bluuebunny/crossref_metadata_2025_split huggingface dataset:
Colloidal Dispersion Gels CDG in Dina Cretáceos Field: From Pilot Design to Field Implementation and Performance
Authors: Castro R. , Maya G. , Sandoval J. , Leon J. , Zapata J. , Lobo A. , Villadiego D. , Perdomo L. , Cabrera F. , Izadi M. , Romero J. , Norman C. , Manrique E. 
Published: July 2013

Abstract
Dina Cretaceous Field is located in the Upper Magdalena Valley (UMV) Basin, Colombia. Dina Field operated by ECOPETROL S.A. (discovered, 1969) started peripheral water in 1985. Based on high water cuts (96%) and recovery factors of 32%, comprehensive enhanced oil recovery (EOR), screening evaluation began late 2009, identified Colloidal Dispersion Gel (CDG) as an optimum EOR method for the field.
This paper summarizes Dina CDG project from the laboratory to the field evaluation. Laboratory studies include basic fluid/fluid evaluation, static adsorption, CDG formulations, slimtube, and coreflood tests. Pilot area selection was based on a comprehensive reservoir and injection/production data analysis, water management, well integrity, among other factors. Pilot design was based on detailed numerical simulations using sector and full field models. CDG pilot design also considered water handling limitations and potential injectivity constraints due to the narrow margin of maximum injection and reservoir pressures, combined with low reservoir permeability (50 to 200 mD).
Peripheral CDG pilot included one injector and three producers. CDG injection began in June 2011 and as of September 2012, approximately 437,000 bbl of CDG have been injected (5% of pilot PV). CDG injection strategy considered a fix polymer concentration of 400 ppm and a variable polymer/crosslinker ratio ranging from 40:1 to 80:1; to control maximum injection pressure. Field results showed an important increase in oil recoveries (oil productivity up to 300%) and reduction of water cut decrease (10%). After 16 months, no polymer had been produced in offset producers. Main operating challenges experienced during the pilot project included; the improvement in water quality and its impact on CDG injectivity which will also be described.
This study provides guidance to successfully design, implement, and evaluate CDG pilot projects and other potential chemical EOR technologies in waterflooded reservoirs. Lessons learned during pilot testing contributed to defining pilot expansion strategies supported by an integrated decision-risk management approach.
Integrated Approach in Deploying Low Salinity Waterflooding
Authors: Sorop T. G. , Suijkerbuijk B. M. , Masalmeh S. K. , Looijer M. T. , Parker A. R. , Dindoruk D. M. , Goodyear S. G. , Al-Qarshubi I. S. 
Published: July 2013

Abstract
Low Salinity Waterflooding (LSF) is an emerging IOR/EOR technology that can improve oil recovery efficiency by lowering the injection water salinity. Field scale incremental oil recoveries are estimated to be up to 6% STOIIP. Being a natural extension of conventional waterflooding (WF), LSF is easier to implement than other EOR methods. However, the processes of screening, designing and executing LSF projects require an increased operator competence and management focus compared to conventional waterflooding. This paper discusses the practical aspects of deploying LSF in fields, focusing on the maturation stages, while highlighting the key success factors.
LSF deployment starts with a portfolio screening against specific surface and subsurface screening criteria to prioritize opportunities. Next, the identified opportunities are run through reservoir conditions SCAL tests to quantify the LSF benefits, while de-risking the potential for any injectivity loss due to clay swelling or deflocculation. Standardized LSF SCAL protocols have been incorporated into the general WF guidelines, so that any suitable new WF project conducts LSF SCAL. For mature waterfloods, this SCAL program provides additional reservoir condition relative permeability data, enabling operating units to optimize well and reservoir management (WRM). The next steps in the process are production forecasting, facilities design, and project economics for the LSF opportunity. The multidisciplinary nature of LSF deployment requires integrated (sub)surface technology teams closely collaborating with R&amp;D and asset teams. The standardization of the facilities design, including cost models, can significantly accelerate the deployment effort.
In Shell, LSF is currently at different stages of deployment around the world and across the whole spectrum of WF projects, from the rejuvenation of brown fields to green field developments (offshore and onshore). The LSF deployment effort is combined with the screening of other EOR technologies, to identify where LSF may be able to unlock additional value by creating the appropriate conditions for subsequent chemical flooding.
Maturing a CO2-EOR Opportunity from Initial Screening to Field Testing - A Case Study
Authors: Samad Abdul , Al Ahmed Arwa , Al-Dayyni Taha , Kalam Zubair 
Published: July 2013

AbstractImmiscible WAG (IWAG) processes, although proven quite useful in maintaining pressure in low permeability reservoirs, has the inherent drawback of leaving high residual oil saturation (Sor) behind the flood front. Often, dependent on the reservoir characteristics, the oil volume which is left behind by a secondary IWAG process can be of significant value and requires investigating tertiary EOR processes that could economically produce it. This case study discusses the approach taken to mature an EOR opportunity in a giant onshore carbonate reservoir currently being developed with IWAG injection.A plan was put in place to assess the suitability of prospective EOR processes in the subject reservoir. This commenced with a detailed PVT lab study which involved specially designed EOR tests such as swelling, slimtube, forward contact, backward contact, equiphase and asphaltene deposition. The experimental data was used to develop an equation of state model (EOS) that is able to describe the reservoir fluid behavior. Next, analytical methods were used to screen out the EOR processes found most promising. The EOR processes were screened based on the performance indicators estimated using classical reservoir engineering techniques, empirical methods, experience and judgment. The favourable results for the CO2 injection, both from the PVT experiments and the analytical screening led to the design of 1D coreflood experiments on composite cores at full reservoir conditions.Comparison of the different displacement tests showed CO2-WAG to be highly efficient recovery mechanism with 93% of the HCPV recovery potential. The PVT experiments and the coreflood injection tests, within their experimental limitations provided recovery profiles and CO2 injection characteristics to validate model predictions on a microscopic scale, and thus enhanced confidence in full field development studies based on the underlying reservoir simulation models. The proposed CO2-EOR strategy will help reduce the Sor significantly and hence improve Ultimate Recovery (UR). A field pilot is being considered to evaluate the CO2 injection recovery process optimally.
Fitting Foam Simulation Model Parameters for SAG Foam Applications
Authors: Rossen W. R. , Boeije C. S. 
Published: July 2013

Abstract
Foam improves sweep in miscible and immiscible gas-injection EOR processes. &quot;SAG&quot; foam processes (injecting alternating slugs of surfactant solution and gas) offer many advantages over co-injection of foam for both operational and sweep-efficiency reasons.&nbsp; The success of a foam SAG process depends on foam behavior at very low injected water fraction (high foam quality), which means that fitting data to a typical scan of foam behavior as a function of foam quality can miss conditions that determine the success of a SAG process.&nbsp; The result can be inaccurate scale-up of results to field application. A successful SAG foam process depends on behavior at very low fractional flow during gas injection and on behavior at larger water fractional flow further from the well where gas and surfactant slugs mix.
We illustrate how to fit foam-model parameters to steady-state foam data for application to SAG foam processes.&nbsp; Dynamic SAG corefloods can be unreliable because of failure to reach local steady state&nbsp; (because of slow foam generation), the increased effect of dispersion at the core scale, and the capillary end effect.&nbsp; For current foam models the behavior of foam in SAG depends on the mobility of full-strength foam, the capillary pressure or water saturation at which foam collapses and the parameter governing the abruptness of this collapse.&nbsp; We illustrate how to fit these model parameters to coreflood data, and the challenges that can arise in the fitting process, using the published foam data of Persoff et al. (1991) and Ma et al. (2012). For illustration we use the foam model in the widely used STARS simulator. Having accurate water-saturation data is essential to making a reliable fit to the data.&nbsp; Model fits to a given experiment may result in inaccurate extrapolation to mobility at the wellbore and therefore predicted injectivity: for instance, a model fit in which foam does not collapse even at the extremely large capillary pressure at the wellbore.
We show how the insights of fractional-flow theory can guide the model-fitting process and give quick estimates of foam propagation rate, mobility and injectivity at the field scale.
The Use of Modeling and Monitoring to Control Scale in Alberta ASP Floods
Authors: Hunter Kate , McInnis Lee , Ellis-Toddington Tyler , Kerr Scot 
Published: July 2013

Abstract
Two commercial Alkali Surfactant Polymer (ASP) floods became operational in the Taber area of Alberta, Canada in 2006 and 2008. Both of these floods used NaOH as the Alkali. Throughout the course of both projects extreme scale deposition was observed in downhole production equipment, gathering systems, and in the production facility.&nbsp; Early in the life of the floods the scale composition was predominantly calcium carbonate, however over time the scale changed to consist of greater amounts of amorphous silicate.
Scale inhibition and remediation strategies have been developed which include a comprehensive monitoring program, chemical scale inhibition, and mechanical scale prevention techniques. As a result of the large amount of data gathered, models were created to predict scale severity, content, and develop specific mitigation plans. Although clear field wide scaling trends can be identified over the life of these projects, scale mitigation strategies still need to be customized for each well.
Although scale remains an operational challenge in these fields, with proper mitigation procedures it can be managed. This report documents the success in reducing the impact of the scale problem and slowing the depositional rate. When designing ASP floods it is important to plan for scale deposition and be proactive on scale mitigation.
The Role of Advanced Well Architecture in Cost Efficient Offshore EOR Field Redevelopment
Authors: Chan Keng Seng , Chong Danny , Masoudi Rahim , Othman Mohamad 
Published: July 2013

Abstract
Enhanced Oil Recovery (EOR) has been touted as the Holy Grail for achieving the highest possible recovery factor. This technology is fairly matured in land based development, with older fields in Bakersfield and Indonesia achieving up to 90% recovery factors. However, EOR considerations take on a whole new dimension in an offshore environment. Astronomical rig rates and escalating operational costs have deterred operators from pursuing ambitious offshore EOR programs.
Most EOR pre-development studies are focused on the reservoir; in particular altering relative permeabilities, reducing residual hydrocarbon saturations, and improving sweep efficiencies. But with up to 40% of slated huge EOR capital development cost earmarked for well construction, more technical focus should be emphasized on well architecture.
This paper details the well architecture work done on several Malaysian fields scheduled for EOR redevelopment. A workflow featuring the various design and operational considerations is explained. Well architecture is composed of two main components: Trajectory and completions functionality. Malaysia&#39;s portfolio of complex reservoirs requires EOR development to be done through a creative lens of complex trajectories and multilateral wells. Marginal economics have precluded the practicality of conventional well construction.
A key enabler in cost efficient EOR redevelopment is advanced completions, namely remote downhole flow control and monitoring. In order to achieve incremental production beyond secondary recovery, reservoir conformance is of critical importance. Remote real time monitoring will allow decisions to be made accurately in a timely manner. Downhole flow control permits purposeful manipulation of injection and production streams. Proper installations of advanced completions will also reduce future intervention and operational costs.
Advanced well architecture however, also comes with a whole range of operational and installation risks. But these can be mitigated with proper planning and coordination with all parties involved.
Managing Chemical Flooding, and By-Products with Produced Water Re-Injection (PWRI) System in Offshore Environment
Authors: Sabzabadi Ali , Amirrudin Farahnajwa , Vai Yee Hon , Juhaida M. Johar 
Published: July 2013

AbstractAngsi field is slated to be the first in the world for Alkaline-Surfactant and Polymer (ASP) chemical flooding via a floating structure in an offshore environment. The chemical flooding will be for 3 years with 6 months of low salinity water pre-flush injection prior to chemical injection to condition the reservoir, and 6 months of treated seawater with polymer injection as post-flush activity. The chemical flooding will be conducted via injection of treated and partially desalinated seawater mixed with ASP chemicals produced from the floater which is tie-in to the existing Angsi water injection pipeline network (Figure 1.0). Angsi reservoirs will experience three (3) different salinity range exposures with two (2) as invading fluids with effects of chemical cocktail, wettability and fluid distribution. One of the main challenges for ASP flooding in an offshore environment is handling the chemical residuals breakthrough in produced water causing the water unable to be disposed overboard. To overcome this problem and to eliminate environmental pollution,&nbsp; a full scale Produced Water Re-Injection (PWRI) system with full integration to existing Angsi Produced Water Treatment (PWT) system should be adopted to meet the new water reinjection specifications. Since the PWRI water will be commingled with treated and partially desalinated seawater mixed with ASP chemicals from the floater, it is paramount to predict the range of salinity of the produced water over time to help to design the PWRI and Floater&#39;s water treatment system to achieve the final water quality and optimum salinity required for an effective ASP cocktail for re-injection. This paper will summarise the PWRI design and operation philosophy coupled with subsurface studies to predict salinity profiles for the produced water.
The First Application of IWAG Surveillance Program with Integrated Operation (IO) for Dulang Field Offshore Malaysia
Authors: W. Daud W. Ata , Sedaralit M. F. , Wong Fadhli , Affendi Amierul 
Published: July 2013

AbstractWith declining oil production, the Exploration &amp; Production companies are in search of applying innovative methodologies to improve recovery factors from existing fields.&nbsp; Immiscible Water Alternating Gas (IWAG) has been identified as one of the enhanced-oil recovery techniques for offshore Dulang oil field in Malaysia. The field redevelopment FDP study was initiated in 2007 to evaluate the optimum recovery scheme to increase oil production from all reservoirs in Dulang field. Results from the simulation study indicated that the major reservoirs will benefit from IWAG injection, with ultimate recovery as high as 50% in some reservoirs. Phase 1 of IWAG injection was started in April 2012Prior to IWAG field implementation, extensive surveillance program was developed to ensure requires data is captured for monitoring the success of the project and provide a feedback for improvement.This paper explores the selection of tools and testing programs adopted in surveillance program which include Integrated Operation (IO) for IWAG injection in the Dulang field. The new proposed surveillance program is expected to improve water flood and IWAG monitoring; Monitors stable front (water or gas) with high sweep efficiency to push oil to producerMonitors and forecasts displaced reservoir hydrocarbon and water volumesEnables to see and understand the status-quo of WF/WAG performance in each block and reservoirThe new IWAG surveillance program with the IO system will enable the surveillance team to move from reactive to a proactive asset management system. Real time data will enable engineers to know the status of injection facilities, well status and rate and the performance of IWAG EOR in Dulang.
Enhancing the Efficiency of Immiscible Water Alternating Gas (WAG) Injection in a Matured, High Temperature and High CO2 Solution Gas Reservoir- A Laboratory Study
Authors: Mohd Shafian Siti Rohaida , Kamarul Bahrim Ridhwan Zhafri , Abdul Hamid Pauziyah , A Manap Arif Azhan , Darman Nasir , Sedaralit Mohd Faizal , Tewari Raj Deo 
Published: July 2013

Abstract
This paper discusses laboratory results of enhancing the performance of water alternating gas (WAG) injection process. Currently, field is under primary and secondary phases. It is light oil with moderate to good reservoir characteristics and relatively higher in reservoir temperature between 92 – 101°C and higher CO2 percentage in produced gas. Field is in decline phase and rise in water cut and GOR values. Redevelopment strategy of the field includes optimization of well spacing and WAG application to maximizing the oil recovery. One of the key challenges faced on WAG injection is gas overriding. Therefore, it becomes important to control the gas flood front during gas injection cycle of WAG and allowing the reservoir to reach to Sorg level.
The study will focus on measuring the variation of petrophysical parameters for surfactants that has bulk foam stabilization properties. In addition to classical foam Mobility Reduction Factor (MRF) determination, effect of foam on gas saturation has also been monitored along the core using in-situ X-ray monitoring tool. Propagation of foam in porous media is less understood and application of X-ray monitoring for gas saturation in dynamic condition helps to understand this to great extent.
Experiments have been carried out on Berea and reservoir cores mounted on dedicated X-Ray-equipped core flood bench. The core, initially at Swi, is flooded up to Sorw with water followed by gas injection to Sorg level to establish the reference condition for WAG. A slug of surfactant solution is then injected followed by gas prior to co-injection of surfactant and gas (83 % quality foam). Fluid propagation in core is correctly monitored for every 0.1 PV injection of fluids. The results suggest efficient mobility control by achieving required MRF in presence of ROS. High MRF is an essential ingredient for the success of the process. These results are also correlated with a homogenization of the gas front in presence of foam.
Chemical EOR Injection Facilities – From Pilot Test to Field-Wide Expansion
Authors: Chang Harry L. , Yanming Gao , Wu Fengwu , Hou Huaye 
Published: July 2013

Abstract
Chemical injection in enhanced oil recovery (EOR) projects is a complex process because it involves multiple chemicals with complex fluids. Costs for even a small-scale pilot test could be up in the millions of US dollars (USD) and large-scale field-wide expansion would be in the 100s of millions USD for onshore projects. Costs for offshore projects would increase by multiple folds compared to onshore projects with comparable sizes.
This paper discusses (1) conventional designs for small- or large-scale injection facilities, (2) recent improvements in conventional designs, and (3) new concepts in chemical injection facility designs that can improve the quality, lower the cost, and reduce the lead time in the implementation of chemical EOR (CEOR) projects.
The Effects of Suspended Solids and Fine Migration on the Design of Immiscible WAG Process in the Bokor Field
Authors: Chee S. C. , Zain Z. M. , Osman A. M. , Ohen H. A. 
Published: July 2013

Abstract
Among the different Enhanced Oil Recovery methods being implemented in the matured fields of Malaysia, Immiscible Water Alternating Gas (iWAG) appears to be the most viable option. However, reduction in well injectivity and productivity would be very harmful to this process and render it ineffective. Therefore, extensive laboratory testing, interpretation and integration have been performed to reach the conclusions and recommendations presented in this paper.
The target reservoirs in the Bokor are made up of unconsolidated and very heterogeneous rock with high permeability streaks. The mineralogy of the target reservoirs shows over 10% of clay, with abundance of kaolinites and illites which tend to cause fines migration and mixed layer illites/smectite which can swell. Therefore special handling of core samples is necessary for the laboratory testing; this includes flow through cleaning and critical point drying.
The aim of the study is to establish the potential mechanisms of formation damage during the iWAG progress and determine preventive, mitigative measures and provide guidelines for treatment if damage occurs. The main focus is on formation damage by fines migration, dirty injection fluids (Mechanically induced damage) and clay swelling and de-flocculation (Chemical induced damage – fluid rock interaction) effect to Bokor field. The laboratory tests performed includes capillary suction time, filtration level test, critical velocity and fines stabilizer test, constant rate injectivity test and formation damage by iWAG injection test.
Key areas of interesting findings include (1) Potential formation damage mechanism during the iWAG process (2) Strategies to prevent damage and improved injectivity, (3) Recommended treatment frequency based on injection half-life established in this study and (4) Field monitoring strategies.
Potential of the Trifunctional Bispecific Antibody Surek Depends on Dendritic Cells: Rationale for a New Approach of Tumor Immunotherapy
Authors: Eissler Nina , Mysliwietz Josef , Deppisch Nina , Ruf Peter , Lindhofer Horst , Mocikat Ralph 
Published: July 2013

AbstractTrifunctional bispecific antibodies (trAbs) used in tumor immunotherapy have the unique ability to recruit T cells toward antigens on the tumor cell surface and, moreover, to activate accessory cells through their immunoglobulin Fc region interacting with activating Fcγ receptors. This scenario gives rise to additional costimulatory signals required for T cell-mediated tumor cell destruction and induction of an immunologic memory. Here we show in an in vitro system that most effective trAb-dependent T-cell activation and tumor cell elimination are achieved in the presence of dendritic cells (DCs). On the basis of these findings, we devise a novel approach of cancer immunotherapy that combines the specific advantages of trAbs with those of DC-based vaccination. Simultaneous delivery of trAbs and in vitro differentiated DCs resulted in a markedly improved tumor rejection in a murine melanoma model compared with monotherapy.