bluuebunny/crossref_metadata_2025_split huggingface dataset:
Understanding Shale Petrophysics Helps in Drilling Stable Boreholes: Case Studies
Authors: Al-Arfaj Mohammed , Al-Kharaa Hamad 
Published: October 2017

Abstract
Drilling stable boreholes in shale formations can be a very challenging task when water-based drilling fluids are used. The interactions between water phase in drilling fluids with shale rocks cause different drilling problems such as shale swelling and dispersion. The extent to which a shale sample swells or disperses depends on the clay content of the shale. Some types of clay have more swelling tendency while others have more dispersion tendency. Therefore, identifying the type of clay present in a shale rock is very important for developing drilling fluids capable of mitigating shale drilling problems.
Gama ray data is a powerful tool to predict the clay mineralogy, determine shale reactivity and, as a result, predict the rock response when contacted by drilling fluids. Using petrophysical properties to characterize shale can help determine the appropriate drilling fluid and shale inhibitor to be used. The spectral gamma ray log has been used to determine the proportion of the radiation coming from potassium, uranium and thorium. The ratio of K/Th is utilized to identify clay mineralogy for different shale formations. In addition, formation density log data was utilized with neutron log to give more accurate information about lithology.
The objective of this study is to discuss how petrophysics data of shale formations can be utilized to improve and optimize drilling practices to achieve the ultimate goal of enhanced wellbore stability. Depending on clay content, different shale formations have different responses when exposed to drilling fluids and, therefore, it is of high importance to characterize the shale formation to develop the appropriate drilling fluid.
Characterising the Dependence of Coal Permeability to Methane Adsorption, Pore Pressure and Stress: Laboratory Testing of Walloon Coals from the Surat Basin
Authors: Bottomley W. , Furniss J. P. , Raza Shabbar Syed , Ge Lei , Rudolph Victor 
Published: October 2017

Abstract
This paper discusses a set of laboratory experiments on coal core samples, which seek to understand the changes in coal fracture permeability with varying confining stress, pore pressure and methane adsorption. Currently, no measurements exist to support QGC'sSurat Basin Coal Seam Gas (CSG) development, and therefore themagnitude of change in permeability relative to initial conditions is unknown.
The set of experiments described here use a flow apparatus to measure the permeability of coal core samples as a single variable is changed. The ability to control the laboratory test to separate out the different variablesis an improvement on inferring coal permeability variations from well test data, which isaffected by multiple unknown variables at the same time.
Four separate experiments have been carried out. The first investigated the impact of higher burial pressures on permeability, a four-fold reduction in permeability was measured with confining pressure increase from 150-750psi. The second replicated the reduction in pore pressure during dewatering the intention was to measure ‘stress-dependent permeability’, a halving of permeability was observed with pore pressure reduction from 220-30psi. The final two experiments used methane gas to investigate the effect of coal shrinkage with changing pore pressure. Under constant stress conditionspermeability halved and under constant volume conditions permeability saw a significant fifteen-fold reduction.
Focus on the resulting magnitude of permeability change is more important at the current stage of this study than the absolute permeability change. The magnitude of permeability change can be used assensitivity in numerical simulation studies toassess the impact of pressure dependency of coal permeability and therefore better characterise coal reservoir behaviour and, consequently, improve the accuracy of any forecast derived from the reservoir model.
Revisiting EOR Projects in Indonesia through Integrated Study: EOR Screening, Predictive Model, and Optimisation
Authors: Hartono A. D. , Hakiki F. , Syihab Z. , Ambia F. , Yasutra A. , Sutopo S. , Efendi M. , Sitompul V. , Primasari I. , Apriandi R. 
Published: October 2017

Abstract
EOR preliminary analysis is pivotal to be performed at early stage of assessment in order to elucidate EOR feasibility. This study proposes an in-depth analysis toolkit for EOR preliminary evaluation. The toolkit incorporates EOR screening, predictive, economic, risk analysis and optimisation modules. The screening module introduces algorithms which assimilates statistical and engineering notions into consideration. The United States Department of Energy (U.S. DOE) predictive models were implemented in the predictive module. The economic module is available to assess project attractiveness, while Monte Carlo Simulation is applied to quantify risk and uncertainty of the evaluated project. Optimization scenario of EOR practice can be evaluated using the optimisation module, in which stochastic methods of Genetic Algorithms (GA), Particle Swarm Optimization (PSO) and Evolutionary Strategy (ES) were applied in the algorithms. The modules were combined into an integrated package of EOR preliminary assessment. Finally, we utilised the toolkit to evaluate several Indonesian oil fields for EOR evaluation (past projects) and feasibility (future projects). The attempt was able to update the previous consideration regarding EOR attractiveness and open new opportunity for EOR implementation in Indonesia.
Prediction and Analysis of PDC Bit Downhole Behavior Provides Insights and Efficiencies for Directional Drilling
Authors: Cuillier B. , Al-Enezi D. , Goswami B. , Al-Salamin M. , Al-Shelian J. , Sayed S. , Mikhail B. , Genidy E. El , Reboul S. 
Published: October 2017

Abstract
PDC bit designs for directional drilling typically sacrifice penetration rate for steering performance, resulting in a higher cost per foot. This paper discusses a process for modeling the drilling behavior of PDC bits, insights gained regarding bit efficiency when steering with various motorized and non-motorized rotary steerable systems (RSS), and field experience with the resulting bit design.
Prediction and analyses of PDC bit behavior used a bridgeable software platform to integrate various design applications. This allowed the combined analyses of performance objectives and criteria, including cutting structure, rock type, application, well profiles, drives, and 3D contact. Simulations were then run to examine the performance of different cutting structures relative to various drilling parameters, and matched to a specific drive system. An optimized PDC bit design was developed and manufactured, and its field performance was compared to the model and to PDC bit performance in offset wellbores.
The optimized design was manufactured in a 6 1/8-in PDC bit and run on motorized and non-motorized RSS. It resulted in significant ROP increases and a lower cost per foot compared to offset wells, while retaining a high level of steering response. In one well, the ROP was increased to 48.43 ft/hr versus a target of 35 ft/hr based on offset performance. The resulting cost per foot was reduced from $11.40 KD to $8.59 KD.
The paper examines bit performance and dull condition for the runs and compares them with offset runs. Field performance results validate the bit design modeling and simulation process, and emphasize the importance of integrating various performance analyses to improve bit efficiency without degrading critical steering characteristics.
Extensive development of cutting structures that "drilled on paper" combined with full scale bit laboratory testing has resulted in the development of a design process that combines multiple design objectives and criteria to model and simulate bit behavior during drilling. As shown by field results, this process of balancing the design provides the means to optimize overall performance and lower costs for many different bit applications.
Monitoring Imbibition of Water Into Shale Pore System: State of the Art
Authors: Al-Arfaj Mohammed , Al-Osail Mohamed , Sultan Abdullah 
Published: October 2017

Abstract
To understand the interactions between shale rocks and aqueous drilling fluids, the spontaneous imbibition of water phase into shale pore systemsneeds to be investigated. It is important to study the shale-fluid interactions to mitigate problems associated with drilling shale formations using water-based drilling fluids. Spontaneous imbibition experiments have been frequently conducted to assess the flowback and recovery for reservoir engineering applications. In this paper, the literature has been reviewed in an attempt to link the work that has been carried out in that area to study the water filtrate invasion of drilling fluids into shale rocks while drilling.
Over the years, different techniques and instruments have been used to study the spontaneous imbibition into shale rocks including: spontaneous imbibition device, which is basically analytical balance to measure the weight changes as imbibition progresses, pulse decay permeameter, scanning electron microscopy, X-ray tomography and nuclear magnetic resonance. To aid in analyzing and interpreting the results, the rocks are characterized in terms of: surface area, porosity, permeability and wettability. Fluids that have been used as the imbibing medium included: water, oil, brines, and surfactants.
Three imbibition mechanisms have been revealed by literature: capillarity, osmotic diffusion, and water adsorption. These mechanisms can be distinguished when imbibed water volume is plotted against time where the imbibition rate differs for three distinct regions. Factors that were found to have impact on imbibition process include: capillary pressure, porosity, pore size distribution, pore connectivity, effective permeability, presence of fractures, bedding, mineral composition and clay content, fluid type, and properties and depositional environment (marine or continental).
Integrated Approach in Determining Residual Oil Saturations to Water Sorw and its Impact on Potential Enhanced Oil Recovery EOR Volume Estimation
Authors: Murugesu Thanapala S , Masoudi Rahim , Johare Dzulfadly B. , Jalan Shlok , Marzuki Izral Izarruddin 
Published: October 2017

Abstract
Residual oil saturation (Sor) is defined as fraction of pore volume occupied by oil at the end of the oil displacement by a specific fluid. It signifies the ultimate recovery under a given displacement process and represents the endpoint of the relative permeability curves in reservoir simulation. The estimation of Sor is critical in understanding the behavior of the reservoirs during various recovery mechanisms and it is a very important measure used to decide the EOR process selection and feasibility for further exploitation of the reservoir.
The residual oil saturation varies depending on lithology, pore size distribution, permeability, wettability and fluid characteristics. There are several ways to estimate the Sor including core analysis methods, well log methods, and other saturation and volumetric assessment methodologies. However, none of the methods is regarded as a single best method for determining the Sor. In addition, there could be circumstances that the remaining oil saturation (ROS) is misinterpreted as Sor. The integration of various data sources is therefore critical in estimating the true residual and remaining saturations.
This paper highlight number of offshore field case studies where significant difference observed in Sorw estimation using various approaches from core and logs analysis. In these examples, SCAL data and logs in hydrocarbon column as well as swept intervals together with the wells/reservoir performances have been considered in estimating the Sor. It was observed that the production forecasting, reserve estimates, EOR mechanism are hugely affected by the Sorw estimation.
Water Control of Horizontal Wells Using Foam-Gel: Lessons Learnt in a Heavy Oil Reservoir with Strong Waterdrive
Authors: Deng Bo , Liu Wei 
Published: October 2017

Abstract
As technology advances in horizontal well drilling, long horizontals completion are now preferred for producers aiming to explore more oil-bearing zones, especially in heavy or tight oil reservoirs. However, for strong waterdrive horizontal wells, abrupt increase of water-oil ratio and abounding unwanted water production severely affect the profitability of the field due to the constant decrease of oil production and premature well shutting.
The targeted reservoir of this work is a typical heavy oil reservoir with strong waterdrive. By December 2014, the average water cut for the two productive layers has increased 40-70%, for some wells especially, the water cut has exceeded 95% causing frequent well shutin. Therefore, to ensure the productivity of the horizontal wells, water shutoff has become a challenging and urgent task.
According to the aquifer identification and water influx diagnosis, 27 horizontal wells distributed in aforementioned two productive layers were first categorized into two groups in order of treatment difficulties, after which foam-assisted gel and gel treatments were designed and conducted.
For the three of the treated wells, the average water cut was significantly reduced from 80.3% to 48.0%. Although the gross liquid production rates were slightly reduced after treatment from 31.7 to 27.7 t/d, the oil production rate was considerably increased by 28.1 t/d. By January 2016, 4 500 t of the incremental oil was produced indicating the success of the water shutoff jobs. However, it should be noticed that the water cut of the N2 foam-assisted gel treated well started to rapidly rise after two months. This is probably caused by inappropriate foam/gel volume ratio. The water control strategies and field results in this heavy reservoir will provide the necessary clues for the design and application of water shutoff treatments for horizontal wells driven by strong water.
Development and Operational Implementation of Scale Management Strategy in a Mature Field
Authors: Tiwari Amitosh , Fartiyal Prashant , Malik Ankit , Sharma NeelMani , Manickavasagam Chandran , Lele Sarang , Sharma Aastha , Sabhapondit Anindya 
Published: October 2017

Abstract
Calcite scaling is a major production challenge in many mature oil fields. One of the most effective manners to control calcite scaling losses is to predict the scaling behavior in the wells using thermodynamic models and then use prediction results to build an operational program to control scaling in the field using a combination of effective acid washes and scale inhibitor (SI) injection. This paper presents a case study from a mature oil field and details the operational facets of scale prediction and control program. It describes both operational challenges as well as cost optimization involved in program implementation in the field.
There are three major aspects which are discussed in this paper. First part deals with selection of right scale inhibition chemical for a field. It details laboratory experiment that was used to select the most appropriate chemical for the field. Also, this section describes the hardware infrastructure that should be in place to ensure effective implementation.
Next section deals with the trial of chemicals, selected from lab analysis, in actual field conditions. Impact of scale inhibitor in controlling scaling within the tubing and flowarm of the wells is discussed. Secondly, benchmarking of new scale inhibitor chemical performance against the existing chemical is also presented in this section. This formed the technical basis for change in existing scale inhibitor and going for full fledged implementation in the field.
Final part of the paper details field-wide implementation of scale inhibitor injection and chemical performance monitoring program. Critical parameters for chemical performance monitoring and field data on chemical dosage optimization using these critical parameters are presented. This section also presents several case studies showcasing impact of scale inhibitor injection on the well performance.
This scale management approach has not only helped in terms of reducing production losses but also assisted in improving safety performance. Field data, highlighting the impact of scale inhibitor in significantly reducing the scaling in the wells, is shared in this paper. Post implementation of this program, asset has been able to reduce its scaling related production losses significantly (~90% reduction in less than 2 years).
Once an oil field enters decline phase of its life cycle, reservoir pressure drops and water cut increases – conditions which favor high scaling behavior in the wells. Thus, scaling related losses presents a serious challenge in controlling production decline in a mature oil field. By adopting the operational practices shared in this paper, many mature oil field can benefit by reducing scaling related losses.
Characterisation of Readily Bioavailable Compounds in Surat Basin Walloon Coals for Biomethane Production Using Exogenous Culture
Authors: Chen Tianyu , Hamilton Stephanie , Rodrigues Sandra , Golding Suzanne D. , Rudolph Victor 
Published: October 2017

Abstract
This experimental study aims to characterize the bioavailability of six Surat Basin Walloon coals to exogenous methanogenic consortia, and the possible compositional and environmental factors that control bioavailability. Finely crushed coal cores samples were inoculated with digested sludge culture sourced from domestic wastewater treatment plants in biomethane potential bottles (BMP bottles) maintained at mesophilic temperature. Degradation of coal compounds was demonstrated via GC-MS characterization of methanol and dichloromethane (DCM) extracts of coals, as well as analysis of volatile fatty acids and alcohols and total dissolved organic carbon (TOC) in water eluents of coals conducted before and after biodegradation. The resulting methane yields ranged from 14 to 33 μmol/g, with an average of 21 μmol/g (0.515 m3/t) achieved within 30 days. Organic solvent-extractable materials accounted for 3.8 to 12% of coal weight. Aliphatic compounds, primarily medium-long-chain n-alkanes, n-alcohols and esters dominated the solvent extracts. Aromatics were detected up to three fused rings, and are rich in dibenzofuran, alkyl benzene, alkyl polyaromatic hydrocarbons, and acetyl diphenyl. The abundance of solvent-extractable matter was found to rely on liptinite content, particularly suberinite. Preservation of these compounds was thought to be facilitated by vitrinite, such as telinite and collotelinite that are rich in micropores, serving as storage for the hydrocarbons. On the other hand, environmental factors, such as microbes-carrying groundwater might compromise coal extractability by converting coal hydrocarbons to biogas. The study has revealed three levels of dependence regarding coal bioavailability: 1) Water solubility - An average 98% of aqueous compounds (based on TOC) was eliminated via biodegradation. These were mainly volatile fatty acids and alcohols, and to a lesser degree, medium-chain n-alcohols, esters and aliphatic amine; 2) Solvent extractability – approximately 35% of solvent-extractable compounds were biodegraded on average, with aliphatics being more bioavailable than aromatics; 3) Heterogeneous moieties, particularly aliphatic hydroxyl, ester bond, ether bond and C-N bond in aliphatic amine - These functional groups are characteristics of compounds that were heavily degraded. The study is to our knowledge, the first coal bioavailability research that demonstrated a detailed linkage between biomethane generation and bio-elimination of coal extractable compounds with connections to petrographic composition and possible environmental factors.
Enhanced Efficiency in Deep Water Testing Operations Delivered by Smart DST String
Authors: Amir Shah Jayachand , Aminuddin Mior , Fatah Al , Fyfe D. , Justin Metrol 
Published: October 2017

Abstract
This paper discusses the smart Drill Stem Test (DST) string, run for a Deep Water (DW) well test operation, which enabled considerable saving of rig time, reduced risks, and provided best reservoir data quality, while performing a commingled DST in a single run. Evaluation of the zones was made without any wireline intervention runs such as Production Logging Tool (PLT) or Surface Read Out (SRO). Acoustic telemetry provided seamless access to downhole data, including production profiles from both zones, throughout the DST operations.
This paper will help the well testing fraternity conduct well test operations efficiently and safely in a deep-water environment using new technology tools and innovative methods. Well testing costs and risks can be reduced significantly.
The smart DST string, run in hole (RIH) for the DW well test, consisted of a combination of conventional DST tools, a new generation packer and below packer, acoustically operated tools including: Acoustically Operated Sliding Side Door (SSD) - provided access to the reservoir for Well Kill Operations after the standalone screens became plugged with unconsolidated sand and Loss Control Material (LCM) pills.Multiple Discrete Temperature Sensor Array - Eliminated the requirement of running a conventional PLT to evaluate the commingled flow of two zones, provided valuable production logs, and resulted in unexpected, additional information evident from the thermal transient data.Acoustically Activated Bottom Hole Samplers - collected bottom hole samples selectively, at different drawdowns, without wire line intervention or without applying annulus pressure.Wireless Gamma (GR) Depth Correlation Tool - Provided accurate TCP gun placement, without running a conventional wireline GR/CCL, by using a tubing conveyed Gamma Ray logging tool; results were collected wirelessly in less time than a conventional wireline run.New Generation Packer -The large size 9-5/8" Hydraulic Set Retrievable seal bore type packer was used for the first time by the company. This is a most suitable packer for DW DSTs, which eliminated the requirement for slip joints, drill collars and safety joints or the running of a permanent packer, which would have required multiple trips and restricted the gun size.