bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design Considerations for a 200°C MWD System
Authors: Stroehlein Brian 
Published: December 2014

Abstract
It is a well-accepted rule in electronics that, at best, every 10°C increase in operating temperature shortens operating life by an additional 50%. Just as designers of 175°C+ Measurement-While-Drilling (MWD) systems face new challenges in making their designs work to reliability and operating time requirements, so are they finding newly-available opportunities to help them meet those requirements. This paper summarizes a recent cross-disciplinary effort to identify and address the key challenges involved with development of a new 200°C MWD system.
In 2012 we completed a Feasibility Study, commissioned by an operator, for a 200°C directional-gamma MWD system with a mud pulser for real time telemetry and a turbine alternator for power. The primary users of this system would be MWD service providers servicing those operators drilling hot holes. This Study included a comprehensive survey of the state-of-the-art in components, materials, system architectures, fabrication & assembly techniques, and statistical reliability & quality techniques required for successful implementation. Sufficient downhole memory for time-stamped directional, gamma and diagnostic records were essential parts of this project. Due to the potentially drastic life-shortening environmental effects of drilling hot holes, we also specified recording of temperature, shock and vibration data to enable Condition-Based Maintenance (CBM) based on Accumulated Damage Modeling (ADM).
Our Feasibility Study showed that several key technology developments inside and outside the oilfield made the 200°C MWD system technically achievable. The system was also shown to be operationally viable for all three parties in the application chain: our organization, the independent drilling service provider users and their operator customers. These factors were expected to have a positive effect on service availability for hot hole applications.
This paper provides insights into the drilling technology development process in general and the key technologies available for implementation, specifically, of a 200°C directional-gamma MWD system. We completed extensive research on the history and current state-of-the-art in components, materials, fabrication & assembly techniques and statistical reliability & quality techniques, and found no insurmountable obstacles to implementing a successful production 200°C MWD system suitable for use by independent MWD service providers.
Sedimentology Genetic Modeling of an Offshore Abu Dhabi Carbonate Reservoir
Authors: Bourdarot Gilles , Khemissa Hocine , Al Shemsi Abdullah , Murat Bruno , Richet Remy , Games Federico , Porcher Florent 
Published: December 2014

Abstract
During this innovative work a 3D Stratigraphic forward Modeler initially designed for geohistorical basin modelling has been used to produce multi-realization of 3D facies distribution of a giant offshore carbonate reservoir in Abu-Dhabi.
The Stratigraphic 3D forward Modeler simulates carbonate production and transport by solving a diffusion equation. The modeling started from a given age, through a sequence time steps. At each time step, three main parameters controlling deposits are modelled: 1) Accommodation space which reflecting the total available water depth for sediment deposits, 2) Sediment Supply by setting carbonates production laws inside the model, 3) Transport and Wave Reworking using a diffusion law, function of wave energy, slope and a diffusion coefficient depending on carbonate nature and grain size.
The model is calibrated to facies thickness and texture described at 17 cored wells by a previous 4th order Sequence Stratigraphic Sedimentology study.
The model has a grid of 200 X 200m, similar to the reservoir simulation grid size, a 50,000 years time step which corresponds to 136 layers, ensuring a vertical resolution in the range of 1 to 2 meters. The total size of the model is 2.7 Million cells. The resulting model reproduces the spatial facies distribution in the reservoir and with more than 80% success the facies texture and thickness at cored wells for each 4th order sequences.
By varying the parameters controlling sediment deposits, using an Experimental Design approach, several realizations of the geological model have been produced to capture uncertainties on facies distribution between wells, each of them honoring the facies description and thickness at cored wells.
This new approach increases considerably the consistency, resolution and reliability of the geological model between wells.
Neutron-Star Seismic, an Ultra-Dense 3D Acquisition and Processing Test
Authors: Keggin James , Ourabah Amine , Ellis David , Grimshaw Martin , Kowalczyk-Kedzierska Monika , Murray Eamonn , Cooper Sharon 
Published: December 2014

Abstract
Since the advent of modern seismic methods in the 1950s, we have seen the quality of our subsurface images increase dramatically. Along with improvements in engineering, computing and seismic processing techniques, this is largely due to the massive increase in the number of seismic measurements made per unit area. In the 1950s 2D seismic data consisted of hundreds of seismic recordings per sq. km – in 2011, BP acquired an onshore 3D survey in Jordan with around 10 million seismic measurements per sq. km. The first part of this paper describes how, using the Independent Simultaneous Source technique (ISS®) these data were acquired efficiently in a short time frame. Then in the second half of the paper, we describe the careful processing and analysis of a large number of data decimations. We then discuss whether there is an upper limit to the improvements in image quality seen as data density increases. Image quality is judged not only on the quality of the post stack data, but also on the quality of various pre-stack attributes that are increasingly being used for reservoir description and lithology and fluid prediction. We also discuss the challenges associated with managing and processing the huge data volumes that are generated with this style of dense acquisition - modern seismic surveys of this density are starting to contain Petabytes of data.
Low-salinity Water-alternating-CO2 Flooding Enhanced Oil Recovery: Theory and Experiments
Authors: Teklu Tadesse Weldu , Alameri Waleed , Graves Ramona M. , Kazemi Hossein , AlSumaiti Ali M. 
Published: December 2014

Abstract
Carbon dioxide flooding is currently the most technically and economically viable enhanced oil recovery (EOR) process in carbonate and sandstone reservoirs. Low-salinity waterflood is a relatively new EOR process; and our experiments in carbonate cores show significant oil recovery improvements. We propose a new EOR process to improve economics, which involves low-salinity water-alternating-CO2 (LS-WAG) injection.
To evaluate the proposed idea, three core floods and several contact angle and IFT measurements were performed. The core floods include: seawater flood, followed by low-salinity waterflood, followed by CO2 injection, which yielded fourteen, twenty-five, and thirty-eight percent additional oil recovery by CO2 from two carbonate and one sandstone experiments.
We performed contact angle measurements on several low-permeability carbonate, medium-permeability Berea sandstone, and ultra-low permeability Three Forks mudstone core discs using different salinities. The contact angle measurements confirmed that favorable wettability alteration is achievable with the proposed EOR process. In addition, visual observations suggested that the proposed EOR process could be effective for cleaning the matrix-fracture interface in conventional and unconventional reservoirs. IFT measurments and modeling relevant to the EOR process is also included in this study.
Drilling Deep Horizontal Well in Highly Depleted and Thin Sandstone Reservoir: A Successful Case Study from North Kuwait
Authors: SANYAL A. , De S. , Dutta A. , Al-Khaldy M. D. , Safar A. 
Published: December 2014

Abstract
In the Asset of North Kuwait, a very productive, narrow and moderately continuous sandstone layer has been heavily exploited since 1990. Over and underlain by extensive shale barriers, this channel sand with weak lateral drive, has been developed using predominantly vertical and deviated wells. The sand body was deposited in an estuarine environment as a minor switching channel with limited lateral connectivity. With reservoir pressure currently at 3ppg MWE, horizontal completions were planned to further accelerate production in anticipation of much needed pressure support. The major challenges to overcome were i) the trajectory planning and high-angle drilling through about 300 feet of highly loss prone Dolomite, close above the target reservoir, ii) casing-off the high-pressured overlying shale, iii) restrict formation damage while drilling lateral section and iv) avoiding differential sticking using conventional over-balanced mud systems. An excellently engineered 7.6 ppg OBM (least possible mud weight) yielded rich dividends as it minimized formation damage and reduced chances of differential sticking. Pre drill modelling based on nearby well data and judicious use of Distance to Bed and Azimuthal Deep Reading Resistivity image from LWD tool suite provided excellent control that facilitated successful geosteering through thin pay. Dynamic and Contingency Planning during execution were crucial to real time decisions leading to a successful completion of the first horizontally completed well. The case study details the analytical approach and meticulous planning towards the selection of a Directional Drilling BHA, Wellbore Trajectory, Mud Weight and type, Drilling Strategy, pre-job and contingency planning that resulted in successfully drilling and completing a productive horizontal well through grossly depleted reservoir in its maiden attempt. The engineering tools and strategies outlined can be appropriated to the drilling and completion of horizontal drain holes in thin-pay, heavily depleted reservoirs that require high-angle penetration of equally depleted zones.
Production Optimization of Maximum Reservoir Contact Well by Utilizing Acid Stimulation with Limited Entry Technique
Authors: Issa Faiz , Abbott Jonathan , Akbari Aulia 
Published: December 2014

Abstract
In recent years, a major Abu Dhabi offshore operating company has shifted towards utilizing Maximum Reservoir Contact (MRC) wells to improve oil production and long-term oil recovery. The initial MRC pilots demonstrated the importance of designing the well and completion to facilitate intervention and stimulation. Coiled tubing stimulation methods applied in these first wells were able to meet the objective by significantly improving overall oil production and water injection. However, as we move into tighter formations and longer wells the efficacy of coiled tubing is significantly reduced by limited accessibility and restrictions on the rate.
The MRC strategy is being implemented in Reservoir II which is the largest reservoir in terms of Oil in-place. Reservoir II is a thick multilayered limestone reservoir characterized by its low permeability. This low permeability becomes more pronounced as one moves from the crest of the field to the periphery of the field.
In such tight reservoirs (Reservoir II), conventional techniques may yield lower than expected production results. In an effort to improve production and ultimate recovery, a new stimulation and completion strategy is required that improves contact with the reservoir beyond the wellbore.
In this paper we will discuss the design and implementation of a new technique intended to improve the production and recovery from tight reservoirs. This technique combines a fit-for-purpose limited entry type completion with high rate acid stimulation. Pre- and post-production comparisons demonstrate a substantial production increase and uniform contribution along the extended horizontal interval.
We will review the design approach, job execution and evaluation of pre- and post-production performance. We highlight key technical challenges and risks encountered during the preparation, design, execution and evaluation stages of this operation and discuss how these were overcome and mitigated for the improvement and optimization of future MRC wells.
A Combination of Selective Noise Suppression Methods and Pre-stack Time Migration for Effective Denoising: A Case History from Offshore Abu Dhabi Production Oil Field
Authors: Inoue Hiroyuki , Al Shehhi Jamila , Hagiwara Hiroshi , Mahgoub Mohamed , Khakimov Oleg , Janik Frantisek , Hussain Ayad 
Published: December 2014

Abstract
Effective and careful noise attenuations are crucial for any seismic processing project to control and assure the product quality. The robustness of the data processing can be often identified and quantified by existing well data in production oil and gas fields during the processing. However, if we drill new infill and/or appraisal wells on the flank of the structure based on the processed seismic data, we always need to address the thorny issue of unforeseen mismatching between predicted and actual geological formation tops.
In this paper, we present a recent seismic re-processing study from an offshore an Abu Dhabi oil field utilizing relevant seismic processing techniques to overcome these problems as a case study. The original data processed in 2006-2007 exhibits several technical issues: wavelet instability, poor signal-to-noise ratio, limited resolution and offset range, remnant acquisition footprint and multiples. This imperfect dataset led to significant depth discrepancies on a recent appraisal well that was planned using this seismic dataset.
The recent processing techniques such as adaptive subtraction of ground roll, 3D deconvolution, 3D Radon-demultiple, 3D projection filtering in the OVT (offset vector tile) domain were carefully applied to address these issues. In addition, we demonstrated that PreSTM (prestack time migration) is an effective de-noise tool while unnecessary and harmful noise attenuations could not be applied to the data because of the potential damage to diffractions and signals before PreSTM. These noise attenuation efforts allowed longer offset ranges into the stack, which proved to be the crucial factor in improving the seismic data quality.
Our recent structural interpretation results based on the reprocessing have successfully demonstrated more accurate depth matching on key geological formation tops at this appraisal well location. In addition, blind test utilizing nearly all wells in the field has reinforced our observations. Since subtle reservoir depth variation at each well location will make significant changes to oil production and recovery factor in this particular field, this cast history brought added value to the field development plan particularly for planning horizontal hole drilling and optimizing appraisal well locations.
Efficient Structural Uncertainty Parameterization for Risk Assessment of Large Fields
Authors: Sabatino R. , Viviani E. , Della Rossa E. , Sala C. , Maffioli A. 
Published: December 2014

Abstract
Unexpected results during the development phase of a field, often due to geological structure and fault network limited knowledge, have a huge impact on reserves. 3D reservoir models, however, are usually built on the basis of a deterministic interpretation of sparse or indirect information. The typical description of structural uncertainty by means of a large number of alternative reservoir top surfaces is commonly used in reservoir studies and risk assessment. Nevertheless, this approach might be cumbersome for two reasons: firstly, the high computational costs for large field models and secondly the link between a single uncertain structural feature and the related dynamical responses is not easily identified using the random surfaces realizations. To overcome the above issues, in this paper an approach based on the Principal Component Analysis (PCA) is presented. This statistical technique is able to reduce the number of parameters required for an effective representation of uncertain geometrical features. The idea is to decompose the large set of surfaces coming from geophysical uncertainty modelling into a limited number of spatial frequency components.
The resulting reduced parameterization is then used in combination with an elastic gridding approach, internally developed, to directly modify the corner point grid. The proposed methodology is therefore applied to assess hydrocarbon in place and estimate reserves of a large carbonate field. Structural uncertainties such as flanks geometry and reservoir thickness, were combined in a unified workflow with other static and dynamical uncertainties.
The benefits and improvements of this approach were highlighted and compared to a standard workflow. The outcome is a comprehensive risk assessment which allows for a clear understanding and a straightforward connection between the effect of uncertain structural features and both the hydrocarbon in place and the dynamical behaviour.
The Appraisal and Development of a Challenging Marginal Field in the Middle East
Authors: Saadawi Omar , Baguenane Boussad , Al Marzouqi Mohamed , Al Hashemi Tayba 
Published: December 2014

Abstract
Abu Dhabi Company for Onshore Oil Operations (ADCO) is a major oil producer in the Arabian Gulf with a wide portfolio of fields and reservoirs. The company is currently developing both new and existing assets to increase its production capacity. Field ‘M’ is one of the new assets that will contribute to this additional production.
Although the field was discovered in 1975, it was categorized as a marginal development primarily due to its remote location, limited size and reservoir properties. As a result it remained undeveloped until 2011. A 3D seismic reprocessing was conducted in 2009, and significant reservoir data was gathered from an appraisal well in 2010 which reduced the subsurface uncertainties. The field became less remote through the development of a larger, neighboring field 50km away. As a result, in 2011 a decision was made to carry out a full field appraisal campaign, with the aim of putting the field on production by 2017.
This paper describes the main challenges of the appraisal and development of the field, and details how they were tackled. A special emphasis is put on the value of multi-discipline integration between all the project stakeholders.
Low Salinity Water Injection: eni's Experience
Authors: Rotondi M. , Callegaro C. , Masserano F. , Bartosek M. 
Published: December 2014

Abstract
Low salinity water flooding has been recognized as prominent enhanced oil recovery technique acting at microscopic scale by reducing residual oil saturation thanks to a combination of intertwined mechanisms. In the last ten years, several studies and applications have been performed by Academia and Oil Companies giving indication of the process potentialities to increase oil production both in clastic and carbonate reservoirs.
Low salinity is considered by eni a key EOR method to improve recovery of both green and brown fields due to low capital and operational costs, leading to favorable economics compared to riskier and more expensive EOR techniques.
This work presents the state of art and describes eni's experience on low salinity waterflooding. Beneficial combination of low salinity water with polymer is also discussed as efficient and cost-effective EOR process for viscous oil fields. Eni has covered the whole low salinity life-cycle since 2006, from field candidate screening, laboratory experiments, log-inject-log tests, single well chemical tracer tests (SWCTT), accurate 3D reservoir modeling, desalination technique studies up to inter-well pilot tests. Experimental investigation in eni laboratories is executed to understand low salinity basic mechanisms and assess main parameters affecting fluid/rock/low salinity water interactions. Tertiary corefloods at field conditions are the first step to obtain evidence of beneficial effects. Lab results are reproduced by means of core-scale models to define simulation parameters. Obtained values are then applied on well and sector scale models for injection optimization and pilot design. Subsequently, field pilots such as SWCTT are performed, giving additional information on low salinity effectiveness. If positive results are confirmed and supported by updated simulation model, the technology is extended at inter-well and full field scale.
Eni has developed robust best practices leveraging on internal laboratory, modeling work and field experience which are crucial to boost recovery factors and extend fields life.
Intercept Method - A Novel Technique to Correct Steady-State Relative Permeability Data for Capillary End-Effects
Authors: Gupta Robin , Maloney Daniel Riney 
Published: December 2014

Abstract
In laboratory measurements of relative permeability, capillary discontinuities at sample ends give rise to capillary end-effects. End-effects influence fluid flow and retention. If end-effect artifacts are not minimized by test design and data interpretation, relative permeability results may be significantly erroneous. This is a well known issue in unsteady-state tests, but even steady-state relative permeability results are influenced by end-effect artifacts. This work describes “The Intercept Method,” a novel modified steady-state approach, in which corrections for end-effect artifacts are applied as data is measured.
The intercept method requires running a steady state relative permeability test with several different flow rates for each fractional flow. Obtaining multiple (3-4) sets of rates (Q), pressure drops (DP), and saturation data allow for assessment of capillary end effect artifacts. With Darcy flow, a plot of pressure drop versus total flow rate is typically linear. A non-zero intercept or offset is an end-effect artifact. To correct for the effect, the offset is subtracted from measured pressure drops. Corrected pressure drops are used in permeability calculations. The set of saturations from measurements at the target fractional flow are used to calculate a corrected final saturation. Because corrections for end effects are made during the test rather than after the test is over, any discrepancies can be resolved by additional measurements before moving on to the next fractional flow. Rates are then adjusted to yield the next target fractional flow condition and the same protocol is repeated for each subsequent steady-state measurement. The method is validated by theory and is easy to apply.
Introduction
Relative permeability is a fundamental input parameter for reservoir engineering. It describes multiphase flow and retention characteristics that are important for production forecasting, reserves estimates, and ultimate recovery predictions. Relative permeability versus saturation functions are typically obtained by conducting multiphase flow tests on reservoir rock core plugs in the laboratory. By nature of the laboratory multiphase flow set-up, there is a capillary discontinuity (end-effect or boundary effect) at the outlet end of the sample where fluids pass from the rock into the end-piece and tubing. In the rock, capillary pressure is related to saturation and saturation history. In the end-piece and tubing, capillary pressure vanishes. The discontinuity yields an accumulation of the wetting phase at the sample end which influences saturation distribution and pressure drop across the length of the sample.