bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Reservoir Characterization with Lower Risk and Higher Efficiency Using a New Wireline Formation Tester Module in a Giant UAE Offshore Field
Authors: Sarsekov Arlen , Al-Neaimi Ahmed Khalifa , Abed Abdalla , Akram Fazeel Ahmed , Cig Koksal , Osunluk Halil Ibrahim , Al Shaikh Firas 
Published: November 2016

Abstract
One of the giant mature carbonate offshore field with multilayer hydrocarbon reservoirs in Abu Dhabi, United Arab Emirates is undergoing further development in its deeper, heterogeneous and more structurally complex carbonate sub-zones. The reservoirs in this field have a range of low to high permeabilities, several oil-water contacts and relatively big transition zones. There has been extensive water and gas injection operations in this field, which changed the fluid saturations with varying amounts in some of the zones.
The main challenges in the current development wells are to have an extensive data gathering program to recover representative fluid samples, to identify altered fluid saturations and contacts and decide on the optimum completion intervals of the work-over and/or new wells. One of the most important requirement at offshore fields obtaining pressure measurements and samples efficiently with minimum risk while maintaining the quality at the highest level due to offshore operational risk.
Historically, a large number of formation testing and sampling operations with wireline formation tester (WFT) tools were conducted in this field using straddle dual-packer and single-probe type inlets. A recently introduced new inlet module shows a significant improvement in risk minimization and increased operational efficiency over the dual-packer and single-probe inlets by reducing the sampling durations while maintaining high quality fluid sample recovery even in low mobility formations. High efficiency and low risk operations offered by the new WFT inlet has enabled the operator to include extensive formation testing and sampling operations in their drilling programs that resulted in better reservoir characterization especially in the deeper, undeveloped and less developed carbonate sub-layers even in difficult borehole conditions where the data gathering program was difficult to tackle.
This paper demonstrates the benefits of the new WFT module, which achieves operational efficiency and obtains quality PVT samples and accurate downhole data for the reservoir characterization. In addition, this paper shows the differences between the new WFT inlet and the previous WFT inlets, such as the dual packer and the single probes.
Reducing the Uncertainty of Static Reservoir Model in a Carbonate Platform, Through the Implementation of an Integrated Workflow: Case A-Field, Abu Dhabi, UAE
Authors: Torres Kevin Michael , Al Hashmi Noor Faisal , Al Hosani Ismail Ahmed , Al Rawahi Ali Salem , Parra Humberto 
Published: November 2016

Abstract
The prediction of the spatial distribution of petrophysical properties within heterogeneous reservoirs are affected by significant uncertainties when based only on well information. However, integrating additional constraints such as 3D seismic data and sedimentary concepts can significantly improve the accuracy of reservoir models and help reduce uncertainties on predictions away from wells.
The aim of this study is to build a reliable 3D geological static model through an integrated workflow using petrographic and sedimentary reports and the current understanding of the sedimentary conceptual model for the field in order to reduce the uncertainty. These core interpretations provide a clear description of the facies architecture across the A-Field, serving as excellent reference during seismic stratigraphy interpretations and lead into a geological distribution of the petrophysical properties in the reservoir through the facies models.
An integrated approach for facies modeling was implemented in order to generate stochastic models of the facies associations capable to reproduce the natural transition through the sequences. This method was adopted to model the high-resolution prograding pulses in the carbonate platform that were interpreted through cores description and facies association interpretation for both reservoirs.
The final 3D sedimentary-stratigraphic architecture is used as main constrain to model the petrophysical properties for each reservoirs. Under this approach, these models can account for varying the spatial continuity of reservoir properties honoring the different sedimentary facies. Facies-based property models preserve the facies-specific statistical distribution of the property, as well as its depositional direction. The facies-based 3D petrophysical models provide an improved prediction of petrophysical properties distribution and reservoir heterogeneity. The permeability simulation based on facies and the cloud transform between porosity and permeability allows better control of spatial connectivity patterns across the reservoir that could be used for improving reservoir performance predictions as it was carried out in the present static model.
Recent Advancements in Temporary Diversion Technology for Improved Stimulation Performance
Authors: Shahri Mojtaba P. , Huang Jian , Smith Clayton S. , Fragachán Francisco E. 
Published: November 2016

Abstract
Temporary fluid diversion using solid particulate systems has been used in several field applications in both conventional (acidizing) and unconventional (fracturing/refracturing) stimulation operations. Besides extensive successful field applications, less attention has been paid to the underlying physics and mathematical modeling of the diversion process. The aim of this study is to propose a comprehensive workflow for designing and optimizing different stages of diversion; i.e., slurry displacement from surface to downhole, sealing and fluid diversion, stimulation efficiency, and corresponding production enhancement. Coupled computational fluid dynamics (CFD) and discrete element method (DEM) numerical simulations are used to better understand the parameters controlling the fluid diversion process. These results are coupled to a 3D fracture simulator for investigating stimulation efficiency and production enhancement corresponding to successful fluid diversion.
Creative Solution for Cutting of Blast Joint at High lnclination Wells +/-75 Degrees in Horizontal Wells
Authors: Gebaly M. A. , Mufti A. S. , Al-Hammadi A. M. , Qutob A. , Makkawi S. , Mathew T. 
Published: November 2016

Abstract
Recovery of dual completion strings within horizontal wells is almost always a challenging and risky operation. This is generally due to presence of high concentration H2S along with a typically corrosive environment. Also, hard scale within the internal diameter of the completion string accumulated inside the tubing could prevent access to the desired location of a severance operation – which eases the transition of the overall recovery and subsequent work over.
Typically, dual completion horizontal wells contain approximately 200ft or more sections of blast joint above the single packer – essentially across upper perforation. This sort of arrangement and design of completion prevents washing over and leads to excessively long and occasionally complicate fishing operation. This typically involves hard jarring with maximum over pull to retrieve single packer – which can create complications and possible issues with the overall fishing operation. In most cases, the usual option to create the necessary cut to sever the production tubing is via electric line conveyed chemical cutters or radial torch cutters. The deployment of these types of tools offer a more cost effective and faster rig up and rig down – allowing for the required work over to take place is a rapid way. However, due to the typical orientation of these wells, being deviated (+/- 75 degrees) as such – this would prove to be difficult. Also, there often is a significant accumulation of scale inside the diameter of the production tubing which will not allow access to such tools to reach the required cut point.
The general methods, procedures and processes involved in this case were quite novel. The case was studied and came up with creative solution to cut the blast joint at approximately 20ft above single packer at high inclination of approximately 75 degree with a hydraulically actuated through tubing cutter with coil tubing conveyance. The overall project objectives were to minimize the risk of fishing operation, avoid dropped object and avoid the risk of washing over single packer with 4 to 6 joints of wash pipe at high inclination wells which consider weak point with high dog leg severity by conventional fishing tools. The hydraulically actuated through tubing cutter with coil tubing conveyance to cut long string close to the single packer revealed a lot of benefits – primarily in terms of cost and time savings.
Molecular Dynamics Simulation of Miscible Process in CO2 and Crude Oil System
Authors: Yang Siyu , Lian Liming , Yang Yongzhi , Ma Desheng , Tang Jun , Su Xuefeng 
Published: November 2016

Abstract
Different from the physical simulation, this method could describe the movement and interaction of molecules in detail in calculation and research with virtual system. Through this process, minimum miscible pressure is calculated as well as the influence of temperatures, pressures and components on miscible process. Four steps have been taken to study these factors and four conclusions were obtained. Low temperatures cause low minimum miscible pressures (MMP), MMP is low with low CO2 contents in the system, MMP of system is basically increasing with the increase of carbon number, and MMP of system is critically influenced by the structure of aromatic, naphthenic and paraffinhydrocarbons with different carbon number.
Evaluating a Complex Low-Resistivity Pay Carbonate Reservoir Onshore Abu Dhabi: From Model to Implementation
Authors: Ashqar Ayham , Uchida Miho , Salahuddin Andi A. , Olayiwola Saheed O. , Awolayo Adedapo N. 
Published: November 2016

Abstract
Early identification of low resistivity pay (LRP) reservoir is vital in assessing its prospect and capability. Productive reservoirs may exhibit low resistivity and consequently, their potential is simply overlooked. Remapping these intervals can have significant production and reserve implications. Traditionally, resistivity logs are used to identify pay intervals due to the resistivity contrast between oil and formation water. However, when pay intervals exhibit low resistivity, such logs return low confidence in defining hydrocarbon potential.
Due to the complexity of low resistivity pay (LRP), its cause and proper mitigation should be determined prior to applying a solution. Researchers have identified several reasons responsible for this occurrence; among which are the presence of heterogeneous pore structures specifically micro-porosity, fractures, paramagnetic minerals, and deep conductive mud invasion.
Almost all preceding publications assume a technique will work but not the other. However, this is the first time, to our knowledge; an integrated approach is used to develop LRP assessment workflow. We have integrated the information coming from geology (e.g., thin-section, XRD), formation pressure and well tests, NMR, MICP, and dean stark data. The integration successfully identified and remapped the carbonate low resistivity reservoir. This model was validated in an appraisal well on Abu Dhabi mainland, for that an extended data was acquired.
Thereafter, the integrated LRP model was compared with the computed water saturation from conventional resistivity tools. The validation was successful in terms of confirming the prognosis. Interpreting the results from the multidisciplinary integrated model confirms a deeper Free Water Level (FWL), hence oil pool extension. Further analysis showed that the causes of LRP in this considered formation was limited to presence of micro-porosity and high saline mud invasion.
Abu Dhabi Stress Map, UAE
Authors: Noufal Abdelwahab , Obaid Khalid , Ali Mohammed Y. 
Published: November 2016

Abstract
As drilling of horizontal wells is increasing in Abu Dhabi, so is the need for a stress map. In this paper, such a map, composed of the in-situ stress field of Abu Dhabi, is determined by the analysis of borehole breakouts and drilling-induced tensile fractures along with the results of 1-D Mechanical Earth Models. Stress orientations are variable across the Abu Dhabi fields as a whole; however, within 3 of 5 individual stress provinces defined in Abu Dhabi, mean stress orientations are statistically significant. The stress provinces and stress trajectory mapping reveal that they are systematic continental-scale rotations of stress orientations within Abu Dhabi. The stress orientations are not parallel to the direction of absolute plate motion of the Arabian plate, nonetheless; the regional pattern of stress orientation is consistent with plate boundary forces controlled by the complex nature of the subduction in the northeastern boundary of the Eurasian-Arabian plates.
To date, 130 1-D MEM's were generated, 98 of them expose the in-situ stress orientations, which have been compiled as the cornerstone of Abu Dhabi Stress Map. Of these, over 57 are considered reliable tectonic stress indicators, recording horizontal stress orientations to within ±15°. Remarkably, a good correlation was observed among stress orientations deduced from in-situ stress measurements and geologic observations made in the upper 1–2 km and in well bore breakouts extending to 2–3 km depth. The stress fields are believed to be largely the result of compressional forces associated with the subduction of the Arabian Plate beneath the Eurasian Plate and possibly from the divergent movement of the Red Sea along with the sinistral movement of the Aqaba-Levant fault boundaries. Knowledge of the contemporary crustal in-situ stress is of great importance for several applications, such as, borehole stability, hydraulic stimulation and understanding of the structural evolution of the terrain.
Taking Ownership of the F&G System While Reducing Costs and Increasing Safety - A practical Approach to F&G Mapping
Authors: McNay James , Farmer Murray 
Published: November 2016

Abstract

Objectives/ scope
This paper analyses the dangers of inappropriate design of Fire and Gas (F&G) systems not only to the hazards in question, but in failing to take account of the hardware/ environmental drawbacks to ensure a safe and reliable system. The review will detail common misconceptions of F&G devices, focusing on flame detectors and flammable gas detectors.

Methods, Procedures, Process
This will also review the significant cost savings which can be introduced when incorporating knowledge of how these instruments operate, and the hazards in question, in the F&G design. Taking account of these factors has been demonstrated to increase overall plant safety and greatly reduce the CAPEX costs of projects. It is also evident that when these systems are not adequately designed, the costs in unwanted shutdown/ plant down time can be unnecessarily excessive.
The paper will discuss the matters in light of the current challenging climate of the Oil and Gas Industry and how different disciplines must work together to ensure while overheads are being reduced, this is not at the expense of safety.

Results/ Observations/ Conclusions
The main conclusion to be drawn is that: 1) too much emphasis is placed on the simple percentage coverage achieved which can significantly over engineer a system; and 2) not enough emphasis is placed on the characteristics of the hardware being mapped which can cause issues at a later date with unwanted downtime.

Novel/ Additive Information
As the process industry moves towards the reduction of the potential for ‘fail to danger’ in safety related systems (with an increase in the prevalence of IEC 61508 and IEC 61511), it is of great concern that designs of fire and gas detection technologies (whether classed as a SIS or not) applied today still provide this potential, and even worse, these drawbacks may never be accounted for in design. In light of this, the guidance within the recent guidance document ‘ISA TR84.00.07 Guidance on the Evaluation of Fire and Gas System Effectiveness’ shall be reviewed with reference to its efficiency and what can be done better by those following the guidance, to ensure it remains relevant in the current challenging climate.
Ten Year ESP Mean Time between Failures, Reality or Fiction
Authors: Lastra Rafael 
Published: November 2016

Abstract
Improving Electric Submersible Pump (ESP) system reliability, eliminating or reducing failures, comprise the most frequent requests from O&G operators. Over the last few decades, notable design improvements have been made with the use of computer aided design, rapid prototyping techniques, and use space age materials. But the average ESP run life has increased marginally, and remains at around three years.
ESP failures have important economic implications for O&G operators, including: nonproductive time, production deferral, production losses, and high cost of ESP replacements, especially for offshore or remote wells. Operators have tried different approaches to incentivize ESP vendors to improve ESP reliability, including: performance based contracts, internal research, open research, joint industry projects, and market competition. Despite these efforts, the goal of a ten-year run life remains elusive.
Saudi Aramco has set a very aggressive target of operating ESPs for an average of ten years without failure. This paper explores the likelihood of developing an ultra-reliable submersible pump system that can meet this challenging objective. It discusses the fundamental issues that currently prevent achieving higher ESP reliability, and also evaluates potential approaches to the reliability improvement challenge. Finally, the paper examines technical, operational, economic and market implications of such alternatives, for both O&G operators and ESP vendors
Characterization of Stress Induced Azimuthal Anisotropy Using AVOAz Inversion
Authors: Nakayama Shotaro , Benson Mark Allen , Al-Khamiri Ahmed Mubarak 
Published: November 2016

Abstract
An OBC seismic data generally provides an opportunity to acquire wide azimuth data via azimuthal anisotropy analysis. However, it generally requires large amount of survey effort so OBC seismic data is sometimes sparsely and irregularly sampled. This led to several challenges during original processing and reservoir characterization using an OBC seismic data acquired in offshore Abu Dhabi.
To deal with spatial sampling sparseness and irregularity, we reprocess the data. For the improvement of spatial sampling, data interpolation and regularization using anti-leakage Fourier transform is applied. The process employs anti-aliasing capability along with 5D implementation (4 spatial coordinates and time) so reliable data reconstruction can be performed at any desired trace distributions. This yields enhancement of fold, offset and azimuth distributions of the data. In addition, 3D algorithms are implemented in several stages of reprocessing such as de-noise, de-multiple, imaging and velocity analysis, allowing for the preservation of offset and azimuth information. As a consequence, the reprocessing successfully addresses challenges in sparsely and irregularly sampled OBC seismic data, and consequently provides an optimum data sets for subsequent azimuthal anisotropy analysis.
Although the use of amplitude and/or velocity is considered as relatively quick and easy approaches to analyze magnitude and orientating of azimuthal anisotropy, they employs undesired effects and inherent limitations. To overcome those, AVOAz inversion is performed using the azimuthally sectored angle-stack data. The azimuthal attributes from the inversion clearly indicate a preferred orientation of NNE-SSW. By integrating different observations such as core description, well data and regional geology in a comprehensive manner, the inversion results can be interpreted as an indication of current stress regime in the field. The results also infer that the OBC seismic data with insufficient spatial sampling can potentially achieve to an equivalent data quality to a dense and full azimuth survey.
BHA Optimization for Surface and Bottom Hole Pressure Control in UBD Wells
Authors: Ge Q. , Shahat A. E. , Kodiah B. N. , Hay M. A. , Al-Hosani M. S. 
Published: November 2016

Abstract
Underbalanced Drilling (UBD) has become a popular technique in oil & gas industry, especially for well-developed hydrocarbon fields to minimize formation damage and maximize productivity. The key in UBD is to control bottom hole circulating pressure (BHCP). To maintain BHCP lower than the formation pressure, a light weight drilling fluid has to be used and probably with concurrent N2 injection. In the case of a tight reservoir, N2 injection rate is increased as high as 1500 SCFM, which will cause severe gas slugging and dramatic standpipe pressure (SPP) reduction when the gas is circulated though the choke. MWD signal will then be lost due to the pressure fluctuation. This paper will present a BHA optimization solution to maintain sufficient and stable SPP during UBD.
Two UBD cases will be discussed. Two main challenges were encountered in the first well: one was to reduce BHCP sufficiently low, the other was to maintain SPP high and stable. To reduce the BHCP, MWD pulser was changed from 180-280 GPM rating to 150-250 GPM to allow lower drilling fluid flow rate and increased N2 injection rate to 1500 SCFM. However, surface SPP dropped significantly due to gas slugging. To avoid this happen, the following optimizations were implemented in the second well: 1) added more HWDPs to reduce internal diameter of the drill string; 2) reduced bit TFA by using less nozzles; 3) installed flow rate restrictor in the drill string.
With reduced flow rate and increased N2 injection rate, BHCP was reduced to 300 psi below formation pressure. At the same time, with the optimized BHA, surface SPP was increased sufficiently to transfer MWD signal continuously. According to the simulation, among the 600 psi increase in surface pressure, 300 psi was from the restrictor, 150 psi was from the change of bit nozzles and 150 psi was from the added HWDPs. The main contribution was from the restrictor. Compared with the first well, which was drilled without restrictor, the data retrieved from the second well was smoother and more readable.
It was the first time that downhole flow restrictor was used in UBD well to maintain SPP. Combined with adding HWDPs and reducing bit TFA, SPP was increased sufficiently, whereby enabled continuous signal transmission and better data quality. Therefore, it is recommended to use this technique in the next UBD campaign.