hook-load to identify the best position for which the hook-load is maximum.
As per its physics, there is only one position of placement which results in the highest axial tensile force, also known as hook-load, when forces of gravity and friction engage. Placing the tool too high or too low in the string misuses the available tensile axial force and will not provide the best results. By using casing flotation tools as a barrier, a spectrum of thirty to eighty percent tensile improvement in the axial load are observed and more than fifty percent reduction of buckling effects in vertical section. For some cases, running a flotation tool was the only option to reach to the target depth with the casing string.
Flotation tools in long string wells are the only economical alternative to changing casing weights or running liners when it is to completing wells with extended horizontal sections. A flow-chart is presented to help with simplifying the process of choosing a flotation tool and finding its best position of placement.