bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analytical and Numerical Solutions for Interpretation of Chemical Compaction in Chalk
Authors: Andersen Pål Østebø , Berawala Dhruvit Satishchandra 
Published: October 2018

Abstract
Chemically reactive flow is of significant importance for EOR due to possible wettability alteration (low salinity and smart water brines), scaling and chemically enhanced compaction, which all can affect hydrocarbon transportation. In particular, chalks (Ekofisk, Valhall) are highly sensitive to the composition of the injected brine (typically modified seawater) as demonstrated on lab and field scale. We present numerical and analytical solutions to interpret the link between geochemical alterations and creep compaction in chalk cores.
A 1D core scale model is proposed for interpreting geochemical compaction during reactive brine injection into chalk cores loaded uniaxially in creep state (compaction under constant applied effective stresses). An analytical solution is derived to describe the steady state ion and dissolution rate distributions. An analytical model for creep compaction is proposed based on the applied affective stress and the rocks ability to carry that stress as function of porosity. The two models are coupled as follows: The compaction rate is assumed enhanced by the dissolution rate. Further, the solid volume changes by mineral dissolution and precipitation, also affecting the compaction rate. Brine-dependent and non-uniform compaction is therefore built into the model via the dissolution rate distribution.
The model is validated against data from ~ 25 core samples where simple Mg-Ca-Na-Cl brines were injected at Ekofisk reservoir conditions (130 °C), in particular experimentally measured effluent concentrations, distributions in mineralogy after flooding and creep compaction behavior. The model captures the effect of varying key parameters such as brine composition, injection rate and initial porosity and can predict ionic and mineralogical profiles along the core, axial and radial deformation profiles locally and with time. This model is a highly useful tool for interpreting experimental data, predicting in-situ mineralogical distributions where measurements have not been made, and for predicting compaction behavior at changes in brine composition, injection rate or effective stress.
The model is intended for giving a prediction of qualitative and quantitative trends during flooding-compaction tests in chalks. The model and its methodology are translatable to other systems but is validated for lab measurements on chalk samples. Current modeling approaches do not consider the complex interplay between brine and rock compositions, reaction and compaction. This work aims to contribute to the current understanding of this topic.
Edge Analytics and Future of Upstream Automation
Authors: Saghir Fahd , Gilabert Helenio , Boujonnier Matthieu 
Published: October 2018

Abstract
As data processing capabilities improve electronic device performance, it becomes necessary for Oil and Gas operators to understand how computing power can be harnessed at the extremities of their production network by deploying Edge Analytics solutions.
This paper will discuss adapting the Industrial Internet of Things (IIoT) in the Upstream Automation domain, specifically in Artificial Lift assisted production, and will shed light on how Edge Analytics can be leveraged to deploy Machine Learning Models (MLMs) directly at the well-head.
A Review of Current Knowledge with Geomechanical Fault Reactivation Modelling: The Importance of CO2 Mechano-Chemical Effects for CO2 Sequestration
Authors: Altaf Iftikhar , Towler Brian , Underschultz James , Hurter Suzanne , Johnson Raymond 
Published: October 2018

Abstract
A fault stability study constitutes a fundamental element of any subsurface injection project that involves faults within a storage complex, yet the transient geomechanical effects introduced due to CO2-rock chemical interactions are rarely considered. This paper presents a review of the published work investigating the potential alteration of rock properties due to short to long term CO2-host rock chemical interactions during commercial scale carbon capture and storage (CCS) operations. Furthermore, the authors of this paper are attempting to highlight the potential significance of these mechanical-chemical effect on the fault reactivation potential for a commercial scale carbon capture and storage (CCS) operation.
The reactive nature between CO2 dissolved in formation water and the storage reservoir can significantly alter the hydraulic and mechanical properties of the host rock, which could in turn affect the storage potential of the target reservoir. Alteration of the host rock mineralogy due to chemical interactions with CO2 have been well studied (Farquhar et al. 2015), but little is available in the published literature on the resulting changes in rock elastic properties (i.e. Young's modulus and Poisson's ratio) due to these reactions. Some recent experimental studies have suggested significant changes in rock properties occur. When we incorporated the geomechanical effects, induced by the rock elastic property changes documented in these published cases, into both 1D analytical and 3D numerical models based fault stability analyses for a Surat Basin reservoir, we observed significant modification of the reservoir storage capacity prior to reaching fault reactivation criteria.
Based on our review of the published literature and our fault stability analyses, we conclude that the chemical effects of CO2 interaction with host rock needs to be experimentally tested to confirm if these effects are significant. If yes, then these effects should constitute an integral part of the geomechanical study for any large scale CO2 injection exercise if there is a critically stressed fault as part of the storage complex.
CSG Reservoir Monitoring Technology: Advantages, Challenges and Selection Criteria Queensland Case Study
Authors: Mortezapour Amin , Bassat Abdul , Lean Eugene 
Published: October 2018

Abstract
Application of reservoir monitoring systems has great value in facilitating the understanding of reservoir behavior and complexity, efficient production optimization and reservoir management over time. The technology has been well accepted by oil and gas pioneers globally in the last 32 years (Australia, Venezuela, Colombia, Kuwait, Oman, Norway, China and USA). In the past 10 years, more than 1,000 wells have used reservoir monitoring systems to monitor the well and reservoir performance of coal seam gas (CSG) wells in Queensland. This paper presents technology, reservoir and production engineering analysis and failure mechanisms in more than 600 CSG wells in Queensland. This paper postulates the selection criteria for every specific application. Some services companies has a 8-year history of installing different types of gauges as one of the main reservoir monitoring technologies for different operators in Australia and New Zealand (The majority of this technology is based in the State of Queensland due to business and regulatory requirements). The application of technology helps CSG operators in the following capacities: Optimizing pump performance and water level monitoringOptimizing hydraulic fracture performance, ground water movement and modellingPressure data for the history matching process (Reservoir Engineering Application)Multizone pressure monitoring (gas injection performance, etc.)
Specific application of the technology, findings during the installation, monitoring, operation, typical completion scheme and best practices for coal reservoir monitoring are summeraized in this paper.
Rate Transient Analysis RTA and Its Application for Well Connectivity Analysis: An Integrated Production Driven Reservoir Characterization and a Case Study
Authors: Ataei Abdolrahim , Motaei Eghbal , Yazdi Mohammad Ebrahim , Masoudi Rahim , Bashir Aamir 
Published: October 2018

Abstract
Rate Transient Analysis (RTA) has been used in gas reservoirs as a proven method for reserve estimation, well diagnostic and production performance evaluations. The authors have demonstrated several case studies showing the application of production analysis (PA) for reservoir characterization in gas and single phase oil reservoirs previously (Motaei, 2017, Ghanei and Ataei 2017, Ataei 2018). The adopted method for Integrated Production Analysis (IPA) works well in those case studies after combining the available data from RTA, PTA, or Material balance and basic reservoir engineering tools. The RTA found to be completing those is based on simple production data analysis using flowing data rather than limited shut in and less accurate ones. With benefit of continuous monitoring of FBHP using PDG, it is possible to evaluate the interferences and boundary in distance beside conventional reservoir properties like permeability and skin.
These methods were found to be extremely powerful and popular particularly with the high resolution data from pressure downhole gauges (PDG).
In this paper we have analyzed the available production data from a gas reservoir in offshore environment in South East Asia. It has been developed with five high PI wells and smart completion and monitored closely with PDG and other surveillance data to understand the contact movement during the production history. Due to the complexity of the field, different methods of production data analysis were used to understand the production performances. The recent advances in RTA allows us to apply the classical single well analysis method to a multiple well and multiple phase flow using Generalized Pseudo Pressure (GPP).
The previously published workflow by the authors (Ghanei and Ataei, 2017) is used for this case study. We evaluate this technique for a multi well gas field with advancing aquifer. The connected volumes as estimated by single well analysis will be used for a group of wells which are communicating and have interference. We have also used a simple reservoir modelling approach to define scenarios which fit the production data and can be used for forecasting which can potentially save study teams time when deciding on the potential value and defining the targets of a major infill drilling project.
Minimum Stress, Maximum Pressure: A New High Performance Bridging System Facilitates Drilling Depleted Formations at High Overbalance in Middle East
Authors: Addagalla Ajay , Maley Iain , Lawal Ishaq , Jadhav Prakash , Luigi Moroni 
Published: October 2018

Abstract
Wells drilled in the direction of minimum stress are potentially more favorable for reservoir development and optimal production. In such a situation, hydraulic fractures grow transversely to the wellbore axis, allowing placement of multiple fractures without the overlapping fractures. However, wells that have been drilled in the minimum horizontal stress direction typically encounter drilling-related problems such as stuck pipe, wellbore breakout and lost circulation. These problems can result in increased well costs due to significant periods of non-productive time and in the worst case, loss of the well.
To address this, wellbore strengthening techniques can be applied to bridge or plug fractures and increase near-wellbore stability via hoop stresses. Designing drilling fluids from a wellbore strengthening point of view has proved successful at managing problems associated with wells that have high overbalance pressure and low formation strength. As more challenging wells are drilled, though, overbalance pressures are exceeding the wellbore strengthening capabilities of existing fluid designs. These high-overbalance pressures significantly increase the risks associated with drilling in the minimum stress direction.
This paper describes an improved, environmentally acceptable, customized high-performance system that can be used in water-based and oil-based mud systems, enabling wells to be drilled with more than 4500 psi overbalance pressure and mud weights beyond 145 pcf. This newly designed system helps the operator increase operational efficiency by:Minimizing the risk of differential stickingReducing downhole lossesImproving wellbore stabilityReducing torque and drag through enhanced lubricity
Laboratory data is presented outlining the design of the new system and field case studies show how this new, improved bridging system reduces the risks associated with drilling in the minimum stress direction through highly depleted reservoirs or reservoir sections where multiple targets may be separated by high-pressure zones that require higher mud weights.
Delivering the First Horizontal Well Under the Harsh Economic Conditions in an Offshore Brownfield in Malaysia
Authors: Kumaran Prashanth Nair , Charbernaud Thierry , Ibrahim Ramli , Kadir Zairi , Kamat Dahlila , Yaakob Mohd Taufiq , Mandal Dipak , Ataei Abdolrahim , Maldonado Jorge , Abdul Rahman Mohd Ramziemran , Iskenova Gulnara , Ceccarelli Tomaso Umberto , Djarkasih Fredy , Abdul Rahman Nor Nabilah , Mohd Salim Ahmad Syahrir , Moreno Juan Carlos , Cavallini Alberto 
Published: October 2018

Abstract
A West Baram Delta prolific mature oil field has been developed through 150+ wells since 1975 in Malaysia. In 2015, an exploration well drilled in neighboring block, successfully found ~500ft TVT of gross oil, 50% less than expected due to structural changes. With lower than expected hydrocarbon in place, the project team was forced to re-evaluate the development and identified key strategies to minimize the number of wells to drill while ensuring healthy project economics. Optimizing reserves and ensuring future accessibility while minimizing number of wells and cost, were the key challenges. Rather than developing all sands with highly deviated well, the team designed an extended reach horizontal well targeting a single key reservoir containing 60% of block STOIIP. Team decided to drill from an existing platform with no pilot hole but opted for real time reservoir mapping technology for well placement. The well was designed with no smart completion due to surface power limitation. First time in the region a dual defensive sand control mechanism was selected, Gravel Pack & Sand Screens. The 1st ever horizontal well was drilled S field meeting its objective at Q4-2017 and exceeding forecasted initial rates. With a long horizontal open hole section and being the only well in the block, a major challenge was to delay water coning and to control water cut once water breaks through. This was achieved with the installation of 8 Inflow Control Devices (ICDs). Real-time reservoir mapping while drilling was used successfully to land the well and then optimize the production section in good quality sands despite structural uncertainty. The well, designed with 60° maximum inclinations, ensures routine well intervention to be done using slickline (i.e. gas lift valve change). Any major intervention would still require coil tubing with usage of barge. The horizontal profile overcomes the limitation of power supply for automation that would be faced with high angle deviated well hence saved significant surface modification cost. The out of box solution of optimized field development plan for complex offshore Brownfield with limited facilities modification, while being cost conscious but technically sound concept proven to provide the answer for sustainable production growth in S Field at low oil price environment. The success of this well has changed the team mindset to relook and propose similar design wells in previously deemed uneconomical FDPs within the S Field.
Experimental Investigation of Crude Oil Emulsion Stability: Effect of Oil and Brine Compositions, Asphaltene, Wax, Toluene-insolubles, Temperature, Shear-stress, and Water-cut
Authors: Uetani Takaaki , Kai Jyunichi , Hitomi Tomoko , Seino Hitoshi , Shinbori Kiyomasa , Yonebayashi Hideharu 
Published: October 2018

Abstract
This paper presents the results of a laboratory case study that was initiated to understand the main causes of the crude oil emulsion for an onshore oil field in Japan. The factors investigated on the influence of emulsion stability were oil and brine compositions, content of asphaltene, wax and toluene-insolubles, temperature, shear-stress, and water-cut. The results showed the emulsion was stabilized by multiple factors, indicating that multiple preventative approaches are required to sustain stable production, free of emulsion.
The Impact of Pore Structure on Carbonate Stimulation Treatment Using VES-Based HCl
Authors: Sibarani Tiurma Theresa , Ziauddin Murtaza , Nasr-El-Din Hisham A. , Zakaria Ahmed S. 
Published: October 2018

Abstract
This study investigates the performance of viscoelastic surfactant (VES)-based HCl stimulation fluids as a function of carbonate rock type and quantifies the response of the acid to different pore-structures. A pore-structure evaluation during stimulation design could lead to a successful field treatment.
Coreflood tests were conducted using several types of limestone cores with permeabilities ranging from 2.5 to 155 md. Intergranular pores were dominant in the Indiana limestone and Austin chalk samples investigated, whereas moldic pores were dominant in the Pink desert, Edwards yellow, Winterset, and Edwards white cores. Tracer experiments characterized the pore structure in each carbonate sample, and the tracer fluid was injected at 5 cm3/min and 75°F into the cores with dimensions of 6 in. length and 1.5 in. diameter. The tracer effluent data was used to measure accessible porosity (flowing fraction) for each core sample. After the tracer, the VES acid was injected at rates from 1 to 10 cm3/min and 150°F to determine pore volume to breakthrough (PVbt). The wormhole patterns were analyzed using computed tomography (CT) scan images, and the pattern complexity was examined by fractal dimension analysis.
A better pore connectivity showed for Indiana limestone compared to Edwards yellow, Winterset limestone, and Edwards white. The flowing fractions were 1, 0.86, 0.61, and 0.53 for Indiana limestone, Edwards yellow, Winterset limestone, and Edwards white, respectively. The PVbt of Indiana limestone ranged from 0.62 to 0.92. Cores with lower pore connectivity, such as Edwards yellow, had PVbt ranging from 0.52 to 0.81, Winterset limestone from 0.34 to 0.49, and Edwards white from 0.21 to 0.36. These results revealed that higher flowing fractions are required with a higher PVbt. Rocks that have the same dominant pore-structures usually exhibit similar wormhole behavior.
Prior to this study, the performance of VES fluids had only been studied on carbonate rocks with well-connected intergranular porosity. The results of this study show that porosity distribution of the rock affects the response to acids.
Fines Migration as an EOR Method During Low Salinity Waterflooding
Authors: Al-Sarihi Abdullah , Zeinijahromi Abbas , Genolet Luis , Behr Aron , Kowollik Patrick , Bedrikovetsky Pavel 
Published: October 2018

Abstract
This study presents a novel mechanism of enhancing oil recovery by fines migration during low salinity waterflooding. Formation damage is isolated from other low salinity mechanisms in the experimental tests performed in this work. Therefore, the reduction in residual oil saturation is attributed to fines migration mechanism only that is caused by improved microscale sweep efficiency via water flux diversion due to fine particles straining. Corefloods were performed on Berea cores with high clay content, Bentheimer cores with low clay content, and artificial clean sand cores with no clay to investigate the effect of clay presence on residual oil saturation. HSW and LSW took place after drainage displacements that resulted in the same initial conditions of connate water saturation and oil relative permeability. Non-polar oil is used to ensure water-wetness in the cores and to avoid possible wettability alteration by low salinity waterflooding. Single phase corefloods were also performed to study the effect of piecewise decreasing salinity on permeability. The results show a permeability decline with low salinity water injection in the single phase tests of clay-rich cores accompanied by fine particles production and pH increase. The same effect is observed in the two phase tests. In addition, incremental oil production is observed along with the permeability decrease and fines production. This is due to detachment of clay particles by weakened attraction as a result of LSW, which leads to fines migration and straining in water filled pores. Therefore, water flux diversion into trapped oil pores takes place, which displaces the residual oil in these pores. A relationship between formation damage, βΔσ, and residual oil saturation has been introduced and it can be applied in reservoir simulation for LSW.
Numerical Simulation of Well Production Performance Considering Pre-Darcy Flow Using EDFM
Authors: Xu Jianchun , Sun Baojiang , Zhang Wei , Cheng Hongjie , Fu Weiqi 
Published: October 2018

Abstract
Numerical simulation of well production performance for tight oil/gas reservoirs is a hot issue during recent years. Embedded discrete facture model (EDFM) is an effective numerical simulation tool as its advantages and becomes popular. Now it is widely used in multistage fractured horizontal well performance prediction. In this paper, we will extend EDFM to study the well production performance when considering Pre-Darcy flow. Firstly, the two phases flow model is established. The conservation equations are derived for different media, i.e., fracture and matrix. For the flow in fracture, the Darcy's law is used. In the matrix, the Pre-Darcy flow is considered. Then, the solution workflow is showed and the verification is presented. The simulation results of the extended model are compared with that of local grid refined (LGR) method. Finally, the test cases are presented. We show the difference of oil/water production rate when considering Darcy flow and Pre-Darcy flow. The pressure and saturation distribution are also compared. The results show big difference will happen when using different flow model.