bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advances in Reservoir Modeling: A New Approach for Building Robust Reservoir Models
Authors: Kayode B. , Qahtani G. , Thawad F. , Hage A. 
Published: June 2017

Abstract
Due to reservoir description uncertainties, the building of multiple geologic realizations has become an acceptable industry standard for geo-modelling. This paper discusses an approach to rank these multiple realizations, and to determine the geological realization(s) which is/are the closest to reality. It then describes how to further calibrate this best ranked geo-realization(s), especially in situations where there are no production and static pressure data to be used for history matching.
The proposed approach allows us to screen multiple geologic realizations using pressure transient data, and to improve the distribution of permeability away from well control points. The objective is to Rank the several geo-realizations on the basis of global best fit between the simulated pressure transient derivative and the observed pressure transient derivative, then perform a history Match of the pressure derivative for the best geo-model using permeability multipliers, and finally, create a permeability multiplier map, and Spread this permeability multiplier map over the entire best fit geo-model.
Sometimes, the observed pressure transient data may indicate a boundary away from the well, which the original static geo-model may not capture. More so, information from 3D-siesmic may not also indicate any barrier near this well. Using this proposed approach, we can reproduce the well's pressure transient by introducing stratigraphic features in the static model. In the conventional approach, static modeling is solely based on core data measured at well control points, but in this new approach, a dynamic correction factor based on average drainage area permeability is also applied, resulting in a better characterization of the permeability and boundary features.
This approach adds an additional layer of reservoir characterization to geo-modeling by ensuring that the geo-model contains as much dynamic features as possible. In the case of non-producing fields, where there is no further history matching to be done, this new approach guarantees a more reliable static geomodel.
Pushing the Technical Limits in an 8½-in. Section of Manifa ERD Wells Through a Redesigned PDC Bit and Reengineered Drilling Practices
Authors: AlDhafeeri Bader , Alhathelool Mohammed , Salem Loay , Al-Aftan Fahad , Al Mutairi Yousef , Ghazzawi Ayman 
Published: June 2017

Abstract
Over the field development life of the Manifa extended-reach-drilling (ERD) project, extensive drilling tools and practices were introduced to continuously improve drilling performance and well delivery times.
One of the main challenges encountered in Manifa ERD wells lies in landing the 8½-in. section into hard carbonate rocks. Historically, a motorized rotary steerable system (RSS) was used to manage the downhole stick/slip and vibrations experienced by the bottomhole assembly (BHA) while crossing the interbedded hard layers in the 8½-in. section. Engineering efforts were implemented to determine an alternate drilling strategy for the 8½-in. section to overcome such drilling challenges—at lower cost and with a higher performance impact.
Using 4D simulation software, the drill bit was completed remodeled so it could be used on an RSS BHA and still minimize the vibration on drilling tools. This involved revising the cutter count, cutter placement, angle of attack, hydraulics, and gauge configuration. In addition, a thorough drilling parameters road map was modeled to help mitigate downhole vibration. The objective was to constantly remain within the RSS and measurement/logging-while-drilling (MLWD) tool shock limitation to increase their life and ensure reaching the target entry in a single run. Drilling practices were optimized by focusing on improving connections and reaming times without compromising hole cleaning. This performance initiative was implemented in the field in three steps and resulted in unprecedented drilling performance, achieving a record in drilling this long directional 8½-in. section.
As a first step, the redesigned drill bit was introduced in the field to verify the design output in the field and gather the drilling parameters and shock and vibration data with this new design. The design delivered as expected and increased rate of penetration (ROP) by 67% compared with previous records with no shock and vibration recorded on BHA equipment. The second step focused on following the modeled parameters road map from the simulations and improved ROP a further 7%. In the third step of this project, new drilling practices were implemented, which minimized connection and circulation time while maintaining good hole cleaning, tracking of pickup and slackoff weight, and correlating with the torque and drag analysis. The overall drilling performance improved with an increase of 37% in ROP (97.1 ft/hr) over the last record. A total savings of USD 180,000 was achieved on this third attempt, and a new approach to the ERD wells was implemented by the operator's drilling engineering team.
This paper will review the progressive design process and will present the detailed results for each run. Insight will be provided on how this process can be applied to increase ROP performance and reduce cost per foot in a variety of drilling applications.
Critical Micelle Concentration of Different Classes of EOR Surfactants under Representative Field Conditions
Authors: Fuseni Alhasan B. , Al-Zahrani Badr H. , AlSofi Abdulkareem M. 
Published: June 2017

Abstract
The critical micelle concentration (CMC) of surfactants represent the concentration at which surfactant monomers start to form aggregates in order to minimize the energy of the electrostatic and hydrophobic interactions of the system. At this concentration, any additional surfactant molecules are not available at the interface but in aggregates in the bulk of the solution. A measure of CMC for a field surfactant gives an indication of the concentration needed for its effectiveness as an enhanced oil recovery (EOR) agent. This has been shown to be dependent on several factors including the nature of the brine, temperature, and ionic species strength. As such, for field applications, CMCs need to be measured for the particular environment that the surfactant will be used in.
In this work we have measured the CMCs for three types of EOR surfactants. The Du Noüy ring method was used with an automatic dispenser to dilute and measure surface tensions of the various surfactants at different temperatures and in different field brines. The effect of other chemical species, especially polymer was also investigated. Of the three surfactants studied, the betaine surfactant showed the lowest CMC in both injection seawater and field produced brine. It also out-performed the others in temperature stability for all types of brines. The other two surfactants were an amine oxide and an alpha olefin sulfonate. For the field brine conditions, the amine oxide proved to be the poorer performer in terms of CMC while the anionic alpha olefin sulfonate was close to the amphoteric surfactant.
Determination of CMC for real field brine conditions and at elevated temperatures provides a good insight into the performance and potential of different surfactants. Coupled with other tests like phase behavior and interfacial tension (IFT) measurements, very quick decisions can be make about the efficacy of surfactants for field application.
Geophysical Surveillance of a Steam Injection Project in a Kuwait Heavy Oil Field
Authors: Al-Mutairi Amal , Biao Ren Zu , Al-Haqqan Hamad , Tinnin John 
Published: June 2017

Abstract
Kuwait Oil Company conducted a geophysical surveillance program to optimize development options in a shallow heavy oil field in Kuwait. Two optimized 3D Vertical Seismic Profiles (3DVSPs) were acquired in January 2016 to help understand the effectiveness of this EOR project. Goals of this project included acquiring repeatable baseline surveys for 4DVSP surveys, attaining high resolution 3DVSP data, imaging the sealing cap rock shale and two thin vertically stacked reservoirs, and estimating the steam chamber size just after a 30-day steam injection cycle.
One major problem with recording shallow VSP data is the possibility of spatial aliasing due to the slow propagation velocities of P and S waves affecting the ability to achieve desired frequency range. Therefore extensive pre-survey modeling was required in order to determine the optimum source-receiver configuration. The team decided on innovative survey parameters purposely designed to obtain higher frequencies than previously attained in this area to improve the vertical and spatial resolution sufficient to achieve the project goals listed above. The resulting two 3DVSP datasets were then processed and imaged using a patented vector pre-stack Kirchhoff depth migration. Inversion work and qualitative interpretation were then applied to both data volumes to help achieve all the desired goals.
Extensive planning and flawless execution of the two-well 3DVSP operation resulted in the completion of both survey acquisitions in a total of 13 days without incurring any QHSE incidents and having 100% operating efficiency. Frequencies obtained in these surveys were more than 30% higher than previously achieved in this same area. These high frequencies resulted in vertical resolution sufficient to image the sealing shale layer and both of the steam injected reservoir sands as well as the necessary spatial resolution to image a small steam chamber. The novel modelling, acquisition and processing/interpretation methodology described have demonstrated that accurate subsurface imaging in this environment is achievable. The results have contributed to and altered the steam flood expectations and will provide key information that would not otherwise have been available to develop the best development options. Additional 3D and 4DVSPs are currently being acquired.
Extensive modeling enabled innovative customization of an innovative acquisition design, optimized acquisition operations, parallel processing, and interpretation techniques have allowed for a time efficient acquisition-to-results turnaround.
Applicability of Using Electrical Downhole Heaters in Sudanese Oilfields, Modeling Supported
Authors: Elgadi Mussab , Mahgoub Musab 
Published: June 2017

Abstract
Heavy and waxy crudes reduce production, lifting performance and may cause production loss. The common way to solve this problem in Sudanese oilfields is through using Cyclic Steam Stimulation(CSS) technology, however this method has limitations, which made the proper solution is to use Electrical Downhole Heaters (EDH). Unfortunately no body studied EDH application in Sudanese oilfields. This project shows the possibility of using EDH technology in Sudanese oilfields with waxy crudes.
A comprehensive study for literature review for this technology and the types of EDH in terms of components and installation were done. Also number of companies with expertise in this area have been reviewed, with subjective analysis to their case studies. A computational model was developed by using Microsoft excel sheet associated with sensitivity analysis to find major parameters that have a large impact on results. Based on the modelling number of Sudanese fields and wells have been selected to study the possibility of applying this technology to them, by comparing the case studies for wells where this technology was successfully carried out, with some selected wells. A comparison between EDH and CSS in term of process and cost was done.
Simplified model was developed; in order to predict heating cable performance and energy required to heat a well. It was found that (API gravity, pour point, viscosity, downhole temperature and depth) are the major parameters affecting heating performance; by applying the sensitivity analysis. According to our screening and design, we found that the selected wells will give even better performance than ones listed in the literature. It is highly recommended to apply this technology in fields like (Fulla central, Moga, Bambo, Rawat, Hilba, Azrag). finally the economic evaluation illustrates that the cost of using EDH is three times less than using CSS.
This project is not only have huge impact in the oil industry in Sudan, but also shows that there are remarkably high economical value for using EDH.
How Geomechanical Study Helped Minimize Drilling Challenges in Highly Deviated Wells, Offshore, Saudi Arabia: A Case Study
Authors: Ahmed Mujahed , Al-Dossary Khalid S , Baim Ahmad S , Al-Hamad Nasser A 
Published: June 2017

Abstract
A geomechanical study was conducted for one of the drilling platforms in offshore Saudi Arabia, where several highly deviated (well inclination &gt; 80°) development wells were planned. The main objective was to provide safe mud weight ranges and predict possible problematic depths to minimize drilling challenges like pack-off, stuck-pipe, lost in hole, over-pulls etc., which are likely due to wellbore instability. The scope of this work was restricted to the curve section of the planned wells because most of the problematic formations, comprising mainly shale and weak interbedded sand formations, are encountered in the curve section.
The operator's drilling department sought a clear understanding of the geomechanical aspects of these problematic formations to optimize the drilling plan and minimize nonproductive time. A 1D mechanical earth model (MEM) was constructed using openhole log data available from the only exploratory well drilled on this platform. The 1D MEM was further used in conducting post-drilling analyses to validate and history match events related to wellbore instability (like tight spots, pack-off etc.,) that were observed while drilling and stress-related wellbore failure as shown by the calipers.
The developed model was used for analyzing planned well trajectories and providing mud weight window limits to safely drill the highly deviated planned wells. Sensitivity analysis was performed to identify the well inclination limits to drill across the problematic zones whilst minimizing issues related to wellbore instability. The developed geomechanical model was validated using the log data acquired during drilling each of these inclined wells; the predictions from the model were in close agreement with actual observations during drilling.
The outcome of this study helped optimize the well design for upcoming wells in this field. Using the recommendations provided from this study, several highly deviated development wells were successfully drilled and completed. Apart from standard failure analysis, ‘depth of failure’ approach was also taken into account to provide recommendations on optimum drilling mud weight. Utilizing the geomechanical study, extended reach curve sections as long as 5000-ft measured depth (MD) were planned and drilled successfully without any significant nonproductive time (NPT).
A Reliable Method for Determining Fast Shear Azimuth of Sonic Data
Authors: Hamid Osman , Ahmed Omair , Hussain Aborshaid , Ba-Wazir Omar 
Published: June 2017

Abstract
Quantifying anisotropic rock properties from sonic data is a well-known approach that has many applications. For instance, the percentage sonic anisotropy in the formation provides vital knowledge when constructing Geomechanics mechanical models and when determining optimum well trajectory for horizontal wells. One of the main outputs from sonic anisotropy processing is the fast shear-wave polarization azimuth (FSA) derived from auxiliary tool orientation measurements included in the tool string with the sonic tools. This FSA is polarized along the direction of fracture strike, in case of fracture-induced anisotropic zones, and /or along maximum horizontal stress, in case of stress-induced anisotropic zones.
When the hole shape is oval in one axis by breakouts and in gauge in the other axis, the sonic tool remains oriented in one direction throughout logging intervals. As a result, the fast shear azimuth will be stable in one direction. This locked direction inherently has a 90° ambiguity if interpreted wrongly particularly if no borehole image data were available to validate this direction from the strike fractures or breakout directions.
The main objective of the study in this paper is to validate the direction of FSA, and then horizontal stress orientations, from sonic data in vertical wells when the sonic tool keeps a singular orientation throughout the logging and no borehole image data are available to support the direction of horizontal stress orientations. This validation is represented through a graphical interpretation of the FSA, both qualitatively and quantitatively, at intervals that exhibit stress-induced anisotropy and without assist from borehole image interpretations.
Three examples are presented in this paper. The first one shows a determining of the maximum horizontal stress from the graphical interpretation of FSA after processing the sonic data. This interpretation is validated with image data. The other two examples are from wells where only sonic data is used to determine the horizontal stress orientations using the FSA graphical technique
NanoSurfactant for EOR in Carbonate Reservoirs
Authors: Abdel-Fattah Amr I. , Mashat Afnan , Alaskar Mohammad , Gizzatov Ayrat 
Published: June 2017

Abstract
A new class of surfactants for enhanced oil recovery (EOR) applications has been developed in the form of petroleum sulfonate salt nanoparticle dispersions in seawater. These NanoSuractants (NS) are 10- to 60-nm particles of the seawater-insoluble petroleum sulfonate salts, one of the most abundant and inexpensive industrial surfactants, that are resiliently stable in seawater at elevated temperatures via a special class of co-surfactants. They can be easily prepared in the field by mixing with seawater at ambient temperature and injected into the reservoir with seawater without any additional infrastructure. The colloidal nature and extremely small size of the NanoSurfactans particles allow them to migrate and deliver petroleum sulfonates to remaining and residual oil deep in the reservoir without the need of large quantities in order to compensate for losses by adsorption onto the rock surfaces and diffusion into water-filled small pores. This paper reports on the results of few tests conducted to evaluate the performance of NanoSurfactant formulations under reservoir conditions. Results showed consistent colloidal and chemical stability of the NanoSurfactant formulations for over six months at 100°C. They reduced the seawater-crude oil interfacial tension (IFT) by two to three orders of magnitude or formed oil-in-water emulsions at 100 °C without any mechanical mixing. Transmission electron miscroscopy (TEM) images revealed mostly round particle in the submicron range (10- to 60-nm). Finally, core-flood test at reservoir conditions using bottom-hole live oil samples indicated an additional oil recovery of about 7% of OOIP beyond several pore-volumes flooding with seawater by injecting 0.4 pore-volume of the NanoSurfactant at 0.2 wt% concentration.
A Low Elastic-microsphere/surfactant/polymer Combined Displacing Method after Polymer Flooding
Authors: Yang Hongbin , Kang Wanli , Yin Xia , Tang Xuechen 
Published: June 2017

Abstract
Polymer flooding has been widely applied in China and can enhance oil recovery by more than 10%. However, there is about 50% remaining oil in reservoirs. Therefore, it is important to develop a new technology which based on the mechanism of both lowering interfacial tension to an ultra-low value (103 mN/m grade) and improving sweep efficiency of displacing fluid after polymer flooding in extremely heterogeneous reservoirs. A novel dispersed viscoelastic microsphere flooding system (DVMFS) by the combination of low elastic microspheres, surfactants and polymers is suggested. Firstly, the suspension stability of the DVMFS was studied using TSI value measured by stability analyzer. The influence of surfactant concentration, polymer concentration and reservoir temperature was conducted. Then, the ability to reduce interfacial tension was measured using interfacial tensionmeter. Furthermore, conformance control ability was evaluated by double tube parallel model. Oil displacement efficiency of the system was obtained through core flooding experiments under a given reservoir condition after polymer-flooding. The results show that the low elastic microspheres with 23.6 Pa used in this paper has great swelling capability at the reservoir condition of Gangxi Oilfield. The deformable microsphere passes throw the pore throat easily because of its low elasticity. The dispersed system has great suspension stability. The lower the temperature and the higher concentration of surfactant and polymer are, the smaller the TSI value and the better the suspension stability are. Besides, the system has an ultra-low oil-water interfacial tension. The results of double tube parallel model and oil displacement experiment indicate that the injection profile was significantly adjusted and the oil recovery efficiency was increased by 21.66% after polymer flooding. This conformance control is a dynamic one because of the combination of low elastic microsphere, surfactant and polymer, which is different from the common gel conformance control technology. The DVMFS displays a promising application to improve oil recovery after polymer flooding for extremely heterogeneous reservoirs.