bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling the Effects of Salinity, Polymer Rheology, Temperature, and Reservoir Wettability on the Performance of In-Depth Gel Treatment Coupled with Surfactant and Polymer Flooding
Authors: Khamees Tariq K. , Flori Ralph E. , Alsubaih Ahmed A. , Alhuraishawy Ali K. 
Published: November 2018

Abstract
In-depth gel treatment is a chemical EOR process used to improve the sweep efficiency from heterogeneous reservoirs with crossflow. However, if these reservoirs are saturated with viscous oil, polymer and surfactant flooding should be combined with in-depth gel treatment. Thus, in this study, a 3D model using the UTGEL simulator was built to model in-depth gel treatment combined with surfactant slug and polymer solution. The model was represented by one quarter of the five-spot pattern with eight layers where two thief zones are located in the middle of the model. The thief zones had a permeability of 1500 md with a total thickness of 20 ft, while the rest of the layers had a permeability of 100 md with a total thickness of 200 ft.
The gel system consisted of a polyacrylamide/Cr(VI)/thiourea solution, which is considered an in-situ gelation system. Gelant solution was injected for 60 days when the water cut in the model reached 65%, followed by surfactant slug for 2 years, polymer solution for 3 years, and then post-water injection for the rest of the simulation time. The concentrations of the surfactant ranged from 0.01 to 0.2 wt.%, while the polymer concentration was 1,000 ppm. The injection rate was 1,070 bbl/day during all flooding and treatment processes.
The results showed that it is imperative to implement surfactant with gel treatment to reduce the interfacial tension between water and oil phases and to alter the wettability of the reservoir rocks. Thus, gel treatment alone or gel followed by polymer was not as efficient as the injection of a surfactant slug. The results also showed that as the reservoir temperature increased, the overall performance of gel, polymer, and surfactant decreased. Therefore, the higher the temperature, the lower the recovery factor. The results also revealed the importance of viscoelastic behavior of the HPAM polymer solution where higher results for both water-wet and oil-wet conditions were obtained compared to shear-thinning behavior only. Moreover, the results revealed interesting behavior regarding the concentration of the surfactant, where the recovery factor increased as the concentration of the surfactant increased in oil-wet conditions. However, in water-wet conditions, the results were unpromising and unfavorable. Furthermore, the injection of surfactant directly after the gel treatment was more effective in improving the sweep efficiency than the injection of polymer directly after the gel treatment. Finally, as the salinity of makeup water and/or reservoir brine increased, the recovery factor decreased for both water and oil-wet systems. This is because, as salinity increased, the adsorption of both polymer and surfactant increased and the polymer viscosity decreased. Furthermore, the presence of divalent cations such as Ca+2 and Mg+2, would have a negative impact on overall treatment.
Automated Multidisciplinary Collaboration in Integrated Reservoir Management IRM through Business Process Management BPM
Authors: Marzouqi Mohamed Al , Saputelli Luigi , Abdou Medhat , Mohan Richard , Pandian Senthil Murugan , Hammadi Maryam Al , Khan Muhammad Navaid , Cumming John , Pires Joshua , Escorcia Alvaro 
Published: November 2018

Abstract
The objective of this work is to enable the collaboration of multiple disciplines in the performance reviews of reservoirs while establishing a culture of variance reduction and sustainable consistency in results delivery. This effort focuses on the performance management reviews of very large carbonate reservoirs where the number of wells and producing zones overwhelm engineers and organizations with data volume and complexity due to areal and vertical heterogeneity.
A novel Reservoir Performance Review (RPR) solution has been implemented across various offshore reservoirs units. RPR initiates all asset activities during reservoir performance reviews and allows the tracking of actions over the life of the reservoir.
RPR leverages data analytics to automatically compute reservoir health key performance indicators that allow prioritization of the technical work, extract and transform data from multiple data sources, deliver performance dashboards with diagnostic plot standardized across all assets and users providing an archive of information and knowledge from past reservoir performance reviews.
RPR leverages business process management and integrated visualization to assist in the identification and recording of opportunities, risks and actions, while providing control and management of the business processes.
The solution offers an innovative way to collaboratively gather, validate, analyze reservoir performance across the asset on a sustainable and cost-efficient manner while addressing more formal approval processes in order to garner approval or authorization for action. Some of the realized benefits include ensuring effectiveness in the execution of reservoir management, monitor variance between actual performance and expectation during the execution of projects; and ensure production sustainability and mitigate shortfalls proactively. RPR enabled the achievement of a consistent approach across all assets for all reservoir performance review processes, while improving efficiency through automation of data gathering and presentation and the identification of all underperforming reservoir, sectors and fields.
Reservoir management excellence is achieved by delivering immediate value on the opportunities identified during performance reviews which ensure short term profitability while preserving long term goals. Typically, operators are satisfied by meeting targets within certain tolerance. RPR ensures that performance excellence is achieved by considering all technical and business aspects.
Integration of P-P,P-S, and Diffraction Imaging Brings Geophysics, Geology and Engineering Together-A Case Study of the KOC Sabriyah Field
Authors: Al-Saeed Hanan , Duncan S. Bruce , Al-Kanderi Jassim , Negut Dan , Martin Cathy , Nowry Wayne 
Published: November 2018

Abstract
The Kuwait Oil Company's (KOC) Sabriyah field, located in North Kuwait, produces oil and condensate from the Jurassic Najmah formation in a structurally complex setting. In 2017, Kuwait Oil Company reprocessed their 50 square km, three-component 3D seismic survey originally shot in 2010, to include shear wave splitting analysis and diffraction imaging. This project was undertaken not only to seismically image the structures better but to also better define faults and fractures and their positioning in the Najmah.Also in order to determine maxium and minimum stress directions and correlate with the known geological areas of maximum stress from previous core work. This work will help the Engineers to determine best orientation directions for drilling programs to add value.
One of the purposes of this project was to help answer the disconnect between the actual well logs,geology and the conventional seismic interpretation when tied to the well on crestal part of the anticline. The other main purpose was to see if we could help engineers place vertical and horizontal wells in optimal positions through the use of P-P,P-S, and diffraction imaging geophysical methods we were able to come up with a comprehensive look at the fractures and faulting of the Najmah as well as match with current drilling results.
First-Ever Large Diameter Fully Captured & Retained Pressurized Core and In-situ Analysis with Slow Depressurization - Pilot Case on Giant Burgan Reservoir, Kuwait
Authors: Mukherjee Pritish , Peres Jose , Hayat Laila , Anders Dr Erik , Al-Rashaid Mona , Wunsch David , Rothenwaender Tobias , Al-Kandari Jassim 
Published: November 2018

Abstract
Typically, conventional cores provide indeterminate reservoir condition; suffer loss of unknown volume of hydrocarbon fluid and mechanical integrity while being retrieved. Most laboratory analysis thereafter are simulated however it's not truly turning back the lost conditions into in-situ condition. A fully captured, and pressure retained core is thought to be a solution to provide a true micro-reservoir at surface which explains the reservoir behaviour as it behaves in subsurface. This led to successfully deploying the technology to fully capture a large diameter pressured core for the first time in conventional hydrocarbon industry in Giant Burgan Field in southeast of Kuwait in a Middle Cretaceous Clastic reservoir and also to derive a number of critical parameters from the retrieved micro-reservoir. The technology involves lowering of a large diameter pressure corer (LPC) with an outer pressure vessel and inner core barrel. After the core is cut, a drop ball mechanism sets the inward movement of the inner barrel past a spring activated pressure seal thereby keeping the core in reservoir condition. While continuous pressure recording on the retrieved core, a core analyser (PCAL) system captures multiple sets of reservoir data through a predetermined slow depressurization without hampering any operations on the rig floor. Other than measuring accurate reservoir pressure, the analytical process provided for sampling of released gases, fluids and PVT samples in addition to in-situ bubble point estimation, all at the rig site. The onsite gas analysis with compositional changes during depressurization and bubble point estimation well matched with the subsequent analysis performed on the samples in laboratory. Thus, a real representative Upper Burgan reservoir sand was retrieved containing present reservoir pressure with all fluids retained. Additionally, it provided a nearly undisturbed core with high degree of original mechanical integrity. The final depressurized core is then sent for further laboratory investigations and geological studies including slabbing and plugging. This encapsulated "micro-reservoir" is less sensitive to unexpected events like delays during retrieval and analysis, avoiding damages of the core or loss of fluids. The technology stands out against systems delivering cores at partial or no pressure retention, as it retrieves cores at formation pressure with all fluids retained and core integrity unaltered.
Offshore Electrification from Onshore through Submarine High Voltage AC Cables
Authors: Renaudin Fabien , Toulotte Maxime , Cebeci Ipek , Manna Malay , Shabaka Ashraf , Kotrappa Murugendrappa N. , Sundaresan Hemachandran 
Published: November 2018

Abstract
The objective of the proposed paper is to present the successful electrification of a newly built offshore super complex from shore as well as the shift of power production from offshore to onshore generation of an existing offshore super complex using high voltage alternative current (HVAC) submarine power cables. Both offshore super complexes are electrified from an island and are connected together to create a redundancy in the power supply between them.
The design, qualification, manufacturing, testing, and installation of the HVAC submarine cable system including fiber optical elements and accessories are described in this publication.
The HVAC submarine power cable system for the oil field development is composed of three 132 kV insulated cables which connect the offshore super complexes and the island with length ranging between 30 to 80 km. It also includes HVAC underground power cable to connect the HVAC submarine power cable to the power generation installation as well as approximately 60 km of medium voltage alternative current submarine power cable which are used to power other offshore equipment from the new offshore super complex.
The HVAC cables were designed to fulfill the load demand of both offshore super complexes considering redundancy in the HVAC power system as well as challenging installation conditions at the landing at the island. The technology used for the cable is the well-proven cross-linked polyethylene (XLPE) insulation technology.
The HVAC cables were successfully qualified and type-tested according to the requirements of IEC international standards and CIGRE recommendations.
Each three-phase cable was manufactured and tested within the manufacturing facility in Norway in one complete length insuring that a high-quality product was supplied. It also permitted to install each cable in one laying operation without having to introduce offshore field joints in the cable system.
This publication shows that electrifying offshore assets from an onshore power source using submarine power cables is a viable solution.
Forecasting Unconventional Volatile Oil Reservoirs Using Compositional Reservoir Simulation and Hybrid Decline Curve Models
Authors: Xavier John , Khanal Aadi , Lee John 
Published: November 2018

Summary
Despite emerging technology in the areas of unconventional forecasting, recovery factors are merely a fraction of its conventional counterparts. Unconventional reservoirs are characterized by their ultra-low permeability. It is to be noted that traditional decline curve analysis (DCA) is not best suited to forecast unconventional reservoirs. This is due, in part to a variety of reasons the most important being lengthy transition zones from transient flow to boundary-dominated flow which is highlighted in this paper via the usage of diagnostic plots.
The objective of this paper is to compare the production performance of volatile oil reservoirs, generated from a commercial compositional simulator, by using simple decline models used in the industry. Fluids with different initial gas to oil ratio (GOR), due to different fluid composition, was simulated for a period of 30 years. Oil rate was forecasted by assuming different lengths of available production history. We present the application of diagnostic plots to identify different flow regime. The results from our study showed that the duration of linear flow period and the transition from linear to boundary dominated flow varies drastically based on the initial fluid composition. With respect to the decline curve analysis performed, a hybrid decline curve model was used to model different sections of the production profile. Since we are analyzing volatile oil reservoirs, the biggest challenge in performing traditional DCA is the effect of multi-phase flow behavior. So, use of hybrid decline model results in a better production forecasting compared to a single decline curve.
With the advent of the shale boom, many oil and gas producers struggle to forecast unconventional reservoirs effectively. We believe that this paper serves to further elucidate the theory and application behind the concept of unconventional forecasting.
De-Risking Multi-Well ASP EOR Pilot in a Challenging Clastic Reservoir in Kuwait Following Successful Implementation of a One-Spot EOR Pilot
Authors: Al-Murayri Mohammed T. , Kamal Dawoud S. , Al-Mayyan Haya , Shahin Gordon T. , Shukla Shunahshep R. , Ten Berge Anke B.G.M. 
Published: November 2018

Abstract
Following encouraging results from laboratory experiments, simulation studies and a one-spot EOR pilot for the Raudhatain Zubair (RAZU) reservoir in Kuwait, a multi-well pilot is planned in the near future. A combination of high temperature (90°C), in-situ brine salinity (&gt;250,000 ppm) and divalent ion concentration (&gt;20,000 ppm) make implementation of Alkaline Surfactant Polymer (ASP) flooding in RAZU quite challenging. The presence of a ‘Tar Mat’ interval in the pilot area further complicates pilot design. This paper outlines some of the risk mitigation measures for a successful ASP pilot.
Laboratory experiments were performed to evaluate different polymers for improved thermal stability and to obviate the risk of polymer precipitation at the producers. Based on long-term thermal stability studies and producer scaling considerations, HPAM/ATBS based polymer was chosen over HPAM -based polymer. The original formulation which was used in the one-spot EOR pilot required 3.5% co-solvent to overcome surfactant separation at optimal salinity. Several alternative alcohols were tested and finally an appropriate co-solvent that gave adequate performance at 1.5 wt% was selected to reduce cost and logistical requirements. Additionally, optimization experiments were conducted to de-risk emulsification potential of produced oil by reducing the concentration of the injected surfactants. Finally, experiments were carried out to characterize the nature of the hydrocarbon and rock in the ‘Tar Mat’ interval to evaluate the risk versus reward of perforating it in the pilot area.
This is the first time, to our knowledge, that ASP injection is being considered in a reservoir in such a harsh environment due to combination of high temperature, salinity and divalent ion concentration in formation brine. The presence of a ‘Tar Mat’ interval further complicates pilot design. The successful execution of this pilot will push the envelope of ASP deployment in other challenging reservoirs worldwide.
Integrated Geo-Modeling and Ensemble History Matching of Complex Fractured Carbonate and Deep Offshore Turbidite Fields, Generation of Several Geologically Coherent Solutions Using Ensemble Methods
Authors: Abadpour Anahita , Adejare Moyosore , Chugunova Tatiana , Mathieu Helene , Haller Norman 
Published: November 2018

Abstract
History matching reservoir models has always been tedious as it involves many uncertain parameters and requires many trial and error iterations. Frequently the modifications introduced seem artificial and may destroy geological concepts, only one matched model is obtained and the forecast of such a model may quickly be invalidated by new data. Eventually imperfect models lead to imperfect decisions.
Assisted History matching with ensemble methods has received a lot of attention in the past decade. In this methodology with an ensemble of models the correlation between all uncertain model parameters and the selected production data is assessed and using this correlation the ensemble of the models are modified to reduce the difference between simulated and real historical data in an iterative manner.
Ensemble methods are recognized to perfectly perform on the continuous Gaussian parameters, but their application on discrete geological parameters like facies and rock types has been a challenge for several years. Different solutions proposed to tackle this issue showed the importance of integrated workflows and the implementation of an assisted history matching loop in close relationship with the geo-modeling tools.
After several years of research, an assisted history matching tool based on ensemble method has been developed in Total via the integrated platform of geo-modelling Sismage-CIG. This tool has been industrialized early 2016 with the first operational study performed on a giant gas field in the Middle-East.
Ensemble methods are known to be relatively insensitive to the size of the model, number of uncertain parameters to be handled, number of wells and the length of historical data, but the industrialization of the tool to operate on huge complex fields with very large number of the wells needed several rounds of code optimization using state of art algorithmic approaches.
This tool showed outstanding performance on several types of models such as turbiditic deep-offshore and complex fractured carbonate fields. The latest history matching study performed with this method on a Middle-East field modeled with a grid containing 20 million cells, around 200 wells and more than 25 years of production history, involved more than 130 million uncertain parameters in each realization.
The use of assisted history matching with ensemble methods allows not only to take into account cell by cell heterogeneities as uncertainty in a coherent manner but it also delivers an ensemble of hundred matched models which creates a huge opportunity for forecast and decision making process. Moreover all models fully respect the geological a priori knowledge and the duration of history matching study has been drastically reduced (weeks instead of months if not years) using much less manpower.
Managing Human Barriers through Operating Integrity Management
Authors: Balakrishnan Hemant Kumar 
Published: November 2018

Abstract
ADNOC Gas Processing, one of the world’s largest gas processing companies, operates 5 large sites (includes 26 processing trains and an NGL distillation complex at Ruwais) and manages 3000+ kilometre pipeline distribution network which has a capacity of 8 billion standard cubic feet of gas per day. Both the country’s electricity and water supplies are dependent on ADNOC Gas Processing’s continuous operation and the safety of people working on or near their assets is dependent on their safe operation.
The ADNOC Health Safety and Environment (HSE) Code of Practice (COP) requires that ADNOC Gas Processing implements a systematic approach to HSE which is consistent with the ADNOC HSE Management System. Therefore the ADNOC Gas Processing HSE Management Manual (HSEMM) serves as the ADNOC Gas Processing HSE Management System (HSEMS) and describes expectations in line with the ADNOC COP and provides an overview of how these expectations are met.
In addition to ADNOC CoP Requirements, Process Safety Expectations from ADNOC Gas Processing’s Process Safety Management Standard are included in the ADNOC Gas Processing HSE Management Manual (HSEMM).
Advanced ERD Lower Completions: Delivering Accelerated Production and Enhanced Performance
Authors: Clews Matthew , Beaman Daniel , Newton Daniel , Kofoed Curtis 
Published: November 2018

Abstract
This Extended Reach Drilling (ERD) field re-development predominantly from four artificial islands of a giant offshore field in the United Arab Emirates (UAE) requires in most cases extremely long laterals in order to reach the defined reservoir targets, by the field development team.
The giant offshore field can be effectively split in to two (2) geographical sections; East and West. The East portion of the field has been developed extensively and is considered to have good reservoir properties. The West portion of the field has much lower quality reservoir properties and requires an engineered lower completion liner in order to deliver the required well performance that will adequately produce and sweep the reservoir. The engineered liner along with the extremely long laterals means significant time is spent switching the well from reservoir drilling fluid (RDF) non-aqueous fluid (NAF) to an aqueous completion brine.
In order to reduce the amount of rig time spent on the displacement portion of the completion phase, technologies have been developed to provide a method of switching the well from RDF NAF drilling fluid to an aqueous completion brine, without the associated rig time of the current displacement method. This technique eliminates the use of a dedicated inner displacement string and allows for the displacement to be performed with the liner running string, saving on average five (5) days per well.
In this paper the authors will demonstrate the technology and system developed to perform this operation, as well as the qualification, testing, field installations and lessons learned that were required to take this solution from concept to successful performance improvement initiative.