bluuebunny/crossref_metadata_2025_split huggingface dataset:
Examining Heterogeneity based on the Computerized Tomography Imaging
Authors: Caliskan Sinan , Shebatalhamd Abdullah 
Published: June 2017

Abstract
Core analyses are carried out on the selected rock samples with the aim of establishing the basis of the building a data base to provide direct and quantitative measurements and interpretations about the reservoir characteristics. During a careful sample selection process, besides available conventional data such as porosity and permeability it is also important to understand the degree of heterogeneity that exists within the core samples. Computerized Tomography (CT) scanning technique, in this respect, has efficiently been used due to its non-destructive cross sectional imaging capability. CT scanning images obtained by medical type CT scanners are reconstructed on a 512×512 grid of pixels, with a typical resolution of 50 to 300μm depending on the sample size. Since the CT numbers are based on the density within rock samples, the heterogeneity analysis based on the CT numbers reflects the lithology of the samples being examined. Therefore, understanding the statistics of the CT images can significantly contribute towards an accurate classification and improved sample selection of the rock samples into different level of heterogeneities/homogeneities, which in turn significantly contributes towards the success of specialized studies, e.g. SCAL tests, Enhanced Oil Recovery and Acid Treatment. To examine the level of heterogeneity of rock samples on the basis of CT numbers, this study focuses on the application of statistical parameters, including Coefficient of Variation (CV) and Heterogeneity Index (HI) as well as histogram. The results indicated that only visual examination of CT images are not adequate but more thorough examination, such as statistical methods are required and have been proven to be an effective approach.
Modelling and Optimizing Inflow Control Devices
Authors: Todman S. , Wood G. , Jackson M. D. 
Published: June 2017

Abstract
Passive inflow control devices (ICDs) can redistribute the fluid influx (rate per unit length) into the well completion by causing additional pressure drops between the sand face and tubing. The aim of ICDs is to provide an increase in oil recovery and/or net present value (NPV) by reducing unwanted fluids. Software tools exist to model all aspects of ICD, reservoir, well and surface facilities. The challenge addressed by this paper is to provide an understanding of the implications for optimal ICD design over the life of the field, by integrating these models in a consistent manner.
This paper investigates different aspects of detailed ICD design on horizontal producers, using a wellcentric reservoir model. The ICD designs from the well-centric models were then applied to a full field reservoir model and integrated studies were then completed. This was achieved by linking several existing software to study the interaction between the ICD design, full field reservoir, well and surface network. Various aspects of the integration of these models were simulated including: artificial lift, water injection strategy and surface network.
Predictably, well-centric simulations showed that ICD designs are dependent on the objective function that is being maximized. If NPV is to be optimized, designing ICD strength to have higher production from the heel and toe regions of the well may produce better results than attempting to equalize the inflow for the entire well.
Integrated studies showed that artificial lift can be beneficial in combination with ICDs, as the ICDs redistributed the fluid influx into the well, yet the liquid rate reduction due to the additional pressure drop from the ICDs was mitigated. Even when ICDs were shown to be beneficial on standalone reservoir/well models, the design and predicted benefit when a surface network is coupled depends on: how the surface network is operated, surface network constraints and the relative water cut of the well which ICDs are applied to in comparison to the other wells in the field. These results show that ICD design and optimization requires an integrated approach to ensure outcomes that are consistent with the reality of the field.
Enhancing Production Using New Cable Deployed Electrical Submersible Pump - The First Trial and the Challenges Faced
Authors: Butt Qasim , Kothari Nikita , Boutamine Tahar Zoubir , Roth Brian 
Published: June 2017

Abstract
Coiled Tubing deployed Electrical Submersible Pumps (ESPs) have had a very short history in the oil and gas industry. The idea of installing a pump using coiled tubing was developed more than a decade ago which would allow the possibility of rigless operations and reduce the time for deployment/retrieval of the completion under "live-well" conditions. However, the initial attempts to define their economics were limited to comparing operational costs based on equipment and services, without considering the long term performance and gains over the life of the installation.
A new concept of power cable consisting of 3 mono-conductors has been developed in the past 2 years for deploying ESPs that eliminates the need for spooling and banding at the wellhead. The project has been a strategic development for ESP alternative deployment methods that would eliminate the need to move a work over rig on location to replace/service an ESP, making it more cost effective. A customer in Saudi Arabia has chosen the path of performing an initial recompletion of the well with this system with the benefits of the alternate deployment method during the periodic ESP replacements for resizing and wear out.
This paper outlines the details of the new cable deployed ESP system and the extensive considerations given to the deployment process to ensure safe and successful installation of the ESPs.
Water Control in High-Water-Cut Oil Wells using Relative Permeability Modifiers: A Saudi Lab Study
Authors: Al-Hulail Ibrahim , Shakeel Muzzammil , Binghanim Ahmed , Zeghouani Mohamed , Rahal Raed , Al-Taq Ali , Al-Rustum Abdullah 
Published: June 2017

Abstract
Water production in a hydrocarbon-producing well greatly affects the economic feasibility of a well, in worst cases, resulting in the well being shut in. Therefore, an effective water-control treatment program is important to help control water production and maintain or increase hydrocarbon production. Relative permeability modifiers (RPM) can be implemented in some high-water-cut wells as a chemical treatment to selectively reduce water production.
The study in this paper introduces an RPM system that is a hydrophobically modified, water-soluble polymer. This polymer is adsorbed on the rock surface, resulting in the alteration of the characteristics of rock surfaces. The unique polymer chemistry selectively reduces the water's effective permeability in the reservoir, impeding water flow and facilitating increased hydrocarbon flow. It can also help enhance the reservoir drainage area. Core-flooding experiments were conducted in the laboratory to assess the performance of the RPM system. Experiments were conducted on synthetic cores and formation cores from a well in the Central Arabia field.
The laboratory experiments showed that the RPM system can drastically help decrease water permeability, with low regained water permeability and high regained oil permeability in a synthetic core. The water regained permeability was 17% (i.e. 93% reduction in water permeability) in a formation core using formation oil and water. High-permeability core plugs were used in the laboratory to determine the effectiveness of the RPM system. A detailed procedure was followed, including repetitive oil and formation water cycles, to determine core permeabilities. The results demonstrate that the RPM system is effective in the Central Arabia sandstone formation.
This paper discusses the study performed to implement an RPM system in a Saudi formation, where the treatment can effectively reduce water flow in the treated area with minimum damage to hydrocarbon flow. The RPM system can be customized based on the temperature and permeability of the treatment zones to achieve maximum reduction in water production.
Sensitivity and Uncertainty Analysis of a Downhole Flow Metering System for an ESP
Authors: Ejim C. E. , Xiao J. 
Published: June 2017

Abstract
Downhole flow meters are needed in oil field applications to measure the amount of fluid produced from a well. One of their advantages over surface flow meters is measurement of in situ pressure and temperature, which provides additional wellbore information to reservoir and production engineers. This work involves performing uncertainty analysis on a downhole flow meter tested for use in oil field operations. It is an important step to determine acceptable measurement limits of the metering system.
To quantify the measurement uncertainty, the analysis was performed on a downhole, oil-water flow meter with an inlet pipe diameter of 0.076 m. The analysis covered differential pressures with corresponding flow rates from 0.0036 m3/s up to the maximum flow meter capacity of 0.0224 m3/s. The operating fluid temperatures varied from 32°C to 40°C, which consequently changed the oil and water densities and kinematic viscosities during the flow meter tests. For a given operating flow rate and temperature, the uncertainty in the individual measurement components of the meter were determined, and the overall metering system uncertainty established.
The results indicate that as the operating flow rate increased, the uncertainty in the flow rate reduced substantially. The increase in temperature had the effect of increasing the magnitude of the flow rate measured by the flow meter. The variation in the flow meter inlet pipe diameter introduced the largest uncertainty in the flow meter measurement. The uncertainty was in the order of a factor of two and higher compared to the next lower uncertainty contributor. These observations suggest the importance of ensuring accurate control of flow meter geometry and flow parameters, to ensure reliable measurements of fluid flow from the wellbore.
Installing downhole flow meters in oil field applications is an important step in gaining additional knowledge of reservoir conditions at the flow measurement location. It is vital to ensure that measurements obtained from these flow meters are accurate in field operations for good production decision making. This paper highlights the flow meter parameters contributing to its uncertainty and also provides recommendations to maintain its reliability in the field.
Laboratory Customizations and Field Application of Water-based Drill-in Fluid to Enhance Well Productivity – A Case Study from the Kingdom of Saudi Arabia
Authors: Pino Rafael , Abahussain Abdullah , Addagalla Ajay , Jadhav Prakash 
Published: June 2017

Abstract
Customizing a fluid system for drilling into the pay zone or working over an existing well requires a thorough understanding of the reservoir. Damage mechanisms while drilling in the pay zone include fine solids migration, clay swelling, drill-in fluid (DIF) incompatibilities with reservoir fluids, and the use of reservoir damaging chemicals that can reduce the average formation permeability and lower production rates.
A suitable drill-in fluid system must be chemically nonreactive with the rock minerals and reservoir fluids, and be less invasive to preserve the native state of the rock along with its natural wettability. The selection of the bridging particles type, size distribution, and concentration must be based on reservoir rock morphology and the calculated pore throat size distribution. An adequate selection rapidly establishes a tight, thin filter cake and an efficient bridging mechanism that prevents the invasion of filtrate and fine drilled solids deep into the formation, minimizing damage to the reservoir and the potential for differentially stuck pipe.
This paper discusses the extensive laboratory analysis performed to design a DIF system based on the reservoir characteristics. This customized DIF was then successfully field tested with predefined key performance indicators (KPIs) to drill two wells, each with a production interval of approximately 2,000 ft, in the Kingdom of Saudi Arabia. Fluid properties, along with particle size distribution of bridging additives, were continuously monitored and precisely controlled through drilling fluids engineering. The optimized drilling practices and hydraulics analysis also enabled us to improve hole cleaning, prevent influx, and minimize hole instability.
The First Successful Nitrogen Lifting Job without Stripping Out for a Gas Well in Saudi Arabia
Authors: Purusharthy Naresh K. , Alhamed Khalid I. , Fraikh Saud B. , Asel Sultan A. , Shammari Nayef S. , Atwi Mohammed A. 
Published: June 2017

ABSTRACT
This paper discusses the first successful in-Kingdom coiled tubing intervention in a well without conventional stripping-out of the well leading to significant cost savings, reduced risks, and compliance to Saudi Aramco environmental protection policies by adhering to a zero flaring initiative.
Conventionally, wells are shut-in, secured, and stripped out (depending on the operation, stripped out refers to the disassembly and removal of directly connected piping, cathodic protection, and other production system components) in preparation for performing any high pressure coiled tubing (HPCT) interventions (to allow crane and HPCT units to spot and rig-up). Wells are then again re-manifolded to the production system. These stages consume a tremendous amount of manpower, cost, time, and production loss. Unfortunately, some wells have severe condensate loading issues, to the extent that they tend to die again, during shutdown (re-manifolding period) after the lifting operation. A new approach was required to be developed to avoid asset depletion in problematic wells.
The new approach suggests eliminating the need for stripping out and re-manifolding by lifting the well while it is connected and flowing to the gas plant. Many challenges were encountered during this effort, including the limited space for spotting equipment around the well connections, well control, and well response monitoring. In addition, it was difficult to overcome the downstream pressure across the pressure control valve (PCV) to allow unloading the well under its own pressure drive.
The operation served as a benchmark for future wells. The operation turned out to be a huge success in terms of cost and safety. The avoidance of strip-out, re-manifolding, testing package, and producing to the gas plant instead of flaring resulted in significant cost avoidance and reduction in production time.
This paper will provide an insight on the reasons behind selecting this well as a potential candidate for the job. It will also shed light on the risk assessment aspects, both technically and environmentally, and the operational safety backup plan that was thoroughly discussed and implemented. In addition, the challenges faced throughout the whole process of selecting the well, conducting risk assessment, issuing the Management of Change (MOC), designing the rigless program, and finally commencing operations will be discussed to ensure obstacles in future operations can be minimized. At the end, lessons learned and recommendations will be shared to ensure that the highest levels of operational efficiency are maintained for similar cases in the future.
Solving Complex Petrophysical Characteristics to Unlock Hydrocarbon Potential of a Naturally Fractured Pre-cambrian Reservoir
Authors: Al-Rahbi K. , Al Wahaibi N. A. , Al Mamari O. , Hegazy O. A. , Yaarubi A. H. 
Published: June 2017

Abstract
The Buah formation has gained increasing interest in the search for new exploration plays in the Sultanate of Oman. Significant hydrocarbon accumulation has been discovered in the Buah recently. The Buah formation is complex in terms of lithology, pore structure, and the coexistence of oils with different gravities, including bitumen. The existence of bitumen makes it difficult to determine permeable and recoverable hydrocarbon intervals.
The rock characteristics of Buah formation impose significant challenges to traditional formation evaluation methods. Because of the low porosity, error tolerance for estimation is low. Saturation determination using resistivity logs is uncertain because of low porosity and inexact Archie parameters. These include the cementation factor (m) that accounts for water phase connectivity, and the saturation exponent parameter (n), which is sensitive to rock wettability. The wettability status is unknown. However, the existence of bitumen could greatly influence the wettability and thus the saturation exponent.
A formation evaluation workflow has been developed to provide accurate petrophysical parameters necessary to estimate stock-tank oil initially in place (STOIIP) and conduct static and dynamic modeling. The triple combo and elemental capture spectroscopy logs are first combined for the best total porosity estimate and lithology determination. Nuclear magnetic resonance provides a lithology-independent pore space hydrogen index, which improves the accuracy of the porosity estimate and also quantifies the bitumen-filled pore volume. Dielectric dispersion analysis provides water-filled porosity together with the water tortuosity exponent (mn) that is strongly related to the cementation factor that can be incorporated in resistivity analysis to obtain a better estimate of water saturation in uninvaded zone. Thus, the integration between nuclear logs and dielectric measurements enables the direct estimate of producible hydrocarbon. Conventional core analysis was used to categorize different rock types in this reservoir by using the reservoir quality index (RQI) approach.
The results of our analyses have improved the static model, and examination against production logging and the dynamic model has revealed the best contributing rock types, the importance of fractures, and the impact of bitumen in hindering production.
Dynamic and Static Extraction Efficiency
Authors: Rowe Mathew , Muirhead David 
Published: June 2017

Abstract
The conventional approach to gas extraction at the surface is often flawed because of static extraction efficiencies used during drilling operations; a dynamic approach has proven to be much more effective. A dynamic extraction efficiency correction captures inter- and intra-molecular interactions and physical changes in drilling fluid that are not captured by static corrections. To demonstrate the difference between dynamic and static extraction efficiency corrections, both methods were used to analyze multiple wells of various reservoir types.
For any extraction system, a dynamic set of extraction efficiency equations is used to adjust the chemical composition for variations in chemical concentrations, temperature, fluid properties, and extractor type. A vapor-liquid equilibrium (VLE) model was used to dynamically adjust the gas composition to reflect the extraction efficiency and to compare to a static extraction efficiency correction. These correction methods were applied to multiple wells to compare the dynamic and static methods in several types of reservoirs.
The use of the dynamic extraction efficiency method has enabled more than 25 organic and inorganic chemical species results to be provided in 10% of downhole pressure-volume-temperature (PVT) samples, without the need to calibrate vs. the drilling fluid system. In direct contrast, the static extraction efficiency method, which was calibrated vs. the drilling fluid, showed inconsistent results and more significant errors. These results clearly indicate that the dynamic extraction efficiency correction is the better solution for predicting formation fluid composition.
The ability to dynamically adjust a wide range of organic and inorganic chemical species with changing fluid conditions provided more accurate predictions of formation fluid composition than possible using static correction.
An Effective Streamline History Matching Technique
Authors: Anwar Awan R. , Mohamed Bouaouaja , Mustafa Amari , Zawawi Ahmed 
Published: June 2017

Abstract
The paper describes a comprehensive generic workflow that was developed to enhance the history match of the reservoir simulation model for fractured reservoirs. Commonly in the industry, such reservoirs are modeled in dual porosity, dual permeability (DPDP) mode; this is to account for the dominant effect of natural fractures. Additional complexity may be added for secondary/tertiary recovery processes and production history.
Streamline trajectory mapping provides insights about fluid flow patterns and well communications, which improves our understanding of flow in the reservoir and the dynamic behaviors. Additional streamline attributes, such as allocation factors and time of flight (TOF), can help in quantifying the degree of connectivity in the reservoir. All these factors were utilized to improve history match.
The workflow capitalizes on utilizing this information in methodic stages. The first step is to map the streamline and report their attributes for each timestep in the DPDP model. This first step accounts for the fluxes in both media: matrix and fracture. Once these results are obtained, the discrepancies between observed and simulated data for each well are computed, along with the graphical 3D analysis of the streamlines. These are then used to guide the modification of the target gridblock properties during history matching. It is required to perform few iterations, repeating the same procedure, to achieve acceptable history match results.
The presented approach is more time effective than the conventional method, and the results demonstrate large improvements in matching the dynamic data.
The Interpretation of Miscible Fluid Displacements in Multimodal Carbonates
Authors: Al Harbi Ahmad M. , Kwak Hyung T. , Gao Jun 
Published: June 2017

Abstract
The transport of fluids through a permeable rock can follow complex paths depending on the complexity of pore size distributions and connectivity. Understanding the contribution of individual pores to total flow helps to build representative relative permeability models for reservoir simulation of secondary and tertiary recovery applications. Whether or not micropores contribute to the flow will eventually affect the shape of the relative permeability curve of the two-phase flow. In addition, it affects the extent of the mixing zone during fluid displacement for any miscible enhanced oil recovery (EOR) processes.
Through a single-phase dispersion test, mimicking miscible displacement with continuous nuclear magnetic resonance (NMR) T2 distribution measurements, fluid displacements relative to pore type were directly observed and quantified. The displacement data was modeled using the classical convective-dispersive model.
Results illustrate that the micropores of the selected bimodal carbonate samples are preferentially connected and the micropores in M_1 petrophysical rock type (PRT) effectively contribute to the displacement/flow mechanism in these rocks. In addition, the experimental results from single-phase study suggests the contribution of micropores to the total displacment in the M_1 PRT should not be ignored when modeling relative permeability for reservoir simulation. The results from modeling the miscible fluid displacement data using the classical convective-dispersive model showed that micro- and macropores in M and M_1 PRTs communicate in parallel and in serial. This result should be accounted for designing any types of miscible and surfactant flooding for reservoirs with these PRTsas they are relevant to the extent of the mixing zone relative to pore types.