bluuebunny/crossref_metadata_2025_split huggingface dataset:
Permeability Computations of Shale Gas by the Pore-Scale Monte Carlo Molecular Simulations
Authors: Li Jun , Sultan Abdullah S. 
Published: December 2015

AbstractThe permeability variation of shale gas with pressure is an important input data in the predictions of well performance for optimizing production. We present a novel pore-scale simulation scheme to accurately compute the permeabilities at different pressure conditions by using the Fortran parallel software NanoGasSim, which was developed with a recent Monte Carlo molecular simulation method (i.e., the DSBGK method that is based on the Bhatnager-Gross-Krook (BGK) equation and has been comprehensively verified against the traditional direct simulation Monte Carlo (DSMC) method). The influence of adsorption layer on the permeability can be considered at each given pressure by adjusting the effective pore space according to the adsorption-layer thickness and specifying a potential moving velocity for adsorption layer. Then, the Klinkenberg slippage effect at high Knudsen numbers (Kn) is accurately modeled in the DSBGK simulations of free gas inside the effective pore space and the permeability can be computed from the steady-state flow velocity distribution. Linear variation of permeability with reciprocal pressure is observed in the range of high Kn with low pressure and the permeability becomes almost unchanged at low Kn with high pressure, where a large number of simulated molecules move inside hundreds of millions of cells and message passing interface (MPI) parallel computations are employed to reduce the computational time. Our computed permeability data can be directly used for industrial applications and also provide a reference to calibrate empirical correlation models as fitting formulas (e.g., the Klinkenberg model) and to validate other pore-scale simulation methods based on artificial corrections at high Kn (e.g., the lattice Boltzmann method).
Flow Regime Prediction Using Fuzzy Logic and Modification in Beggs and Brill Multiphase Correlation
Authors: Rammay Muzammil Hussain , Alnuaim Sami 
Published: December 2015

An accurate prediction of Liquid Hold-up and pressure drop in multiphase flow is required in designing of million or billion dollars surface and subsurface facilities projects in Petroleum industries. These projects include building of offshore Oil and Gas pipelines, Oil and Gas field's process plants, multiphase separators, Oil and Gas wells equipments such as tubing, completion equipments. Therefore accuracy in prediction of Liquid Holdup and Pressure drop has a lot of importance and one of most primarily concerns in petroleum and chemical industries.
Beggs and Brill multiphase flow correlation is one of the most widely used multiphase flow correlations in the industry [19] due to its applicability for horizontal, vertical and inclined multiphase flow modeling. It also takes into account the different horizontal and vertical flow regimes. [4] It uses the general mechanical energy balance and the average in-situ density to calculate the pressure gradient. But due to the complex flow regimes and its wide transition, the method prediction becomes poor in certain practical conditions especially, when flow pattern classification parameters are near to the boundaries of the flow regime limits usually due to the inaccurate prediction of slip liquid hold-up. [18]
In this paper modification to Beggs and Brill correlation is proposed by predicting horizontal pipe flow regime using fuzzy logic instead of the one presented by the correlation. A fuzzy model is designed and tested to predict horizontal pipe flow regime and used in Beggs and Brill Correlation. The fuzzy model developed in this study is made by the technique of "Learning from example", which is basically used for rule base construction in automated methods for fuzzy systems [3]. For this purpose the fuzzy logic toolbox of MATLAB is used [17]. In this new proposed method, mixture Froude number and no slip liquid hold up, which were used by Beggs and Brill correlation for flow pattern calculation, are fuzzified. By using these parameters, the coefficients for liquid holdup calculations in Beggs and Brill correlation are modified and eventually produced by this fuzzy model. The new proposed correlation was verified using sets of published data in [1], [2] to predict flow pattern from no-slip holdup and Froude number. Some datasets in [1] were used to further refine the given fuzzy model, particularly high Distributed and low segregated flow regimes, which were not captured by Beggs and Brill data set.
This new proposed fuzzy model indicated that the generated fuzzy model empirical coefficients improve the liquid hold up prediction, which can improve pressure drop prediction of Beggs and Brill correlation; hence improve the accuracy of this widely used multiphase flow correlation. This fuzzy model outperforms the published models and Beggs and Brill multiphase correlation in terms of the lowest absolute average percent error 12.55 % and 9.94 % for Dataset in [1] and [2] respectively.
Removal of Pyrite and Different Types of Iron Sulfide Scales in Oil and Gas Wells without H2S Generation
Authors: Mahmoud M. A. , Kamal M. , Bageri B. S. , Hussein I. 
Published: December 2015

Iron Sulfide scale is a significant problem in oil and gas industry where the iron sulfide depositions have adverse impact to the production operations. Typically, iron sulfide scale formed as result of the reaction between the hydrogen sulfide and iron. Iron sulfide scale has several forms; pyrrhotite (Fe7S8), troilite (FeS), pyrite (FeS2), greigite (Fe2S4), and mackninawite (Fe9S8). Pyrite, which has good thermal stability, tends to deposit at shallower places downhole and is inert to acid. Other iron sulfides react with acids. Thermal stable species are much harder to be removed by acids. Thus the iron sulfide downhole are mainly pyrrhotite, pyrite, marcasite and mackinawite, in which pyrite cannot be removed by acid treatment. Both pyrite and marcasite have very low solubility in HCl, and the only available method of removal in the oil industry is to mill these types of scale.
In this paper we introduced new formulations that can be effectively used to remove the pyrite and marcasite scales with removal efficiency reaches 85%. The new formulation will not release H2S during the removal of pyrite scale or any other iron sulfide scale as HCl, therefore, no need for H2S scavenger and also no HSE consideration are required during the removal because the new formulation can be considered as environmentally friendly. No need for additives such as corrosion inhibitors because these fluids pH is above 11 and they are not corrosive. The new formulation consists of high pH chelating agents such as DTPA (di ethylene tri amine penta acetic acid) at pH range from 11 to 14 and catalytic or converting agent such as potassium carbonate (K2CO3), (Cesium Carbonate) Cs2CO3, or (Cesium formate) CsCOOH. The optimum concentration of the chelating agents is 20 wt % DTPA and 7 wt% for the catalyst/converter. In the oilfield treatment water wetting surfactant or solvent should be injected first to remove the organic scale that covers the iron sulfide scale and then DTPA/Converting agents can be injected. No gases will be released during the scale removal process and this will not increase the pressure of the well during the treatment process.
Currently the removal efficiency of the pyrite scale type is maximum 20 % by HCl. Using the new formulations the solubility of actual field samples of pyrite reached 85%. The new formulation can be used effectively to remove all types of iron sulfide scales especially those cannot be removed by HCl. One more advantage of the new formulation is that the H2S will not evolve during the treatment and that will cut the cost of safety considerations bedside the cost of H2S scavengers.
Using Free Surface VSP Downgoing Multiples to Obtain Unconventional VSP Image Above the Well Trajectory - A Case Study in Offshore Vietnam
Authors: Dac The Nguyen , Sanders Michael , Ngo Anh Tuan Nguyen , Millot Pascal , Rehman Sadu-ur , Suzuki Katsuko , Lawson Michael , Jeow Foo Say , Tran Van Khanh 
Published: December 2015

Abstract
The Vertical Seismic Profile (VSP) technique is routinely used to create seismic images near the wellbore; traditionally, only the up-going wavefield is used to image the subsurface below the receivers. The standard VSP technique does not provide seismic image information above the well trajectory. The objective of this study was to produce a seismic image above the top receiver depth up to the seafloor by using the downgoing multiples recorded in the VSP data for a more complete seismic-to-well tie.
In VSP acquisition, the seismic source is positioned below Mean Sea Level and deployed above a downhole receiver. The source signal is recorded by a downhole receiver that is moved to cover a large number of depth levels in the well. The upgoing and downgoing arrivals are separated during processing; the up-going wavefield is used for subsurface illumination, whereas the downgoing wavefield and multiples are normally excluded from the processing. The standard VSP technique using the VSP upgoing wavefield gives a seismic image along the range of receiver depths and below the well trajectory. However, a VSP image can also be obtained from the downgoing multiple sequences in deep water.
The processing of sea surface multiple is used mainly to obtain a VSP image of formations above the top receiver depth; such an image is unattainable with the standard VSP technique. Our results show that illumination coverage increases significantly when using multiples versus primaries. In addition, reflectors above the shallowest receiver can be imaged by multiples, including the seabed itself. This can be useful for shallow hazard identification for sidetracks or to avoid the expense of infill nodal seismic below the rig (Farmani et al., 2012). We also show that the image obtained from the VSP multiples can have good resolution comparable to the surface seismic image, with better signal to noise ratio especially for the shallower reflectors. The VSP data is true amplitude, zero-phase, and perfectly tied in depth and in time. In very deep water, the seafloor-sea surface multiple is completely separated in time from the air gun signature and is out of the time range of the conventional processing and interpretation steps.
By using the deepwater surface-related VSP multiples and the mirror-imaging technique, the VSP image was extended successfully above the well trajectory upward to the seafloor and shows a good correlation with the surface seismic section (Marques et al., 2011). We present a case study using the sea surface downgoing multiples for this unconventional VSP imaging technique.
3D and 4D Seismic Data Integration for Geomodel Infilling: A Deep Offshore Turbiditic Field Case Study.
Authors: Silva V. , Cadoret T. , Bergamo L. , Brahmantio R. 
Published: December 2015

Abstract
When seismic data is of good quality and that it can be related to useful geological properties it can become a useful driver to distribute spatial heterogeneity within the geomodel. This paper describes a workflow to incorporate efficiently seismic data during the geomodel infilling process. We propose to combine the seismic facies probability attribute (obtained after 3D pre-stack inversion) with 4D attributes. This is done by increasing the seismic facies probability where 4D information highlights the presence of permeable reservoir facies. Afterward the obtained attribute is combined with well information using Total in-house workflow to generate the final facies proportion cubes. Finally, Associated Facies (AF) simulation is performed using SIS (Sequence Indicator Simulation) algorithms. Comparison is performed between the AF obtained using 3D seismic data only and AF obtained using combined 3D and 4D seismic data.
The integration of 4D information early in the geomodeling workflow (i.e. in facies modelling stage) improves the efficiency of the dynamic back-loop by allowing an early combination of Static and dynamic information. Thanks to this, history matching of dynamic reservoir simulation is facilitated.
Geochemical Applications for Identifying the Source of Hydrocarbons in Well Annuli
Authors: Aly Maher , Clancey Byron , Montgomery John K. , Bugti Mehboob A. , Ahmadzamri Ahmad F. , Al-Meraikhi Ajlan A. , Lawson Michael 
Published: December 2015

Abstract
Pressure build-up in the annuli of oil and gas wells could be an indication of a well integrity problem, in particular if determined to be sustained. In order to implement an effective remediation strategy for sustained annuli pressure, the source(s) of annuli fluids need to be determined so that the root cause of the problem can be identified and effectively mitigated.
This paper describes an approach developed to attempt to identify the possible sources of hydrocarbon fluids observed in some annuli of gas condensate wells located in Field A. During the initial phase of the investigation, it was not possible to determine the source of annuli hydrocarbon fluids from routine compositional analysis alone because the outer casing strings of the wells intersect multiple hydrocarbon bearing reservoirs and aquifers whose fluids have non-unique compositions. A multidisciplinary approach was therefore adopted that incorporated all of the available data and non-routine fluid analyses. A detailed fluid sampling and analysis program was also conducted to better understand and characterize the possible sources of the observed hydrocarbons in each well's annuli.
In one case study, interpretation of routine fluid compositional data indicated that non-hydrocarbon and hydrocarbon gas composition data alone did not provide a clear indication of the source of intermediate and surface casing fluids. Detailed geochemical analysis was therefore required to gain a better understanding of the annuli fluid source. In another case study, comparing the gas composition of the annuli fluid to the gas composition of a produced fluid allowed for the indication of the source of annuli fluid. In both cases, the compositional signature of the annuli source fluids was found to be sensitive to contamination as a result of changes in the pressure and temperature conditions in the annuli and through mixing with aqueous annuli drilling or completion fluids. However, more comprehensive geochemical screening that included molecular geochemistry and isotope analysis was shown to help in understanding the processes controlling the fluid composition and in reducing the uncertainties associated with the derived interpretation based on routine fluid compositional analysis alone. Conclusions from this work have now been incorporated into the annuli pressure management guidelines and in planning of future drilling and completion activities.
The HSSE Journey of Qatar Shell and GDI on Al-Khor Rig
Authors: Dakik A. , Attar F. , Babi B. , Stephenson B. 
Published: December 2015

Abstract
In continuous pursuit of improving safety and operational standards in the drilling industry, Shell took a major step forward in the Middle East when Qatar Shell Services Company W.L.L. partnered with the local drilling contractor, Gulf Drilling International (GDI) in 2011 for operating the Al-Khor Jack up drilling rig.
During the course of this partnership, HSSE was identified as one of the main pillars to be recognized, developed, and reviewed continuously for compliance against key HSSE targets.
GDI the local drilling contractor in Qatar aspires to become one of the best in class drilling contractors. Qatar Shell is committed to assist GDI in achieving that goal by refining the safety leadership attributes within the GDI crew, developing the skills for effective use of HSSE tools, and focusing on performance and people.
Shell's vision in safety is "Goal Zero" which means having an incident free workplace. Qatar Shell's safety journey with GDI started with improving the safety culture in the workforce and focusing on preventing incidents. This was a crucial step in the beginning of the journey as the team had new staff, new rig and a new contract to cope with. In addition, the rig was supporting well testing operations and did not drill wells for the previous 2 years.
Qatar Shell has successfully implemented and contributed to both personal and process safety roadmaps on Al-Khor Rig by adopting, and continuously evolving the learnings and safety procedures that are implemented globally by Shell. A successful implementation of DROPS (Dropped Objects Prevention Scheme), Red Zone management, Hands Free working, and barrier ownership has had a significant impact on Shell operations globally. On the GDI Al Khor, the implementation of these safety drivers in the appraisal wells program led to a reduced number of incidents, comprising a total of 3 recordable incidents in 4 years of operations. In addition, to promote the safety culture onboard the reporting of unsafe STOP cards was encouraged.
On the rig, compliance continues to be measured, and leading HSSE indicators continue to be developed. The goals set by GDI and Qatar Shell will be achieved through continuous commitment and safety leadership. With the vision to constantly improve and uplift the safety culture on Al-Khor rig to become best in class, Qatar Shell's journey with GDI continues.
Sweet Spots For Hydraulic Fracturing And Oil Or Gas Production In Underexplored Shales Using Key Performance Indicators: Example Of The Posidonia Shale Formation In The Netherlands
Authors: ter Heege J. H. , Zijp M. H. A. A. , Nelskamp S. 
Published: December 2015

Abstract
While extensive data and experiences are available for hydraulic fracturing and hydrocarbon production from shales in the U.S.A., such a record is lacking in many underexplored shale basins worldwide. As limited data is usually available in these basins, analysis of shale prospectivity and identification of sweet spots for oil & gas production needs to be based on upfront geological characterization and modelling before drilling, hydraulic fracturing and gas production has commenced. In this paper, different reservoir characterization techniques and modelling approaches are combined to quantify key performance indicators that describe potential shale productivity across the formation. The performance indicators describe the potential for hydrocarbon generation, storage, and flow stimulation based on a limited number of shale properties, and are benchmarked using data from the prospective Barnett Shale Formation in the U.S.A. The approach has been applied to the underexplored Posidonia Shale Formation in the South of the Netherlands (West Netherlands Basin). Local maxima of the mean performance indicator across the formation correlate with local maxima in vitrinite reflectance and depth. Average performance for the Posidonia is lower than for the Barnett shale, mainly due to lower maturity and brittleness. Besides higher clay content and associated lower brittleness, the potential for hydrocarbon generation and storage capacity of the Posidonia are comparable to oil mature Barnett shale from noncore areas. Predictions of gas production in the Posidonia based on simulations of hydraulic fracturing and gas flow using well-based models are in rough agreement with gas production observed in noncore Barnett areas, but low brittleness may hamper succesfull hydraulic fracturing. The example shows that the approach can be applied to underexplored shales worldwide to quantify prospectivity, map out sweet spots, point to preferred drilling sites, and optimize field development planning.
Engineered Formic Acid Precursor Helps Operator Successfully Stimulate Longest Open Hole Section in Carbonate Reservoir to Date
Authors: Degouy Didier , Sofyan Muhammad , Jaffar Mohd Bin , AL-Naimi Abdulaziz , Mohamed Monir , Pavia Linneth 
Published: December 2015

Abstract
A formic acid precursor (FAP) was used in a carbonate reservoir in offshore Qatar to achieve uniform filter-cake breaker treatment over the entire openhole section to improve wellbore productivity. Wells with a moderate wellbore length have been stimulated using a FAP with a delay time of ±3 hours, which is sufficient for spotting the precursor pill into the openhole reservoir section before the filter cake is broken by the treatment reaction (resulting in downhole completion fluid losses). In late 2014, a FAP cake-breaker treatment job was designed and performed for a 3741-m (12,270 ft) section of an 8½-in. open hole. This job required spotting a 159-m3 (1,000 bbl) FAP stimulation pill in the entire openhole section without incurring downhole losses while pumping. Thus, the delay time required for the precursor to convert to acid had to be increased to 8 hours.
Extensive laboratory tests were performed to increase the delay time for mixing and spotting the precursor pill before converting to acid and causing a significant reaction with the reservoir. These tests showed that an additional 5 hours of delay time could be achieved by a redesigned formulation. Mixing time also improved by delivering the liquid precursor in tote tanks, rather than in drums.
By performing the new fluid design and handling precursor material in tote tanks, the job was successfully run with an actual delay time of 8 hours, as compared to 5 hours for previous jobs. In addition, the retarded acid precursor pill was mixed and spotted into the entire open hole in 5 hours without downhole losses while pumping, indicating a successful mixing and spotting plan for the job. The downhole loss rate increased from zero at the end of spotting the precursor fluid to 2.5 m3/hr after 3 hours, signifying that the acid precursor was releasing acid, which reacted with the filter cake. An increase in downhole losses was observed after three more hours, when the loss rate increased from 2.5 m3/hr to 20 m3/hr. This increase indicated that the entire filter cake had reacted with the acid and that the acid had begun to enter the formation, acting as a stimulation fluid and enhancing well productivity.
This job was classified as the largest acid-delay precursor job performed globally to date by volume pumped and by interval length. Extensive laboratory tests were conducted to redesign the precursor fluid to achieve a sufficient delay time to mix and spot 159 m3 (1,000 bbl) of the FAP pill into the entire open hole before the acid reaction began. Using a liquid-precursor material in tote tanks helped to minimize the mixing time by 50% and resulted in a more efficient use of limited rig deck space.