bluuebunny/crossref_metadata_2025_split huggingface dataset:
Screening of Nanoparticles to Control Clay Swelling in Coal Bed Methane Wells
Authors: Patel Archana , Goh Clarice , Towler Brian , Rudolph Victor , Rufford Thomas E. 
Published: November 2016

Abstract
The swelling of smectite clays in the interburden rock layers of coal seam gas wells results in spalling of fine particles that may negatively impact gas production through damage to the well's pump and/or the permeability of the coal layers. One of the causes of the clay swelling is the change in water chemistry at the wellbore location due to drilling fluids and the influx of produced water. The conventional technology to mitigate the swelling of smectite clays in oil and gas reservoirs is to stabilize the clay using a brine such as 4 % KCl, and although this technology is relatively low cost and initially effective the mitigation of clay swelling is temporary because K+ ions are easily washed from the clay when the well is brought into production. An alternative approach recently reported is to use nanoparticles and nanofluids to control clay swelling.
In this laboratory study we evaluated the effectiveness of five commercially available nanoparticles – SiO2, Al2O3, ZnO, Fe2O3, and ZrO2 – to prevent swelling of a natural bentonite clay that was rich in sodium montmorillonite. The effectiveness of the nanoparticles to prevent clay swelling was measured with a visual swelling index method based on ASTM D5890-11 and compared to the swelling of the clay in 4 % KCl brine. In the initial nanoparticle screening tests performed in distilled water all the nanoparticles except for the ZnO exhibited some potential to mitigate the swelling of bentonite. The next stage of screening experiments was performed in model formation water solutions containing 2500 mg /L and 9000 mg/L of Na ions at pHs of 5 and 9. In the model formation water tests, the SiO2 was the most effective nanoparticle to mitigate clay swelling across the range of conditions examined.
These experimental results suggest nanoparticles may be a potential solution to mitigate clay swelling and spalling in coal seam gas reservoirs as well as other types of reservoirs. Further research is required to elucidate the mechanism of swelling inhibition with SiO2 nanoparticles and to develop practical methods to deploy nanoparticles into a CSG well.
A Comprehensive Approach for the Development of New Magnetite Nanoparticles Giving Smart Drilling Fluids with Superior Properties for HP/HT Applications
Authors: Vryzas Z. , Zaspalis V. , Nalbantian L. , Mahmoud O. , Nasr-El-Din H. A. , Kelessidis V. C. 
Published: November 2016

Commercial hematite (Fe2O3) and magnetite (Fe3O4) nanoparticles (NPs) had been used as additives to develop smart drilling fluids. Both types of NPs were found to enhance the properties of such fluids. This work focuses on using a custom-made (CM) magnetite (Fe3O4) NPs to improve the properties of bentonite-based fluids. The microstructure qualities and mode of interaction have indentified, which help in optimizing the rheological and fluid loss properties of drilling fluids.
Rheological properties of the tested fluids were measured using a rotational viscometer at different temperatures up to 60°C (140°F) and atmospheric pressure. Step-change shear rate measurements revealed the degree of thixotropy of the produced suspensions. Fluid loss characteristics were examined under 20.7 bar (300 psi) and 121°C (250°F). Both rheological and fluid loss measurements were also conducted using fluids that are thermally aged at 177°C (350°F) for 16 hrs. Filter cake surface morphology was evaluated using scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS). Bentonite composition was examined by X-ray diffraction (XRD) and X-ray fluorescence (XRF). A superconducting quantum interference device (SQUID) magnetometer was used to measure the magnetic properties of the CM Fe3O4 NPs, and their size was determined using transmission electron microscopy (TEM).
The CM Fe3O4 NPs, which were synthesized by co-precipitation method, have average diameter of 6-8 nm, as indicated by TEM. Magnetic measurements revealed their superparamagnetic behaviour with saturation magnetization of 60 emu/g. For all the tested samples, the Herschel-Bulkley (HB) model was determined to be the best fit model with good correlation coefficient (R2 &gt; 0.99). Yield stress, viscosity, and gel strength of the tested fluids showed significant improvement when adding the CM Fe3O4NPs, which could be a result of the rigid network formed. A linear dependence of yield stress on temperature of the produced nanofluids (NF) was identified. Adding the CM Fe3O4 NPs at 0.5 wt% showed optimal rheological and filtration characteristics. Dynamic thermal aging adversely affects the properties of base fluid. However, the NF maintained its extraordinary rheological and filtration behavior. SEM-EDS analysis revealed the microstructure of the produced filter cake.
The better performance of the CM Fe3O4 NPs can be attributed to their extremely small size, which confer stability in suspensions and effective linking with the bentonite particles, thus allowing the formation of a rigid microstructure network. Such approach introduces the synergistic interaction of components to produce a water-based drilling fluid system with excellent fluid loss characteristics and optimal rheological properties for HP/HT applicaltions.
Novel Coiled Tubing Perforation Approach Enables Efficient Multistage Hydraulic Fracturing Operations in a Horizontal Well in Oman
Authors: Al-Ghaithi Ali , Alawi Fahad , Sayapov Ernest , Ibrahim Ehab , Aouchar Najet , Jumaat Shafie 
Published: November 2016

Abstract
The global horizontal well fracturing market has grown tremendously in the last decade with the increase of multistage fracturing operations. Many of these wells are cased and cemented and had a sequence of a plug and a series of perforations for each stage of the fracturing process. Intervention optimization became a key element for work efficiency and thus cost reduction. A common approach worldwide is to pump-down the plug combined with a few guns and initiate the firing downhole sequentially using switches. Despite the efficiency of this technique, it requires an overflush after each fracturing stage to clean the wellbore of leftover proppant and allow free passage of the plug and guns to be pumped down. Unfortunately, overflushing hampers the fracture's performance because it allows the fracture to close near the perforations. This effect on productivity is now being realized on these overflushed wells, although these wells were once constructed very efficiently.
To move away from overflushing, some operators switched from pump-down to coiled tubing (CT) conveyance of the multiple guns. Conventional CT or CT with electric wireline were used, and each technique has its own advantages and limitations. A newer technology is CT equipped with fiber optics in combination with an optic-based selective perforating system that enables the firing of multiple guns in a single run. This technology combines the advantages of both the conventional CT and the CT equipped with wireline cable. Equipped with gauges, the CT equipped with fiber optics also permits better acquisition of fracture data in horizontal wells. The result is a more efficient operation, better fracture evaluation, and well productivity enhancement by avoiding the damaging effect of overflushing.
After an evaluation of current conveyance techniques, an implementation trial of the new technology on multiple fracturing stages was performed in a horizontal well in Oman. The first trial showed successful application of the technique, especially the accurate real-time gamma ray and casing collar locator (GR-CCL) correlation of the multiple short guns. Even more important was the successful placement of the proppant into the formation during the hydraulic fracturing process. The technique was shown to be efficient while mitigating the possible damage to the formation.
Development of New Formulation of Geopolymer Cement for Oil Well Cementing
Authors: Suppiah Raja Rajeswary , Rahman Siti Humairah Abd , Irawan Sonny , Shafiq Nasir 
Published: November 2016

Abstract
In this paper, we report the results of the investigations on the effects of sodium hydroxide (NaOH) concentration and different ratio of silicate to hydroxide on the density, rheology and compressive strength of geopolymer cement system used in oil well. Different ratios of Class F fly ash is mixed with different ratios of sodium silicate to sodium hydroxide ratio (2.5, 1, 0.5 and 0.25) to produce different geopolymer slurry densities and dispersant is added to control the rheological properties of the system. The NaOH solution was prepared by diluting NaOH pellets with distilled water according to the specified molarity (8, 10, 12 and 14 M). The solution was then mixed with sodium silicate to form the alkaline solution. Class F fly ash were added to the reactive to form homogeneous mixture, which was tested for its density and rheological properties at surface temperature. The mixture was placed in a 50 mm mould and cured at 930C and 3000 psia for 24 hours and the cubes were tested for destructive compressive strength. The results showed that as the concentration of sodium hydroxide increases, the density of the geopolymer cement increases. There was no significant variation on the density of the geopolymer cement. Also, as the ratio of silicate/hydroxide increases, the viscosity of the slurry increases and the workability of the geopolymer cement become poorer. Furthermore, the compressive strength increases as the NaOH molarity increases however when it reaches 14M, the adverse effect to the strength development was observed.
Real-Time Directional Survey Quality Improvement Using Web-Based Technologies
Authors: Maus Stefan , DeVerse Shawn 
Published: November 2016

Abstract
Optimal wellbore placement and collision avoidance requires accurate real-time steering of directional wells. Uncertainties in the wellbore position are accounted for by industry standard error models. However, these error models are only valid if the directional surveys are quality controlled and gross error is prevented by appropriate procedures. Particularly effective quality control is achieved by independent validation. A novel real-time web application was developed for the transfer of directional survey data between the rig site and a remote operations center. Surveying professionals at the rig site upload or import survey data into the web application in real-time. The survey measurements are then automatically validated through independent quality checks to identify gross error. Remote survey analysts can access the pre-qualified survey data and evaluate it for systematic or random error that would indicate non-compliance with the instrument performance model. Surveys can also be corrected in real-time when systematic error is identified and provided back to the rig site personnel for accurate steering and wellbore placement. This web service has been implemented and refined on over 50 rigs in North America. Examples for common types of errors that were prevented and/or corrected are incorrect magnetic declination, wrong north reference, excessive drillstring interference, poor instrument calibration, sensors misaligned with the wellbore and incorrect survey order. The impact of these errors if not prevented could easily cause 100 ft. or more in positional error at the bottom hole location. Real-time survey quality analysis provides higher confidence in wellbore placement, reduces risk of collision, and maximizes reservoir drainage.
Brittleness Index Prediction From Conventional Well Logs in Unconventional Reservoirs Using Artificial Intelligence
Authors: Shi Xian , Liu Gang , Jiang Shu , Chen Lei , Yang Liu 
Published: November 2016

Abstract
Brittleness index is one of the critical geomechanical properties of reservoir rocks. In fact, it is not possible to have accurate solutions to evaluate hydraulic fracturing effectiveness without having accurate brittleness value. Different methods were proposed to measure this parameter, which some of them need reservoir geomechanical parameters by tri-axil experiments, and some others such as mineral analysis are very expensive. Elastic based brittleness is commonly applied because it can provide continuous profile but S wave is generally not performed in all wells. Therefore, attempts have usually been carried out to use artificial intelligences for identification of the relationship between the well log data and core mineralogy based brittleness. This study proposed a new approach based on two common neural network approaches by conventional logging data. The mineral based brittleness database from one well in Jiaoshiba shale gas filed, China were established through QEMSCAN and X-ray diffraction (XRD) analysis. Construction of back propagation artificial neural network (BPANN) and least squares support vector regression (LS-SVR) for predicting formation brittleness is described. Moreover, an overall ranking of sensitivity degree is then provided to show the impacts of different well logs as inputs on models. Obtained results of both LS-SVR and BPANN model are competent for predicating brittleness. But, LS-SVR approach is more accurate than the BPANN method at same conditions. These artificial intelligence methods are first adopted in formation brittleness prediction and the integration of core mineralogy based brittleness and well logs is more practical and applicable than elasticity-based brittleness method using acoustic full waveform logging.
Reducing Drilling Operational Risk and Non-Productive Time Using Real-Time Geomechanics Surveillance
Authors: Hamid Osman , Khan Khaqan , Rahim Zillur , Omair Ahmed , Ahmed Sajjad , Ahmed Mujahid 
Published: November 2016

Abstract
Mud weight optimization is a key driver in attaining optimum wellbore stability while drilling horizontal wells. This paper demonstrates the role of geomechanical knowledge prior to and while drilling to address wellbore stability related issues to help reduce drilling risk and non-productive time (NPT).
To maximize gas production from a tight carbonate reservoir, horizontal drilling and multistage hydraulic fracturing methods have been adopted. For several wells, maintaining wellbore stability has been a challenge without prior geomechanical knowledge of the field resulting in undesired drilling events such as tight hole excessive reaming, stuck pipe, and difficulties while making trips. Even in wells with pre-drill geomechanical analysis for mud weight recommendations, uncertainty in the pore pressure due to depletion along the horizontal section of the wellbore, drilling with one recommended single mud weight (MW) posed great challenge to manage wellbore stability.
In this paper, statistical analysis of data is used to investigate root causes of wellbore stability related issues for a number of horizontal wells drilled in the direction of the minimum horizontal stress. The analysis suggests that wells drilled with little understanding of geomechanical properties along the wellbore path encountered significant NPT's compared to those wells where understanding of rock mechanical behavior and in-situ stresses was utilized to make recommendations prior to drilling. In some cases it helped reduce NPT to less than 2% even in exploration wells.
Among the successful wells, results from a case study describing the real-time (RT) geomechanics workflow was used to optimize MW enabling drilling the well to the planned target depth. The uncertainty related to pore pressure and intervals of high porosity which creates a significant risk of differential sticking were addressed by incorporating RT data and updating wellbore stability models and providing recommendation to the field operation. The paper demonstrates the role of geomechanics and its impact to drilling operations aimed to reduce operation cost and increase drilling efficiency by eliminating geomechanics-related wellbore stability problems.
Recovery of Transport and Geometrical Properties of a Hydrocarbon Reservoir by Statistical Analysis of Microtomographic Images of Core Samples
Authors: Bazaikin Y. , Gurevich B. , Lebedev M. , Khachkova T. , Kolyukhin D. , Lisitsa V. , Tcheverda V. , Merzlikina A. 
Published: November 2016

Abstract
Due to the apparatus restrictions the resolution of the micro-CT scans of rock samples and the size of the 3D image are strictly connected. Thus improve in the resolution giving more detailed representation of the rock structure reduce the size of the sample, so that it goes below the representative volume for the estimation of a particular property. In this paper we study four 3D images of different resolution of Bentheimer sandstone. We show that the geometrical and statistical properties of the images (pore-to-core distribution, porosity, specific surface area, topology) can be stably reconstructed from the images of about 100 voxels. However, numerical estimation of the physical properties, such as permeability, requires larger images. To overcome this difficulty we suggest using statistical simulation of the sampels, based on the stably recovered information – image properties. In this paper we considered the simplest method of statistical simulation; i.e. truncated Gaussiam technique, which is based on the information about the total porosity and correlation length of pore-to-core distribution. This approach underestimates the specific surface area of the pore space, but the permeability of the sample was matched accurately.
Extracting the Best Value from Mature Fields by Petroleum Geoengineering
Authors: Yin K. Yin , Masoudi R. , Rajput S. , Kandau Flavia , Amat Hadi B. , Ring M. , Bertoldi Luca , Ismail S. 
Published: November 2016

Abstract
The success of extracting the best value from mature heterogeneous fields to meet global energy challenges is directly linked to innovation and creativity. The development of these fields requires optimized economic models and fit for purpose reservoir depletion strategies. Petroleum geoengineering is the answer to evaluating remaining opportunities and managing the key uncertainties using smart technologies and reducing the risk of development. This paper describes the field example of how a petroleum geoengineering based approach can optimize the fast track development of a marginal fault block within a complex oil field which is located in offshore Sarawak Malaysia.
The advantages of this workflow compared to the conventional field development plan (FDP) approach is that the iterative time consumed in matching the dynamic model and adjusting the geological model has been properly managed. In our case study, this workflow has improved the quality of the technical proposal as well as saving project duration significantly. In accordance to the workflow, the reservoir architecture was interpreted based on seismic interpretation, geological and reservoir performance understanding. Seismic Inversion derived geobodies were then identified as development targets. Better delineation of the main geological features was achieved using a seismic inversion based algorithm. By prioritizing data consistency among geoscientists, geomodellers and reservoir engineers, a fast track field development plan was developed within manageable uncertainties. Greater reliability of inversion results help to avoid perpetuating bias tendencies on data used for model calibration or quality check.
The petroleum geoengineering based study for such oil reservoir shows how an integrated approach enabled time saving for subsurface development concept identification covering range of estimated hydrocarbon volumes. As a result of geoengineering approach in marginal fault block, the technical proposal was completed within 8 months duration.
Application of Geomechanics for Tight Oil Reservoir Characterisation and Field Development
Authors: Kiatrabile T. , Noosri R. , Hamdan M. K. , Kusolsong S. , Palviriyachote S. , Suwatjanapornphong S. , Rattanarujikorn Y. , Sarisittitham S. , Piyajunya T. , Phonphetrassameekul N. , Manai T. , Adisornsupawat K. , Mustapha H. , Press D. 
Published: November 2016

Abstract
The main objective of this paper is to present the assessment and methodology that would improve the tight oil recovery by hydraulic fracturing (HF) wells. The methodology is enabled by a fully integrated workflow orchestrating petro-physical log interpretation, static modelling, and dynamic modelling coupled with rock mechanics for an optimal fracturing design and mitigating the underlying risks.
In the past, well placement in tight reservoirs and HF design were performed mostly based on available analogous data of offset wells using rock mechanics parameters such as stress magnitude and regional stress orientation to predict the fractures that would propagate through the reservoir in a certain location and well orientation, the stress/strain regime is one of the key parameters that plays an important role. It is also the key performance indicator for developing the tight oil reservoir with underlying complexities.
The process is initiated by the conventional static modelling which involves structural framework construction, distributing the petro-physical characteristics subject to the well logs and other available subsurface data. The second step is to perform a history match of a derived dynamic model by honouring the observed data. This process helps in calibrating the model to be able to represent reservoir dynamic behavior. The results of the history matched model; i.e., reservoir pressure through time is the key input for the Mechanical Earth Model (MEM) in the next step. The MEM process starts with the construction of a 1D MEM using well log advanced scanner and rock mechanics properties from laboratory to represent the strength and elastic properties of the rock where existing wells have been penetrated into the reservoir layers. Hence, a coupled dynamic reservoir simulation with 3D geomechanical model will yield a realistic relationship between the current reservoir depletion state in terms of pressure and the current stress strain regime. This relationship is paramount for optimal location indentification of the fracturing wells and corresponding design together with an estimation of the subsequent recovery. Also, the rock mechanic simulation study would yield a comprehensive result with respect to the reservoir mechanical integrity while conducting the hydraulic fracturing operation to increase the well productivity.
This integrated workflow is considered as the key step for tight oil reservoir development, and it can be expanded to unconventional resources for a better reservoir characterisation and reservoir development. The study was performed within close collaboration within the teams with comprehensive know-how sharing and exchange.