bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Impact Of Completion Related Pressure Losses On Productivity In Shale Gas Wells
Authors: Jackson Gregory , Rai Rakesh 
Published: November 2012

Abstract
Transient linear flow diagnostic plots in shale gas wells often exhibit a positive y-intercept and may mask the early transient linear flow regimes because of non-reservoir pressure drops. Increased completion resistance reduces the peak production rate early in the life of a well impacting NPV. The shale gas industry is very early in the research required to distinguish the individual contributions of completion resistance, e.g. poor fracture conductivity, near-perforation damage or choke skin, and fracture face damage skin. Many of these phenomena can be diagnosed in production wells using unique shape(s) from various diagnostic plots allowing for analysis of completion effectiveness.
Mechanistic reservoir simulations were used to generate diagnostic plot signatures for low conductivity fractures, choke skin, and near fracture face damage. subsequently, the corresponding signatures were compared with a large database of shale gas wells in numerous plays across North America to aid in the fingerprinting of these non-reservoir pressure losses. Only low fracture conductivity, not choke skin, can have a quarter slope. Near fracture face damage results in two distinguishable linear trends, one of the damaged region and the other for the matrix.
Completion skin diagnosis is a way of evaluating fracture efficiency by identifying the root causes of the non-reservoir pressure losses so as to mitigate them in the future. The following presents a catalogue of signatures that enables greater diagnostic capabilities to classify non-reservoir pressure losses. The study is the first comprehensive cause-by-cause look at completion damages with an emphasis on identification and diagnosis in shale gas wells.
Enhancing Vertical Seismic Resolution by Spectral Inversion
Authors: Kirchberger L. , Spitzer R. 
Published: November 2012

Abstract
Vertical seismic resolution quantifies the ability to distinguish between two close seismic events generated at different depths. A typical seismic dataset with a dominant frequency of 30 Hz allows the separation of top and base boundaries of a 25-meter thick reservoir layer. However, very often hydrocarbon bearing reservoirs are significantly thinner and, therefore, the vertical seismic resolution has to be increased in order to image and characterize those thin reservoirs properly.
The present study illustrates the application of spectral inversion technique based on high-resolution spectral decomposition offered by Lumina Geophysical, LLC. Spectral inversion can be described as a sparse-spike inversion driven by geological assumptions. It keys on local frequency spectrum obtained by spectral decomposition. Theoretically, a high signal-to-noise ratio and the exact knowledge of the seismic wavelet at reservoir level yield seismic resolution far below tuning thickness.
OMV chose to apply spectral inversion to various datasets recorded in Kazakhstan, West of Shetland and in Austria, covering different geological settings (e.g. channel features, sub-seismic faulting). Furthermore, a synthetic dataset has been designed and examined to illustrate benefits and pitfalls of the methodology. Each recorded seismic dataset showed significantly improved vertical seismic resolution after applying spectral inversion. The spectral inversion result for the marine seismic dataset (West of Shetland) showed increased seismic resolution and superior fault imaging compared to the conventional seismic data. Furthermore, seismic-to-well ties - including a blind well - very well support the realistic increase in vertical seismic resolution of the Kazakhstan seismic dataset. Finally, the evaluation of the onshore seismic dataset in Austria facilitated a new interpretation of the target sands which resulted in a revised geological model.
After careful evaluation of spectral inversion, OMV is convinced that this technology offers a valuable approach for better delineation and characterization of thin reservoirs and further projects will be performed.
Managing Risk through a Combination of Hazard Observation and Stop Work Authority Programs—Lessons Learned
Authors: Zerarka Said 
Published: November 2012

Abstract
An effective hazard observation program is essential for oil and gas organizations to manage risk and achieve superior health, safety and environment (HSE) performance. An effective hazard observation program is a core component of risk management in the workplace. Stop work authority (SWA) is an effective tool that enables and empowers employees to intervene and address clear and present dangers. Stop work authority promotes employee ownership in the workplace and helps to promote a successful hazard observation program. Supervisors play an essential role in the success of hazard observation and intervention programs by coaching employees in the identification of various hazards and supporting their interventions, as well as by recognizing these observations and completing a timely follow up of them.
Since Halliburton re-launched its SWA initiative in 2011, we have observed an increase in employee participation in hazard observations as well as better identification of these hazards. Furthermore, we noticed an increase in employee intervention to correct unsafe acts or unsafe conditions. Equally important, improvement was made in timely follow up and closing of these observations by supervisors.
This paper shares some best practices and successful case histories through the study and analysis of field data of a combination of hazard observations and SWAs in some of the operations locations where the service company is working in Algeria and the Sultanate of Oman.
This paper describes key success factors for the hazard observation program and demonstrates the positive impact of SWA on employee observations and interventions.
Improving Major Project Development Trough a Front End Loading Management System: Medco's way for Oil&Gas Development Project
Authors: Mishar Syahrilyan N. 
Published: November 2012

Abstract
As we enter the era of no more easy oil/gas, where reserves are located in remote areas with no nearby infrastructure available and multiple new stakeholders are involved, a complex E&P development project is something to be expected. To help the business process, a structured methodology is urgently needed to increase the predictability of a project outcome by reducing the risks from technical, commercial, legal, and other aspects in order to ensure the project is viable prior to authorization and to moving on to the next step.
The methodology which addresses this is commonly known as the Front End Loading (FEL) process, which uses a stage gate system for assurance. For smaller and newer E&P companies, this process is often underestimated, if not overlooked, unless the management realizes it is critical for business growth.
During the last three years, Medco has applied this FEL process to its major development projects as it begins to expand its capability in the E&P business. Several challenges have been faced during implementation of the FEL process and managed accordingly, including the different approach to loading a project to the process, and readiness for applying this new process and a new system.
All Medco E&P major development projects are now clearly mapped out, deliverables are well defined, risks are identified and mitigated through this stage gate system. Hence, projects are managed with the right level of attention and optimum number of resources. Through this FEL process, Medco aims to sustain or even increase the value of a project and return for a larger business growth potentials.
This presentation will report on findings and lessons learnt during Medco's early implementation of this FEL process for its major development projects.
Variations in Bounding and Scanning Relative Permeability Curves with Different Carbonate Rock Types
Authors: Dernaika M. R. , Basioni M. A. , Dawoud A. , Kalam M. Z. , Skjæveland S. M. 
Published: November 2012

Abstract
Relative permeability curves generally exhibit hysteresis between different saturation cycles. This hysteresis is mainly caused by wettability changes and fluid trapping. Different rock types may experience different hysteresis trends due to variations in pore geometry. Relative permeability curves may also be a function of the saturation height in the reservoir.
A detailed laboratory study was performed to investigate relative permeability behavior for a major carbonate hydrocarbon reservoir in the Middle East. Representative core samples covering five reservoir rock types (RRT) were selected based on whole core and plug X-ray CT, NMR T2, MICP, porosity, permeability and thin-section analyses. Primary drainage and imbibition water-oil relative permeability (bounding) curves were measured on all the five rock types by the steady state technique using live fluids at full reservoir conditions with in situ saturation monitoring. Imbibition relative permeability experiments were also conducted on the main RRT samples to assess the relative permeability (scanning) curves in the transition zone by varying connate water saturations.
Hysteresis effects were observed between primary drainage and imbibition cycles, and appeared to be influenced by the sample rock type involved (i.e. wettability and pore geometry). Variations in relative permeability within similar and different rock types were described and understood from local heterogeneities present in each individual sample. This was possible from dual energy CT scanning and high resolution imaging. Different imbibition trends from both oil and water phases were detected from the scanning curves which were explained by different pore level fluid flow scenarios. Relative permeability scanning curves to both oil and water phases increased with higher connate water. Relative permeability to oil was explained based on the occupancy of the oil phase at varying connate water saturations. The change in water relative permeability trend was addressed based on the connectivity of water at the varying connate water saturations. These results and interpretations introduced improved understanding of the hysteresis phenomena and fluid flow behavior in the transition zone of a cretaceous carbonate reservoir which can assist in the overall reservoir modeling and well planning.
Maximize the Ultimate Recovery by Designing and Optimising a CO2 Miscible Gas Injection Pilot in a Giant Carbonate Oil Reservoir, Abu Dhabi
Authors: Rawahi A. , Hafez H. H. , Al-Yafei A. , Al-Hammadi K. , Ghori S. G. , Putney K. L. , Matthews T. R. , Harb R. 
Published: November 2012

Abstract
It is critical to properly design a CO2 injection pilot for its successful implementation. A detailed pilot design provides valuable information in field development decisions especially when managing high CAPEX. This paper presents detailed workflow of a miscible CO2 gas injection pilot design for a giant onshore oil reservoir in Abu Dhabi, UAE. A technical feasibility study was performed in over a two year period by Abu Dhabi National Oil Company (ADNOC), ExxonMobil, and Abu Dhabi Company for Onshore Oil Operations (ADCO).
The key objectives of the study were to evaluate the CO2 EOR potential of the field, reduce performance uncertainty, and productively utilize a specific amount of CO2. A distinctive workflow was developed to identify the optimum pilot design that would successfully achieve these objectives.
The project started with a comprehensive screening process to select a candidate reservoir and a suitable pilot location within this reservoir. A high definition representative sector model was then used to design the pilot. First, pilot well concept parameters such as well pattern, type, and orientation were selected to maximize oil recovery. Second, key subsurface uncertainties and design parameters were identified that would have the greatest impact on pilot performance. The Experimental Design technique was then used to evaluate these uncertainties. Finally, a deterministic simulation model was used to predict the expected range of pilot performance.
CO2 EOR Scheduling by Analytical Model (CESAM)
Authors: Tanakov Mikhail , Al Yafei Arafat 
Published: November 2012

Abstract
This paper presents a new approach developed for high-level scoping analysis, forecasting and scheduling of CO2 EOR projects for multiple reservoirs and fields. The approach utilizes available reservoir simulation, analytical predictions and analog data on a full-field scale and approximates them with analytical functions. This allows for very fast forecasting of oil and CO2 production rates and determines the requirements for make-up CO2 under different potential development scenarios, including piloting phases. Built in MicrosoftTM Excel with VBA code and an advanced solver add-in, this scheduling tool enables the timely use of probabilistic Monte Carlo simulation for estimating the impact of uncertain input parameters on CO2 flood performance from multiple reservoirs. A numerical optimization algorithm searches for the best development schedule by optimizing the start-up times for a number of planned CO2 injection projects subject to allowable oil rate and CO2 supply constraints. Another optimization algorithm matches the estimated CO2 demand with supply from multiple natural and industrial sources and predicts the best time to commission CO2 capture facilities, thus maximizing CO2 utilization by EOR schemes rather than disposing it in depleted reservoirs or saline aquifers.
Comprehensive Diagnostic and Water Shut-off in Open and Cased Hole Carbonate Horizontal Wells
Authors: Ahmad Nawawi , Al-Shabibi Hussain , Zeybek Murat , Malik Shauket 
Published: November 2012

Abstract
Increases in water production can significantly reduce well performance and life of a well, and cause decreased oil production. Water influx can occur through several mechanisms and approach from several directions; accurate diagnostic information is important for the design of successful shutoffs and effective results. To mitigate this situation, water management is crucial. One option is to isolate the water producing zone with a rigless water shut-off technique, which is less costly than the use of workover rigs for interventions.
This paper presents case histories of five horizontal wells drilled in carbonate formations and producing excess water; three were completed in open hole and two were cased. A multiphase production logging (MPL) tool equipped with five miniaturized spinners for phase velocity measurement and six electrical and six optical probes for holdup data provided important diagnostic data for the decisions on remedial actions. Using the tool data, the operator pinpointed the water entries and performed shutoff operations based on the source of the entries and water flow profiles. Subsequent production test results showed that the water cut was reduced in all the wells. Examples from open and cased hole completions are shown utilizing a number of different shutoff techniques. In addition, oil production was considerably increased in many of the wells. These results demonstrate that accurate diagnostic information and an integrated approach are keys to successful rigless water shutoffs.
An Outcrop Analog of Kharaib & Shu'aiba Reservoirs: The Urgonian Platform of Southeastern France (Gard and Ardèche)
Authors: Bastide Fanny , Massonnat Gérard , Virgone Aurélien , Pabian-Goyheneche Cécile 
Published: November 2012

Abstract
The Barremo-Aptian Urgonian formation is widespread in southeastern France. This formation is a giant (20 000 km2) limestone platform deposited along the northern Tethyan margin during the lower Cretaceous, on the Vocontian basin margin. The Urgonian carbonates are mostly composed of rudist facies interupted by several Orbitolinids-rich level. This formation has an equivalent in time in the Middle-East series: the Kharaib, Hawar and the very beginning of the Shu’aiba formations. The quality and diversity of Urgonian outcrops in southeastern France lead that formation to be a good reference proxy of Middle-East reservoirs and to be used for the assessment of sedimentary internal architecture.
A work program focused on the appraisal of geometrical and petrophysical heterogeneity in Urgonian has integrated the acquisition of multi-scales static and dynamic data: outcrop studies (facies, fractures, microfauna ...), well drilling, well tests, aerial photographs, springs and aquifer survey. A huge database has been constituted, it comprises several key sections and more than 60 vertical wells drilled in the Urgonian aquifer, 40 well tests and survey of 13 springs during one year.
Three sequences have been described in the Upper Barremian (Ba3, Ba4 and Ba5) and two sequences in the Lower Aptian (A1 and A2). The existing biostratigraphic chart built for several years by Annie Arnaud-Vanneau for the northern region (Vercors) has been improved and completed including the new data from the western zone (Gard and Ardèche).
Through a multidisciplinary approach integrating sedimentology, hydrogeology and structural geology, a new conceptual model for the architecture of the Urgonian deposits on the edge of the platform is proposed. In the study area, three N110° normal faults subdivide the domain into four tilted blocks. The differential subsidence related to this faults activity makes important variations in thickness and facies distribution according to the location in the blocks.
Joint AVO Inversion for Time-Lapse Elastic Reservoir Properties
Authors: Kato Ayato , Stewart Robert 
Published: November 2012

Abstract
For time-lapse seismic inversion, it is common that baseline and monitor survey data are separately inverted to elastic properties. Elastic property changes are obtained from difference in the two inversion results. Buland and Quair (2006) proposed novel time-lapse inversion method based on the Bayesian theorem, in which posterior distribution of elastic property change are obtained from seismic data difference between two surveys along with the prior information. However, individual elastic properties at baseline (or repeat) survey cannot be simultaneously obtained. Moreover, they assumed constant wavelet although individual wavelets are commonly used in different vintage data. Therefore, to overcome the limitations, we have developed a new time-lapse seismic inversion method. The method uses both baseline and monitor survey data, instead of only uses the difference, and simultaneously obtains elastic properties (e.g., P- and S-wave velocities and density) at baseline survey and the changes at monitor survey as well as the uncertainties. Furthermore, the developed method allows us to use individual wavelet in each seismic data, resulting in multicomponent data which can be used. The method is applied to Hangingstone oilfield in Canada, where heavy-oil with 8.5 °API has been produced by SAGD method and time-lapse seismic data were acquired; baseline survey in 2002 and repeat survey in 2006. Both P-P and P-S data are available in the monitor survey while only P-P data is available in the baseline survey. We use all the available seismic data to obtain initial elastic properties at the baseline survey, which reasonably well agree with well log data, as well as the elastic property change due to steam injection. Furthermore, the elastic property change is converted to temperature change within reservoir by using heavy-oil rock physics model, which are reasonably consistent with measurement at observation wells.
The Challenge of Developing Complex Marginal Fields, Example of Ne Brazil
Authors: Guerreiro L. , Carvalho A. , Maciel C. , Sousa J. , Caetano H. , Soares L. , Carneiro S. , Castanho S. , Machado V. 
Published: November 2012

Abstract
Marginal fields based upon complex reservoirs present to the operating companies real challenges in terms of the implementation of viable full field development plans (FFDP). Small NPVs imply a constant and tight costs control and a careful balance between the data gathering cost and the value of the information that can be retrieved from that data.
The fields under analysis are located in the onshore Potiguar Basin, NE Brazil. Productive reservoirs are composed by shallow interbedded sandstone channels and fine shale laminations with complex geometry. Seismic imaging has very poor quality and petrophysical interpretation presents a major challenge due to the presence of fresh formation water.
The absence of strong aquifers associated with low initial reservoir pressures and a negligible GOR led to the use of artificial lift and, in a near future, the implementation of a water injection scheme. The oil is paraffinic with low pour point temperatures, which easily creates conditions for high deposition of paraffins. All these factors induce very low productivities, ranging from 100 to 300 bbld with high water cuts.
An out of the box thinking attitude was fundamental for Partex to be able to design and implement a sound FFDP, which included the building of consistent static and dynamic models, where uncertainties were identified and quantified. Uncertainty reduction was tackled both through planified but limited data gathering campaigns and compilation of existing analogue data. Operational cost reduction without compromising HSE standards was implemented through innovative well drilling and design and a phased development scheme associated with long term testing (early production schemes).
Wide Azimuth Seismic Processing for UAE Carbonate Reservoir Characterization
Authors: Guilloux Yoann , Tarrass Issam , Boelle Jean-Luc , Landa Evgeny , Buzlukov Vadim , Lafram Abderrahim , Radigon Michel , Mahgoub Mohamed 
Published: November 2012

Abstract
We present in this work an exhaustive seismic study which was performed on a subset of a wide azimuth Ocean Bottom Cable seismic acquisition shot over a carbonate field from the U.A.E.
A first challenge was to reprocess these data ensuring that the azimuthal information is properly preserved all along the sequence. An additional challenge is related to the very shallow water environment which brings complexity like dispersive ground-roll and water layer related guided waves, multiples which can be generated at sea-surface, sea-floor or internally, near-surface heterogeneities.
On top of that the high velocities which are encountered in these carbonate formations are detrimental to a high resolution description of reservoirs.
Two main issues are presented:
Wide azimuth processing: the whole sequence was designed in order to preserve the azimuthal information. Multiples were attenuated in a cascaded approach including 3D predictive deconvolution and wide azimuth high resolution radon filtering. The Common Offset Vector strategy was followed at the imaging step to build 3D Common Image Gathers versus offset and azimuth, which enables to apply an azimuthally variant residual velocity correction and then stack all azimuthal contributions in an optimal manner. This azimuth friendly processing delivers gathers which are ready for azimuthal amplitude analysis. Heterogeneities and fracture characterization: we tested a newly developed technique for imaging diffractions and compared it to the azimuthal amplitude analysis performed on Common Imaged Gathers.
This pilot processing study enabled to set up an operational wide azimuth processing sequence on this dataset, several processing scenarii could be tested and compared. In particular the sequence for attenuation of multiples was considered efficient, bringing a lot of character to the final result.
The implementation of multi-azimuth Diffraction Imaging over this carbonate reservoir is proving very encouraging. Numerous detected features display geologically meaningful characteristics, some of them being not visible on conventional structural attributes. This study would be among the first applications of the methodology with tangible results providing more static and dynamic fracture data become available for calibration.