bluuebunny/crossref_metadata_2025_split huggingface dataset:
Phased Redevelopment of a Giant Mature Offshore Field Using Maximum Reservoir Contact MRC Wells
Authors: Koeck Charles-Henri , Bensadok AbdelAziz , Goyal Praffula , Alhashmi Ali 
Published: September 2019

Abstract
A giant brownfield re-development project with long horizontal wells was initiated to arrest production decline mainly caused by a lack of pressure support and free gas influx from the large gas cap.
Key value drivers for the project are developing an understanding of the layers with regards to gas breakthrough, and achieving capital efficiency through low-cost well delivery, better planning and technology applications.
Firstly, the field has been segmented based on the analysis of multiple factors influencing the free gas production. It considers geological aspects such as the study of depositional environment and diagenesis, structural elements such as high permeability streaks and fractures, dynamic behaviors such as the water injection efficiency, gas cap expansion or coning.
Secondly, numerical simulations were then run in order to rank the sectors based on the expected model performance, compare them with real data categorization, and test the effect of the new proposed development schemes such as water injection at gas-oil contact and long horizontal wells equipped with downhole control valves.
It was found that each sector has a specific production mechanism and appropriate developments were recommended and then tested in the simulation. For instance, high permeability streaks play a significant role on the development of some sectors instigating a big difference of maturity between sub-layers, early water or gas breakthrough. Also, the inefficiency of water injection is one of the biggest issues of the field. Most of the water injectors are located too far from the oil producers, and have a low injectivity due to the often degraded facies in the aquifer because of diagenesis. This leads to a lack of pressure support that is counterbalanced by the gas injection, ending up with a lot of high GOR wells and a bad sweep from the top of the structure as the gas tends to by-pass the oil.
Simulation work showed that several remaining zones are safe for immediate development and should be prioritized for development in the near future. On the other hand, some of the mature layers prone to gas and water breakthrough need a boost for development, such as water injection at gas-oil-contact, artificial lift, low pressure system, GOR relaxation. Tight and undeveloped reservoirs are improved by implementing long horizontal drains.
Using Flow Diagnostics to Quantify the Impact of Reservoir Rock Typing on Fluid Flow in Complex Carbonate Reservoirs
Authors: Alhashmi Fahed , Geiger Sebastian , Albreiki Mohamed 
Published: September 2019

Abstract
A particular challenge inherent to carbonate reservoirs is reservoir rock typing which impacts model initialisation and saturation distributions and hence STOIIP, phase mobilities, and flow behaviours. We explore how flow diagnostics can be used best to detect subtle differences in reservoir dynamics arising from different model initialisations by comparing flow diagnostics simulations with full-physics simulations.
Flow diagnostics are applied to two reservoirs, a synthetic but realistic model representing an analogue for the Arab-D formation and a giant carbonate reservoir from the Middle East. Saturation modelling and reservoir rock typing is based on uniform and heterogeneous Pc and kr distributions, and further employs a state-of-the-art software that integrates of SCAL data and log-derived saturations. Sweep efficiency and dynamic Lorenz coefficients are then derived from the flow diagnostics results to quantify and compare the dynamic behaviour of the reservoir models. The full-physics simulations, which are used to validate the flow diagnostics results, are carried out with a commercial Black Oil simulator.
The flow diagnostics results can clearly distinguish between different homogenous and heterogeneous rock-type distributions, wettability trends, as well as novel saturation modelling approaches that use dedicated software tools. Flow diagnostics capture the same trends in recovery predictions as the full-physics simulations. Importantly though, the total CPU time for a single flow diagnostics calculation including model loading is on the order of seconds, compared to minutes and hours for a single full-physics simulation. These observation give confidence that flow diagnostics can be used effectively to compare and contrast the impact of reservoir rock typing, saturation modelling, and model initialisation on reservoir performance before running full-physics simulations. Flow diagnostic hence allow us to reduce the number of reservoir models from a model ensemble and select a small number of diverse yet realistic reservoir models that capture the full range of geological uncertainties which are then subjected to more detailed reservoir simulation studies.
Flow diagnostics are particularly well suited for complex carbonate reservoirs which are geologically more complex than clastic reservoirs and often exhibit significant uncertainties. Giant carbonate reservoirs are also challenging to simulate using full-physics simulators due to their size, so the impact of geological uncertainty on the predicted reservoir performance is often underexplored. Flow diagnostics are hence an effective complement to quantify uncertainty in state-of-the-art reservoir modelling, history matching and optimisation workflows, particularly for giant carbonate reservoirs.
Rejuvenating a Depleted Reservoir by Capitalizing Existing Facilities for Secondary Recovery in a Brownfield: A Case Study in Offshore Field
Authors: Usop Mohammad Zulfiqar , Suggust Alister Albert , Mohammad Razali Abdullah , Zamzuri Dzulfahmi , M. Khalil M. Idraki , Hatta M. Zulqarnain , Khalid Aizuddin , Hasan Azhari Muhammad , Jamel Delwistiel , Ting Yeong Ye Diana , Abdulhadi Muhammad , Awang Pon M Zaim 
Published: September 2019

Abstract
Reservoir G-4, a depleted reservoir in field B had been producing from 1992 to 2015 with a recovery factor of 30% before the production was stopped due to low reservoir pressure. Due to the huge inplace volume. A secondary recovery screening was conducted and gas injection was identified as the most suitable solution to revive G-4 reservoir due to its low cost impact of 0.4 Mil. USD whilst managing to deliver the same results as other solutions (i.e. Water injection & Water Dumpflood).
The project had utilized existing facilities in field B including a gas compressor. The project required only minor surface modification to re-route gas into the tubing of injection well BG-03. From simulation results, a continuous injection of 5 MMscf/d will increase the reservoir pressure by 150 psia in 9 months, with incremental potential reserves of atleast 5.0 MMstb from the benefitter wells, BG-02 & as well as incoming infill wells BG-14 & BG-15. It is also envisaged that with future development of additional infill wells, the recovery factor will be increased up to 60%.
In term of gas management, field B is able to deliver additional 15 MMscf/d post petroleum operation reduction (i.e. Fuel Gas, Instrument Gas & Gas lift). With the initiation of gas injection, the project had managed to utilize and optimize 33% of additional gas production for reservoir rejuvenation purposes.
The paper provides valuable insight into the case study and lesson learned of maximizing oil recovery through gas injection with minimal cost incurred. The approach is highly recommended to maximize oil recovery especially in mature fields with similar reservoir conditions and production facilities.
A New Method to Accurately Model Hydrocarbon Saturation in a Reservoir
Authors: Saini Prem Dayal , Van Der Steen Erik H. , De Jong Sander , Van Den Berg Francien 
Published: September 2019

Abstract
Hydrocarbon in place volumes are often inaccurate as a result of poor representation of the reservoir structure (by means of a 3D grid), that in combination with the use of traditional saturation calculation methods, lead to erroneous hydrocarbon volumes and poor investment decisions.
Traditionally a reservoir model is represented with a 3D grid, in a complex setting such as fault intersections and stacked reservoirs. A corner point grid is often used, which has limitations to represent this complexity. Further, the hydrocarbon saturations are then derived on a cell by cell basis on that 3D grid using simple averaging techniques of saturation height functions. The poor structure representation on the pillar grid in addition to the simplistic averaging methods lead to inaccuracies of the in place volumes especially where a prominent transition zone is present.
This paper presents new advanced saturation averaging methods (volume and height weighted) using saturation height functions on 3D grids. The new advanced saturation averaging methods are used on different reservoir models to compare the saturation distribution and volumetric differences against the traditional saturation calculation methods. A 4-way dip closure reservoir model with a tilted free water level (typical example of a carbonate reservoir in the Middle East), and a faulted S-grid model of the F3-FA field (North Sea) are used.
For the 4-way dip closure reservoir model, when comparing the advanced ‘volume weighted’ and traditional ‘by center of the part of the cell’ saturation averaging methods, a significant difference in the water saturations is observed which leads to about 5% difference in the calculation of in place hydrocarbon volumes. Further, it is observed that changing the thickness and orientation of the 3D grid cells can result in even larger differences of 5-10%.
The faulted F3 model shows that the difference between the hydrocarbon saturation values is largest where it matters most, that is, around the fluid contacts and in the transition zone. The new advanced saturation averaging methods give accurate hydrocarbon saturations irrespective of the size or complexity of the 3D grid and without any discretization effects.
Optimization of Oil Production in an Oil Rim Reservoir Using Numerical Simulation with Focus on IOR/EOR Application
Authors: Jaoua Maroua , Rafiee Mohsen 
Published: September 2019

Abstract
Development of oil rim reservoirs is challenging and could lead to low oil recovery, if multiple determining factors are not well understood, that influences successful field development concept. It requires detailed analysis and development of specific procedures to optimize the oil production from a thin oil rim underlaying gas cap. Few IOR/EOR applications for oil rim development have been reported in the literature so far. This study presents a concept for the optimization of oil production from an oil rim reservoir by numerical simulation.
As a starting point, a representative sector of the field was selected for the initial analysis. It was decided to perform IOR/EOR methods including water/gas flooding/injection and surfactant flooding using inverted five-spot horizontal well pattern, for the application in the selected sector. Upon execution of the detailed sensitivity analysis, the pattern was optimized by its characteristic geometric variables including the length of the vertical/horizontal section of the well, the location of the wells, lateral well distances and the orientation of the pattern. The optimization was performed by setting an objective function to improve recovery factor and reduce water/gas cut by using the differential evolution algorithm. The latter was run until converging, and the optimal solution was used to perform further IOR/EOR studies.
Finally, after selection of a base-case scenario and best well pattern, IOR/EOR options were evaluated, and the comparative results were reported. The generated results show that the application of 5-spot horizontal well pattern in the oil rim reservoir could increase the oil recovery by water flooding, but with low sweep efficiency. The losses of injected water into the underlaying aquifer and up laying gas gap are large. Immiscible gas injection into the gas cap can support the pressure but massively increases the gas cut. In addition, displacement efficiency by gas flooding is poor.
Simulation results of the surfactant flooding case shows better displacement efficiency compared to water flooding. Also, the possibility of reducing residual oil saturation could increase the ultimate oil recovery but at very late time.
Fully Implicit Reservoir Simulation Using Mimetic Finite Difference Method in Fractured Carbonate Reservoirs
Authors: Zhang Na , Abushaikha Ahmad Sami 
Published: September 2019

Abstract
A fully-implict mimetic finite difference method (MFD) for fractured carbonatereservoir simulation is presented. MFD, as a novel discritization, has been applied to many fields due to its local conservativeness and applicability of any shape of polygon. Here we extend it to fractured reservoirs. Our scheme is based on MFD method and discrete fracture model (DFM). This scheme supports general polyhedral meshes, which gives an advantage for reservoir simulation application. The principle of the MFD method and the corresponding numerical formula for discrete fracture model are described in details. In order to assure flux conservation, fully implicit method is employed. We test our method through some examples to show the accuracy and robustness.
A Modified Well Index To Account For Shear-Thinning Behaviour In Foam EOR Simulation
Authors: Soulat A. , Douarche F. , Flauraud E. 
Published: September 2019

Abstract
An accurate evaluation of injectivity is essential to the economics of any chemical EOR process. Most commercial simulators enable non-Newtonian behaviour modelling but it is often overlooked due to inadequate grid resolution. Indeed, in cases where shearthinning fluids are injected in a reservoir, shear rates and viscosities in the vicinity of the wellbore can be poorly estimated if the spatial resolution of the well grid-blocks is too coarse. This results in biases in injectivity and economics which we discuss here in the context of foam-based displacements.
We consider continuous foam injection in models of different spatial resolutions ranging from 1 to 100 m gridblock sizes and study the behaviour of injection wells obtained on the coarser grids compared with the results from a high resolution grid. This reference grid is sufficiently refined to account for near-wellbore large velocity gradients and render injectivity accurately. In this work we propose new formulations of the well index that capture shear-thinning behaviour that the conventional Peaceman calculation fails to address.
We first demonstrate that a poor evaluation of near-wellbore velocity leads to erroneously degraded injectivity on the coarser grids when compared to the reference grid. In order to correct these errors our modified well index is applied and validated in various scenarios of foam displacement simulation with radial grids. It captures a more accurate injectivity than the conventional Peaceman calculation once steady-state regime is reached. The modified well index we propose, used under a simplified form as direct input in reservoir simulation, significantly enhances injectivity estimates without resorting to grid refinements or modifying the shear-thinning model of the injected foam. In most cases it yields results that are closer to those obtained using grid refinements than the Peaceman formula at a much more attractive computational cost. Additional work remains to complete our understanding of injectivity in more complex settings, especially in the context of foam injection when effects such as foam dry-out and destruction in the presence of oil are as important on sweep efficiency as its shear-thinning behaviour.
Our workflow successfully corrects biases in the estimation of injectivity and yields more accurate results and avoids resorting to time-consuming methods such as grid refinements and physical input data alteration. Moreover it is simple to implement in most commercial simulators and does not require using empirical criteria. However, it bears some limitations which we also discuss.
Increased Production by Leveraging a Multidiscipline Approach for Fracturing a Complex Carbonate Reservoir
Authors: Bagir Muhammad , Andhika Banu , Zhia Ming Wu Ivan , Wijaya Rio , Lail Nasution Sakti , Chung Yee Lee 
Published: September 2019

Abstract
Numerous carbonate reservoir discoveries were made in Indonesia (Soeparjadi et al. 1975), including the Berai Formation, which consists of high heterogeneity and low porosity characteristics. To optimize production on a field-scale basis, developing an effective stimulation program is necessary to maximize the asset’s output. This integrated study demonstrates the multidiscipline approach of well stimulation and reservoir characterization for designing successful acid-fracturing stages. Understanding reservoir characteristics helps during selection of the effective fracturing design and staging plan for application.
The process involves multiple cycles—from formation evaluation (e.g., geomechanics analysis, design of an effective fracturing method, and production forecasting) through the economic impact to the operator. During the early phase of this integrated study, the uncertainties of all static and dynamic parameters (i.e., geological complexity, rock physics, and stress profile) were considered for fracturing design. Production performances from multiple fracturing stimulation scenarios were then modeled and compared to select the plan that optimizes production for the Berai Formation.
Results demonstrated an effective multidiscipline approach toward a comprehensive strategy to meet the ultimate objective in optimizing production. This project leveraged formation evaluation and fracturing design to deliver integrated solutions from exploration to accurate production forecast. The well stimulations were performed by carefully selecting fluid characteristics based on geological-petrophysical properties, pressure, and stress profiles within the area. Results yielded excellent production gains—for the best case, up to 50% with an average of 40% in comparison with initial production by using an acid that provides optimum fracture geometry and permeability.
This opportunity demonstrated the importance of understanding formation behavior and the parameters that aid the selection of an appropriate fracturing design for a low porosity/permeability carbonate reservoir.
Regional Reservoir Fluid Analysis and Interpretation based on the Integration of Petroleum Systems, Organic Geochemistry and PVT
Authors: Diatto Paolo , Cerioli Regondi Anita , Doering Sascha , Italiano Domenico , Maffeis Ivan , Marchesini Marco , Martin Marco 
Published: September 2019

Abstract
With the aim of improving the understanding of production behaviour in a multi-discovery asset and the evaluation of near-field exploration opportunities, an integrated study has been carried out involving three different disciplines: Fluid Thermodynamics (PVT), Organic Geochemistry and Petroleum Systems Modelling (PSM). The synergistic workflow has been undertaken starting from an accurate quality check of the initial dataset related to fluid samples and lab tests. By merging PVT and geochemical data, it was possible to carry out a robust statistical survey and explore correlations across different parameters and features; in this way, strict connection among many physical parameters and some oil maturity and biodegradation indices were identified. In the following step, after geo-referencing the fluid samples in the framework of the Petroleum Systems Model and tracking the locations of the source rocks, a reliable interpretation of the oil expulsion and migration history became possible over the whole reservoir fluid system. Finally, taking into account the simulated fluid phase envelopes, further insights were drawn in terms of the fluid phase behavior in different areas, contributing to reduce uncertainty and exploration risk for future activity in nearby prospects.
From Concept to Execution: A Successful Integrated Exploitation Philosophy
Authors: Mendoza Maria , Cevallos Gonzalo , Molina Edison , Piñeiros Silvia , Torres Water , Garrido Johnny , Gutierrez Ruben , Fonseca Claudio , Cortez Oscar , Fernandez Edgar , Paladines Agustin 
Published: September 2019

Abstract
An Ecuadorian lease ("Bloque 61") composed of 14 oil fields represents the most productive asset in the country. It contains 5.3 billion barrels of original oil in place (OOIP) distributed in four complex producing reservoirs. After 44 years of production and with a decline rate of 31% per year, maintaining the production from these fields represents an important challenge from the subsurface and execution viewpoints. In December 2015, an integrated service contract was signed with the national oil company (NOC) with a fixed investment for the development of the entire lease.
The challenge of the project was to maximize the value of a depleted asset through the framework of the contract. This mature asset has many opportunities to boost production and reserves by implementing an aggressive fit-for purpose development. The opportunities screened and implemented in only 12 months consisted of reaching new oil in appraisal and exploration areas and redevelopment of mature zones with horizontal and infill drilling with mainly reentry wells. Most valuable of all was the implementation of six waterflooding projects. All of these were executed in the Amazon rainforest where there is a pressing need to reduce environmental and social impact.
This exploitation philosophy has successfully changed the asset’s production decline, ramping production up from 60,000 BOPD to 80,000 BOPD. This integrated field development plan has amalgamated several technologies with a specific objective of optimizing the value of the asset. The long term was assessed through the drilling of exploration and appraisal opportunities where prospective resources were recategorized to reserves. The medium term was tackled by drilling horizontal wells and re-entries to optimize sweep efficiency and implementing water injection in the main structures. The short term was directed by executing workovers in areas where the water injection was in place. The asset value was recovered and increased as shown by a reserve’s replacement ratio of 1.13.
This approach will serve as a framework for the future integrated development of these types of mature assets. The technologies implemented have helped accelerating and optimizing the conceptualization and execution of the project; a few of these include high-resolution reservoir simulation, dumpflooding, closed-loop water source system, and dual-string completions. The integration of strong domain expertise, coupled with advanced technologies and workflows, has led to outstanding results.
Beta-Glucuronidase (GusA) reporter enzyme assay for Escherichia coli
Authors: Huber Madeleine , Soppa Jörg 
Published: September 2019

Abstract
The beta-Glucuronidase (GusA) is a long-known reporter enzyme for many different species [1]. The E. coli gusA gene is often used in plant research because plants lack an endogenous gusA gene. In E. coli, the transcript of the gusA gene is more stable than that of the highly used reporter gene beta-galactosidase (lacZ) [2]. The GusA activity can be determined using the artificial substrate p-nitrophenyl-β-D-glucopyranosid (pNPG). pNPG is converted to glucoronic acid and para-nitrophenol (pNP), which can be quantified spectrometrically at 405 nm. To avoid background, it is best to use an E. coli strain with a deletion of the chromosomal gusA gene, which is available e.g. at the Keio collection [3]. The gusA gene can be used for transcriptional fusions, e.g. to characterize promoters, and also for translational fusions, e.g. to study translational regulation. The assay was adapted to the microtiter plate format to enable the parallel handling of a large number of samples. The “procedure” (see below) describes an application with the gusA gene in a translational fusion with the gene of interest cloned under the control of the inducible arabinose promoter PBAD.