bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integration of Core and Log Data for Classification of Reservoir Rock Types in Minagish Reservoir of Greater Burgan Field, Kuwait
Authors: Hayat L. , Al-Rushaid M. A. , Datta K. , Al Sabea S. H. , Muhammad Y. , Gomez E. , Clark W. , Ma Y. Z. , Bond D. J. 
Published: March 2015

Abstract
A detailed Geological and Petrophysical characterization was achieved in a stepwise approach as part of full field 3D Reservoir Modeling and Simulation study for Minagish reservoir in the Greater Burgan field in Kuwait.
Foundation of Reservoir Rock Types (RRT) was developed in first step based on Mercury Injection Capillary Pressure (MICP) dataset. A combination of Discriminant Analysis and Indexed Self Organizing Map (SOM) was used for rock type classification using hyperbolic tangent method. To improve classification of bimodal Pc curves, additional pressure values at different non-wetting phase saturations were used in conjunction with above mentioned parameters. In second step, the available Routine Core Analysis (RCA) porosity, permeability data was grouped together based on common patterns to generate rock types in RCA domain. Blind tests in two of the cored wells revealed a conformance of 81% between MICP and RCA Petrophysical Groups (PG). In the final step of the process, petrophysical groups were propagated in log domain using available log measurements common in all the wells of the field. It was challenging to establish a high level of accuracy for PG's in log domain mainly due to fine scale heterogeneity and inability of log data to capture rock fabric variation.
This porosity estimate, coupled with rock type classification, helped to derive a continuous permeability log with a correlation coefficient of 0.89 validated in key cored wells. The porosity and permeability data in all the wells was incorporated in the 3D geocellular model after up-scaling honoring the unique, per rock type, Phi-K relationship.
Modeled capillary pressure curves generated for each rock type in the core domain using MICP data set in 3 wells were used in saturation height modeling. The modeled equation was captured in the 3D geocellular model after populating rock types in the 3D grid to map water saturation for volumetric estimation.

Introduction
A 3-D static model of the Minagish Reservoir, Greater Burgan Field was constructed that integrated the available geological, geophysical, petrophysical and engineering data. This model was populated with facies, petrophysical properties (porosity, permeability and water saturation) and reservoir rock types. The paper demonstrates the significance of rock type classification within an integrated reservoir characterization study giving a narrow range of uncertainty and how it can impact prediction of reservoir flow performance.
Development of a Polymer Gel System for Improved Sweep Efficiency and Injection Profile Modification of IOR/EOR Treatments
Authors: Crespo Freddy , Reddy B. R. , Eoff Larry , Lewis Christopher , Pascarella Natalie 
Published: March 2015

Abstract
The existence of high-permeability features, such as fissures, fractures, and eroded-out zones, diminishes the sweep efficiency of any water, gas, or polymer flooding operation. Placing crosslinked conformance polymer gels or other types of blocking agents in injection and/or production wells can generate the necessary flow diversion for increasing the recovery factor of enhanced oil recovery/improved oil recovery (EOR/IOR) treatments.
This paper evaluates a high-molecular-weight (HMW) organically crosslinked polymer (OCP) (referred to as HMW-OCP) gel system for such scenarios. This conformance technology is the result of crosslinking reactions between HMW polyacrylamide and polyethylenimine (PEI). The relatively medium viscosities of the fluids caused by the HMW of the components of the system allows for in-depth gel placement in fractures and high-perm channels, without invading the matrix of the rock. A low-molecular version of this polymer system has proven to successfully control water production in matrix applications.
This HMW-OCP system gelation occurs gradually with time and temperature and can be designed to suit the need for short and long placement times. Optimization of gelation times using chemical activators and bimodal distribution of polymer molecular weights (MWs) is discussed. Fast hydration of the base polymer provides on-the-fly mixing capabilities. Also, the use of all liquid polymers and additives allows ease of transportation, handling, and storage and mixing of large volumes of material usually necessary for this type of treatment. Laboratory test results show long-term plugging capabilities, thermal stability, and fluid-loss control.

Introduction
Inadequate profile injection and sweep efficiency are key challenges when trying to achieve reasonable recovery factors with IOR/EOR treatments. Fractures, high-permeability channels, and other heterogeneities present in reservoirs are very likely to provide preferential paths of least resistance to the fluid being injected to sweep hydrocarbons causing premature injected-fluid breakthrough. A common way to mitigate this problem and to maximize the amounts of swept oil from the reservoir is to place sealants or blocking agents in such flow paths. Polymer gels and other types of conformance materials are permeability-reducing agents that can fill fractures and high-permeability channels at the injector or producing well to generate flow diversion and increase sweep efficiency.
There are several technologies that can be used to reduce injected-fluid production and increase sweep efficiency in fractured reservoirs.Crosslinked polymer gels.In situ swellable particulate polymers (or preformed gel particles).Triggered in situ activation of nano-sized gel particle emulsions.Silicate systems.
Shale-Fluid Interactions and Drilling Fluid Designs
Authors: He Wenwu , Gomez Sandra L. , Leonard Russell S. , Li David T. 
Published: March 2015

Abstract
Advanced directional drilling technology has made it possible to drill extended reach wells with long horizontal displacements, resulting in optimally placed wellbores within reservoirs and more economical hydrocarbon production. Logging-while-drilling (LWD) technologies provide new opportunities to improve reservoir characterization and geologic models however, the complicated wellbore and formation geometries in highly deviated wells impose difficulties for quantitative interpretation of well logs using conventional petrophysical analysis methods. LWD log interpretation in high-angle and horizontal wells is often limited to geosteering in well placement applications and qualitative reservoir description.
We developed a state-of-the-art formation evaluation toolkit for quantitative interpretation of well logs in high-angle and horizontal (HA/HZ) wells. Starting with wellbore images and standard triple-combo field logs, the workflow consists of: 3D and 2D displays for well path, wellbore images and field logs to quality control the data;comprehensive image and log analysis to build a 3D geometrical earth model;depth coherence analysis to effectively correct the recorded wellbore images of various logging tool sensors with different depths of investigation;3D joint inversion to accurately model and interpret gamma-ray, neutron, density and resistivity logs in order to build a common petrophysical earth model; andpopulating the common earth model with bedding geometries and rock- and fluid-property distributions.
The toolkit has been successfully applied to a field example to illustrate its applications in quantitative reservoir characterization of net-to-gross (N/G), porosity (???), and water saturation (Sw). Incorporating more accurate descriptions of bedding dips and azimuths from HA/HZ wells within the earth model results in improved geologic models for reservoir simulation. Sensitivity analysis in the workflow defines the uncertainties in wellbore image analysis and wellbore directional surveys.
Additional uplift in reservoir characterization includes quantifying lateral variations and improving reservoir facies classifications, along with delineating potential calcite zones and quantifying stratigraphic bedding and orientation. The results include bed thickness distributions and guidance to appropriate petrophysical cutoff values.
Sequence Stratigraphy Framework of late Early to Middle Cenomanian Rumaila and Late Cenomanian to earliest Turonian Mishrif Formations, Onshore Kuwait
Authors: Youssef Abulkader H. , Kadar Adi P. , Karam Khalaf A.. 
Published: March 2015

Abstract
A high resolution biostratigraphic and paleoenvironmental investigations were integrated with sedimentology and wireline-log-data to establish a sequence stratigraphic framework of Rumaila/Mishrif section, Kuwait. The biostratigraphic analysis of over 500 core/chips from 9 wells recognized six 4th order sequences over the study section. All the identified sequences correlated regionally.
Three 4th order sequences were identified within the Rumaila Formation: RU100, RU200, and RU300. The RU100-SB lies on the boundary between the non-calcareous restricted shale of the upper Ahmadi Formation and the highly fossiliferous, calcareous marine shale at base of Rumaila Formation. The RU100 and RU200 sequences are represented by marine calcareous shale or marl containing common nannofossils and marine microfossils at their MFSs. The RU300-SB lies on top of the shallower facies, poorly fossiliferous highstand of the under-laying sequence. The RU300-MFS is indicated by abundant micro/nannofossils. This marine event is equated with the regionally known K130.
The Rumaila/Mishrif contact is placed at the shift in facies from the deeper water facies of Rumaila to a shallower facies of Mishrif. The shallower facies of Mishrif is bioclastic wack/packstone enriched upward in rudistid and coralline fragments forming a fair/good quality reservoir.
Three 4th order sequences were identified within the Mishrif Formation: MISH100, MISH200 and MISH300. The MISH100-SB lies on top of recrystallized wack/mudstone and packstone ending up with a dolomitic wackstone. The MISH100-MFS is indicated by planktonic foraminifers. MISH200-SB lies on top of Praealveolinid wack/packstone of the previous sequence. MISH200-MFS is indicated by planktonic and benthonic foraminifers. The MISH300-SB lies on top of the Praealveolinid wack/packstone ending up with lagoonal non-calcareous shale. The MISH300-MFS is indicated by planktonic and benthonic foraminifers. This marine event could be equated with the regionally known K140.
The Rumaila is considered as a good seal all over Kuwait while the Mishrif is considered as a fair/good quality reservoir towards the south. Micritic matrix, moldic, vuggy and fracture porosity reservoir is represented in parts of MISH100, MISH200 and MISH300, while the rudist, coralline floatstone reservoir is existing within MISH300-HST of some areas. Geologic model is presented to show; depositional setting, paleoenvironments, basin configuration and geographic extension of different sequences.

INTRODUCTION
The focus of this study is on the Rumaila and Mishrif section which occupies the upper part of Middle Cretaceous Wasia Group, which is composed of Burgan, Mauddud, Wara, Ahmadi, Rumaila and Mishrif formations. The group was formed during the latest Aptian, Albian, Cenomanian to earliest Turonian (111 Ma - 92 Ma), and was deposited in about 19 m.y.
Waterflood Optimization and its impact using Intelligent Digital Oil Field (iDOF) Smart Workflow Processes: A Pilot Study in Sabriyah Mauddud, North Kuwait
Authors: Khan Mohd. Yunus , Chetri H. , Saputelli L. , Singh S. 
Published: March 2015

Abstract
The Sabriyah Mauddud (SAMA) limestone reservoir of North Kuwait is a large oil reservoir currently under waterflooding to meet production targets, and optimization of water injection is critical. The engineers have begun monitoring, diagnosing, and optimizing this waterflood through the implementation of an intelligent digital oil field (iDOF) program called KwIDF (Kuwait Integrated Digital Field). Various workflows have been developed for the visualization and analysis of waterflooding performance. Such workflows use real-time production data to derive and update daily water saturation and reservoir pressure from numerical simulation. The ultimate goal of this workflow is to identify and define actions to improve water injection and production over the short and medium terms. The transformation of raw data into information is achieved through intelligent, automated work processes, which are referred to in this paper as "smart workflows." These smart workflows assist engineers with daily well surveillance activities, aid productivity, and help improve the speed and quality of their decision-making process. The workflow presented is related to waterflood management; however, it is part of a family of smart workflows (e.g., electrical submersible pump [ESP], subsurface waterflood optimization [SWFO], and smart production surveillance [SPS] workflows), which have been discussed in other work. These smart workflows and a commercial software, Oil Field Manager (OFM) for Decline Curve Analysis (DCA), have also been used in waterflood optimization for the optimum production allowable selection, with the ultimate goal of improving asset performance.
This paper shares how these smart workflows are used for waterflood optimization and illustrates a case study of an injection pattern optimization and its impact on production. Comprehensive monitoring of the waterflood has been performed using real-time data through iDOF smart workflow processes, illustrating the analysis of real-time data, which includes pump intake pressure, flowline pressure, water cut (WC), and flowing bottomhole pressures. Other data used include static bottomhole pressure, production log results, and production flow tests. Monitoring is planned in such a way to understand waterflood movement within the reservoir from injector to producers and its impact on the production behavior of the surrounding producers. A positive response in terms of pressure maintenance and production increase has been observed and confirmed using various analytical tools.
Produced Water Management For Sustainable Reinjection - Bench Scale Tests To Remove And Destroy KHI
Authors: Al-Shaabi Mohammed , Emadaddhi Khalid , Roquet Damien 
Published: March 2015

Abstract
Dolphin Energy Limited's (DEL) production scheme is based on a wet transport of well effluents from offshore platforms (DOL-1 and DOL-2) to the onshore treatment plant. At the onshore receiving facilities, sour gas is routed to gas sweetening, condensate is stabilized and treated and produced sour water is routed to water treatment units.
Since the plant startup in 2006, non-chemically contaminated waste water is used for irrigation after treatment. Produced waste water and chemically contaminated waste water are re-injected into a deep reservoir without any major treatment further to H2S stripping, oil skimming, pH control and multi-media filtration. However, local authorities have expressed their concerns about the quality of water injected and the potential risk of long term injectivity loss.
Indeed, as sealines need to be protected all year round against corrosion using a Corrosion Inhibitor (CI) and hydrate formation during winter by using Kinetic Hydrate Inhibitor (KHI), produced water recovered onshore is chemically contaminated with polymer based chemicals.
As KHI could damage the reservoir, it has to be removed from produced water prior to reinjection. However, no technology was clearly available and referenced for this application. Dolphin Energy launched numerous bench scale tests with a third party laboratory to identify the best treatment scheme to remove KHI.
The paper will first explain the overall strategy put in place to identify applicable processes. Then, it will describe the laboratory tests on produced water for KHI removal and destruction. Eventually, results will be presented and compared in order to conclude with applicable treatment schemes that would remove and destroy KHI from produced water for sustainable reinjection.
Geared Centrifugal Pump (GCP) Technology Implementation in Petroleum Development Oman, as a potential Alternative Artificial Lift Method - Oil Wells
Authors: Al-Bimani A.  S. , AbdulElraouf A.  I. , Al-Salmi A. , Al-Hinai Z. , Morrow W. B. , Al-Masfry R. 
Published: March 2015

Abstract
The Company's 5-Year Business Plan shows that well operating cost (OPEX) is increasing, especially for mature fields. It is anticipated that some mature fields will not be economic to operate if these cost continue to rise. The lift and well servicing costs are key components of the well OPEX budget. Given that 90% of the company's well stock is completed with artificial lift system, new lift technologies with potential savings are needed.
The operating companies have always been looking for alternative lift method to lift high volume wells at lower cost. The Geared Centrifugal Pump (GCP) is a new high volume artificial lift system that combines the rod string drive of a progressive cavity pump with a multi-stage centrifugal pump of an ESP, via a down-hole speed increasing transmission. It is anticipated that this new system will reduce costs associated with well intervention as failures related to the drive string can be executed by smaller well service units. In addition, electrical and drivehead mechanical failures can be rectified at surface at less cost. Moreover, the GCP pump is cost effective equipment as it eliminates the expensive motor, cable and surface controller. In this notion the GCP pump will address both the lift and servicing cost challenges when compared to other lift systems.
PDO expects to complete all six pilot GCP installations in two of the north Oman fields before performance of the GCP system compared to the widely used ESPs in the same field. At the end of end-2nd qtr. 2013. The objectives of this pilot trial are to test the efficiency, reliability and operational the approx. one-year trial period, the technical and commercial values will be quantified and thus confirm the viability of deploying the lift system further.
This paper will discuss trial objectives, deployment experience, real time monitoring, troubleshooting & optimization. The paper will also highlight the technology challenges; lessons learned and improvements including future deployment plans for PDO.

Introduction
Petroleum Development Company of Oman (PDO), like most operating companies in the world, is experiencing ever-increasing producing watercuts and every increasing operating costs. Since over 90% of PDO oil wells are on artificial lift, the operating companies are constantly looking for innovative ways to improve upon the lift efficiency and maintenance costs, particularly for the high lift volume and high cost ESP equipped wells.
The geared centrifugal pump, or GCP, was seen by PDO to offer an alternative high volume lift system that had the potential of reducing well operating costs by increasing overall lift efficiency and decreasing well intervention costs.
Advanced Technologies For Produced Water Treatment And Reuse
Authors: Hussain A. , Minier-Matar J. , Janson A. , Gharfeh S. , Adham S. 
Published: March 2015

Abstract
Produced Water (PW) is the highest volume liquid waste stream generated by the petroleum industry. Historically, the treatment of PW has been limited to free oil and suspended solids removal, using physical separation technologies, and injection in disposal wells.
However, because of new regulations combined with geological restrictions and local water scarcity, the drive to have a greater fraction of the PW more extensively treated and ultimately reused is increasing. Moreover, the growth in the application of water intensive processes to extract unconventional oil&gas resources, in particular in shale plays and oil sands, has increased the need for cost-effective treatment and reuse of PW to reduce fresh water uptakes.
Therefore, the petroleum industry is investigating new PW treatment technologies given that the physical separation technologies traditionally used in the past are, in most cases, not capable of producing water of suitable quality to replace fresh water uptakes.
This paper presents the results of a laboratory investigation carried out by the ConocoPhillips Global Water Sustainability Center (GWSC), where various treatment processes (membrane processes, membrane-bioreactors (MBRs), membrane distillation (MD) and ozonation) were evaluated as treatment methods for PW from different oil&gas fields.
The key conclusions of this paper are:Membrane Processes and Thermal Evaporators are currently operating within the petroleum industry in full scale PW treatment and reuse applications.The preliminary results of investigations performed by GWSC confirmed the potential of Membrane Filtration, MBRs and Ozonation to treat PW and produce an effluent suitable for reuse. Membrane Distillation may have potential in the longer term. Further investigation is ongoing.If successfully implemented, the above technologies will contribute to provide the petroleum industry with a broad range of technologies to cost-effectively treat and reuse PW.