bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigating Low Resistivity-Low Contrast Resistivity Pay in a Permo-Carboniferous Reservoir, Central Saudi Arabia
Authors: Ayadiuno C. B. , Khan S. , AlAbbad A. A. , AlMohsen F. 
Published: November 2017

Abstract
The Permo-Carboniferous reservoirs of central Saudi Arabia comprise important accumulations of natural gas and light oils. Some of the reservoirs exhibit low resistivity and low contrast resistivity (LRLC) phenomena. Low resistivity pay reservoirs often produce gas/oil with little or no water at very low resistivities. Low contrast resistivity pay zones, on the other hand, produce hydrocarbon at minimum resistivity contrast between hydrocarbon-bearing intervals and adjacent water-wet or shaley zones. Evaluating these types of reservoirs poses a major challenge to petrophysicists and petroleum engineers due to the difficulty in recognizing them on logs and quantifying their hydrocarbon potential when using simple resistivity-based petrophysical models. As a result, potential pay zones can be incorrectly evaluated or bypassed. The objectives of this study, therefore, are: 1) to understand the causes of LRLC pay in the study reservoirs through a detailed assessment of the textural and mineralogical composition of the rock, and 2) to validate a simple porosity-based methodology for recognizing LRLC pay in both old and new wells.
To achieve the set objectives, 38 core samples and 107 thin sections were selected from two wells exhibiting low resistivity (Well-1) and low contrast resistivity (Well-2) phenomena, for detailed petrographic and mineralogical studies (SEM/XRD). Furthermore, a water salinity map was created to provide general salinity trends in the area. Well data combined with results of mineralogical and petrographic studies suggest that low resistivity and low contrast resistivity pay in the study reservoirs is the product of a complex mix of: 1) clay mineral types and its mode of distribution, 2) thin reservoirs below resistivity tool resolution, 3) significant grain size variation and microporosity, and 4) variable formation water salinities.
This paper highlights the causes of low resistivity and low contrast resistivity phenomena in reservoirs in central Saudi Arabia. Furthermore, the applicability of a porosity-based methodology for recognizing LRLC phenomena was verified with promising results.
Low Pressure Operation LPO: Extending Field Life of Several High H2S Fields with Minimum Costs
Authors: Hadhrami A. , Mihajlov R. , Muthalaly M. , Schulz R. , Alias Z. , Riyami A. , Abri Z. 
Published: November 2017

Abstract
Several high pressure (up to 1000 bar), deep (3-5 km) and high sour oil (H2S/CO2 up to 10%/25%) fields have been in primary depletion production in the Southern Sour Cluster in Petroleum Development Oman (PDO) for the last several years. These fields are currently nearing lift-die out or have already experienced lift die out. These carbonate (and silycillite) fields form stringers which are encapsulated by salt and thus lack natural aquifer support. The only drive mechanism has been up to now fluid (and rock) expansion. Artificial lift in form of high cost Electrical Submersible Pumps (ESPs) was attempted in 3 wells and failed due to suspected design and installation issues, including depth of the reservoir. To extend the depletion production life a Low Pressure Operation (LPO) has been proposed across all the 3 stations within the cluster and all currently being executed. LPO makes smart and sustainable use of existing facilities by simply re-routing incoming trunk line in three stations to the low pressure separator. Several other options were screened but were found to be less attractive. LPO will allow continuation of depletion production for several years until Miscible Gas Injection (MGI) is implemented as a next development phase. LPO concept is commercially extremely attractive with very low Unit Technical Costs (UTCs) of less than $10/bbls and high Value Investment Ratio (VIR) of more than 20.
Impact of Irreversible Retention on Tracer Deployments; Constraining Novel Material Deployments
Authors: Chen Hsieh , Kmetz Anthony A. , Cox Jason R. , Poitzsch Martin E. 
Published: November 2017

Abstract
Full field inter well tracer programs have become more and more ubiquitous for effective reservoir surveillance. Novel tracer materials with much higher detectability and lower costs have been actively screened. One of the biggest challenges in deploying novel material types, however, is their elevated irreversible retention to reservoir rocks. Herein we benchmarked traditional inter well tracer chemicals and then the sensitivity of ever-increasing irreversible retention that might be associated with unconventional materials.
Using field-scale reservoir simulations with a Langmuir-type tracer irreversible retention model, we rigorously test the limits for tracer irreversible retention in order to have successful inter well tracer test (IWTT). Specifically, we studied the tracer breakthrough peak concentrations as a function of tracer irreversible retention as well as inter well spacing in synthetic waterflood patterns. Custom reservoir simulator functionalities were built to perform the simulations. Additionally, coreflood experiments on common oil field tracers were conducted to acquire independent irreversible retention values and compared to the modeling results.
For the reservoir simulations, we first tested the ideal tracer case with no irreversible retention and found perfect agreement with the standard Brigham-Smith model. We then tested for tracer breakthroughs with increasing irreversible retention values and found that the tracer breakthrough peak concentration drops off dramatically. With the consideration that the limit of detection (LOD) of contemporary analytical instruments are at the part per trillion (ppt) level, the simulation results suggested that the tracer irreversible retention should be less than 10 μg/g-rock (mass of adsorbed tracer / mass of rock) in order to have meaningful IWTT with a well spacing of 2000 ft and an injection tracer mass up to 100 kg. Finally, two field tests using fluorobenzoic acid (FBA) based tracers deployed in the highly saline and retentive carbonate reservoirs in Saudi Arabia were compared. The irreversible retention number of the FBA based tracers was estimated to be less than 5 μg/g-rock from the model. Corresponding coreflood experiments for FBA tracers in high temperature and salinity carbonate cores show 0 +/− 10 μg/g-rock irreversible retention number within error ranges, verifying the prediction of our simulation results.
This paper broadens the scope of the extensively used Brigham-Smith tracer behavior model by incorporating tracer irreversible retention effects. More accurate design and interpretation of inter well tracer tests may be achieved through the new insights presented. Better waterflood management can then be established because of the reduced uncertainties from the more precise tracer data. In addition, this study set an unambiguous standard for the tolerable irreversible retention limits for any new materials targeting inter well tracing applications.
Advanced Fracture Modeling: Lab Experiments to Field Applications
Authors: Gosavi Shekhar V. , Kumar Sandeep , Kirane Kedar , Garzon Jorge , Sanz Pablo , Biediger Erika , Searles Kevin , Nygaard Kris 
Published: November 2017

Abstract
This article describes the development, validation, and application of a fully coupled Finite Element (FE) framework for modeling of hydraulic fractures in the context of a diverse set of oil & gas (O&G) problems. The models have been developed within a fully-implicit non-linear FE solver, and comprise two widely established fracture modeling methods: Cohesive Zone Method or CZM (mesh conforms to a pre-defined fracture path) and eXtended Finite Element Method or XFEM (fracture geometry evolves independent of the finite element mesh).
The models were verified by comparing simulation results with analytical solutions for the four asymptotic regimes of fracture propagation. The models were also experimentally validated, which involved comparing simulations with carefully conducted polyaxial fracturing experiments. For this purpose, a comprehensive set of laboratory-scale polyaxial fracturing experiments were conducted. Then, the finite element models were used to simulate these experiments, and the simulation results were compared with the experimental results.
The applicability of these models spans conventional as well unconventional fracturing problems, including 3D multi-zone injection, diagnostic fracture injection tests, and multi-stage hydraulic fracturing. To demonstrate this, a number of field-scale models are constructed and applied to a broad range of O&G problems involving fracture propagation at large length and time scales. These include a Step Rate Test (SRT), a Produced Water Re-injection (PWRI) problem, and a Cuttings Re-Injection (CRI) simulation. These large length- and time-scale simulations were enabled by a high-performance, massively parallel computing system.
Through the various validation exercises and the field examples discussed in this work, we intend to demonstrate the applicability of the newly developed fracture modeling capabilities in successfully simulating real problems ranging from laboratory-scale to field-scale.
Sampling From the Posterior in Reservoir Simulation
Authors: Ramirez B. A. , Gelderblom P. P. , Eales A. D. , Chen X. , Hobson M. P. , Esler K. 
Published: November 2017

Abstract
In recent years, there has been significant effort within reservoir engineering to move towards reservoir simulation studies that rigorously accounts for uncertainties in the model parameters when developing production forecasts. Probabilistic history matching approaches play an increasingly integral role in the calibration of subsurface reservoir models to dynamic data. In a Bayesian fashion, the calibration process employs prior distributions for the uncertain parameters and the likelihood function to generate posterior distributions.
Due to the impossibility of having a closed form for the reservoir simulation evaluations, uncertainty quantification is done via sampling methodologies. Markov Chain Monte Carlo (MCMC) is the widely-accepted uncertainty quantification technique used for this purpose. MCMC applications often require several millions of evaluations of a forward model. In reservoir engineering, each forward evaluation (reservoir simulation) can take hours, direct application of MCMC is too computationally expensive in most real-world applications.
In reservoir simulation applications, sampling is usually performed indirectly via proxies, which replace each forward evaluation with an inexpensive one. The accuracy of the results relies strongly on the ability of the proxy to robustly represent the high-dimensional relationship between the model parameters and the simulator output. The industry standard, polynomial response surface regression, can be quite inaccurate when assessed using blind testing. In addition, the number of simulation runs required to construct an adequate proxy model can itself be prohibitively large.
We present a novel application of Bayesian inference within the reservoir simulation domain. A parallelized nested sampling workflow is integrated with ultra-fast reservoir simulation technology running on Graphics Processing Units (GPUs). MultiNest, a variant of nested sampling, has been shown to require fewer number of runs than conventional MCMC algorithms such as Metropolis-Hasting. In large models, GPUs significantly accelerate each forward evaluation compared to models running solely on Central Processing Units (CPUs). The combination of nested sampling and accelerated simulations results in a rigorous methodology that can be used to quantify uncertainty in reservoir simulation workflows.
The methodology has been applied to synthetic models and field models. It is affordable in terms of cost and elapsed time. Examples are shown to illustrate the capabilities of the workflow.
Comprehensive Role of Structural Integrity Management for Offshore Assets – Project Case
Authors: ELHabbal Mohamed 
Published: November 2017

Abstract
Structural Integrity management (SIM) system is considered one of the main pillars of Asset Integrity Management (AIM) as SIM system role is to ensure and maintain asset structural integrity and fitness for purpose allowing assets owners to flexibly accomplish their business objectives and achieve sustainable operation of their assets. For Offshore and subsea Assets; the importance of SIM gets even more due to the high costs of Inspection, Maintenance and Repair (IMR) activities.
The objective of this paper is to introduce to the Oil & Gas stake holders in the offshore market a deep understanding of SIM methodology and the procedures of establishing SIM system for their assets according to the API RP 2SIM practices which is considered one of the state-of-art practices to manage fixed offshore platforms integrity.
The paper objective is achieved by representing a true project case applying practices and procedures of API RP 2SIM for a 120 Platform fleet using Qualitative (Risk Based) approach describing the basis of platforms data gathering, categorization, ranking and selection for assessment, setting inspection strategy & planning.
It is concluded from this paper that SIM system is an enabler of the success of AIM system, and qualitative approach is considered a reliable and economic method for dealing with SIM projects, wall thickness measurements has a key role in the integrity of offshore platforms, software has a key role in SIM system sustainability and finally acceptance criteria is one of key issues that needs to be addressed in SIM projects. Added to that a set of recommendations is proposed to API RP 2SIM that might be useful to be considered next version.
This paper shares with our stake holders in the oil & gas market a valuable experience of constructing a SIM system for operators using a real life project case, introduce comprehensive application of recommended practices and finally deepen the awareness of importance of SIM systems for sustainable development of offshore oil & gas assets.
Optimization Of Green Field Development Using Multi-Realization Approach
Authors: Semenov Andrey 
Published: November 2017

Abstract
One of the widely known use cases of 3D simulation model is the field development optimization. This task usually requires multiple numerical experiments (simulation runs) under different scenario conditions. Analysis of the huge space of input parameters and multiple runs is time consuming. Also, there is a lack of logic in such process driven by common management requests "run the case". In the scope of the paper, the system approach for analysis of broad parameters space is presented combined with robust techniques for analysis of multiple numerical experiments. The method is demonstrated on the example of solving 2 tasks: determination of the optimal gas usage distribution and selection of the best water injection strategy.
2 separated 3D reservoir simulation models were used in the study. Models have been constructed in commercially available reservoir simulator and another tool was used to substitute variable model parameters by modifiers. Gas injection rates, maximum reservoir production rate, water injection rates, positions of water injection wells, and target reservoir pressure were investigated to find the optimal (in terms of cumulative oil production) reservoir development strategy. On the final step, optimal reservoir development strategy was utilized in the integrated reservoir simulation model.
Based on the analysis of multiple runs with different combinations of reservoir management parameters, the optimal development strategy was formulated for 5 reservoirs. Implementation of optimal positions of water injectors is adding 2% to recovery factor. Usage of proper injection gas allocation strategy is allowing keeping average reservoir pressure above minimum miscibility pressure during the whole reservoir development time and substantially increases cumulative oil production. Summarizing, implementation of the optimal reservoir development strategy (maximum reservoir production rates, gas and water injection rates, and injection wells position) is absolutely crucial for success of reservoir development. Advanced optimization approach using multiple realizations of input parameters was used. More than 100 runs have been simulated and analyzed with prior and posterior distributions of parameters.
Experimental Investigation of Cuttings Transport in Horizontal Wells Using Aerated Drilling Fluids
Authors: Gul Sercan , Kuru Ergun , Parlaktuna Mahmut 
Published: November 2017

Abstract
An experimental study has been conducted to investigate the cuttings transport in horizontal wellbores using aerated drilling fluids. An advanced flow loop system with 21 ft. long annular test section composed of 2.91-in. ID transparent casing and 1.85 in. OD inner drill pipe has been used for the experiments.
Aerated fluids were composed of air/water and air/drag reducing polymer fluid mixtures. Partially hydrolyzed polyacrylamide (PHPA) copolymer was used as a drag reducing agent. Drag reducing polymer fluids (i.e. water-polymer mixtures)were prepared usingPHPA concentrations of0.05% V/V, 0.07%V/V, and 0.10% V/V. The optimum PHPA concentrationwas found to be 0.07%V/Vresulting maximum drag reduction of 41.88%.
Four different flow regimes were identified along with the flow of aerated fluids as bubble, elongated bubble, slug and wavy annular regimes. Adding PHPA polymers in water delayedthe transition from slug to annular wavy flow regime (i.e. for a given liquid flow rate the transition from slug to wavy annular flow regime was observed at higher gas flow rates).
The annular area occupied by the cuttings decreased with the increasing liquid(both water and polymer fluid) and gas flow rates. However, increasing the liquid flow rate was more effective in terms reducing the cuttings bed deposition.
On average, the use of 0.07% PHPA polymer fluid with air for cuttings transport caused 23.90% drag reduction while reducing the annular area occupied by the cuttings by 4% and cuttings bed height by 13.78%.
Though cuttings transport performance of the various flow regimes did not show significant difference, Wavy Annular flow regime seemed to be the most effective flow regime in terms of cuttings transport among the others.
Recent Exploration Activities in Eastern Onshore Abu Dhabi: Implications of the First Exploration Well in 30 Years in the Region
Authors: Fava L. , Rock G. , Conradi F. , Aliabadi R. , Kwiecinski E. , Shateri A. Al , Witte J. M. , Hijleh Y. I. 
Published: November 2017

Abstract
OMV and ADNOC signed a study agreement in 2013 to explore for hydrocarbons in a large (10,000km2) under-explored onshore area, named East Abu Dhabi. The objective of the work programme was to evaluate the conventional and unconventional hydrocarbon potential within multiple play types and structural settings, via the analysis of existing vintage data, acquisition of new seismic followed by exploration drilling.
To date 1,800km2 3D (4S) and 700km 2D seismic have been acquired focused on two principal play types; namely, the ‘Pabdeh’ stratigraphic play and the ‘Thamama’ combined structural/stratigraphic play. Additional studies completed include fluid inclusion stratigraphy using data from nearby vintage wells, and the completion of an unconventional study covering the wider area of interest. The first OMV operated exploration well reached its TD in the Jurassic in March 2017. Two tests have been performed in Lower Cretaceous and Jurassic resulting in a dry sour gas discovery.
The main results of the well that have an impact on the understanding of the regional geology can be summarized as follows: 1) Source Rock, three potential source rock intervals have been penetrated (Middle and Lower Cretaceous & Jurassic). 2) Reservoir, The middle Cretaceous has been found in a back-shoal facies with its suggested corresponding platform margin being located in close proximity to the South-West. The Aptian is represented by the classical Lower Shuaiba fm. and overlain by the Bab shales. No isolated platform has been encountered. 3) Clear stratigraphic and structural evidence supporting structural deformation of the Thamama Group during the Lower Cretaceous. Several distinct fault trends are evidenced from both the well data and 3D seismic depth slices. Understanding these faults and related fracture systems will be fundamental in understanding the play potential in the wider area.
This is the first exploration well to be drilled in the area since the ‘80s. Multiple intervals of regional interest have been encountered spanning the massive loss circulation intervals of the Palaeocene, conventional and unconventional reservoir within the Middle Cretaceous, the entire Lower Cretaceous sequence and the Asab equivalents of the Upper Jurassic.
Alert Today, Alive Tomorrow! Embedding Process Safety Across Organization
Authors: Khan Shamsuddin Ahmad 
Published: November 2017

Abstract
What is difference between Process Safety & Personal Safety?
How can you contribute in making your work place safe?
How your routine activity can prevent Process Safety Incident?
These are few of the questions commonly asked in industries now-a-days. During the past decade, industries have made tremendous efforts in developing robust and effective systems in Health, Safety & Environment, now it is call of the day to focus on Process Safety as well. Process safety differs from personnel safety and has to be dealt differently. Personnel safety deals with injuries that a worker can suffer while doing his job, such as burns, cuts, strains, and fume exposure, while process safety starts with failure of an equipment or system to perform its intended function, thus leading to catastrophic fires, explosions, and toxic releases. Process safety incidents have the potential to kill or injure many workers and even neighbors of the facility and can even lead to long term or permanent shut down of a processing facility.
Process safety leadership and culture are recognized as key factors for effective process safety management implementation. Everyone working in any industry should enhance awareness of his team & himself towards Process Safety and to initiate a drive towards developing Process Safety Culture within organizations whereby mitigation & elimination of potential hazards is embedded in the attitude of every individual.