bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simplified Reaction Kinetics Model for In-Situ Combustion
Authors: Klock K. , Hascakir B. 
Published: November 2015

Abstract
We integrate the results of six one dimensional combustion tube tests and several reaction kinetics experiments conducted with Thermogravimetric Analyzer and Differential Scanning Calorimetry (TGA/DSC) to investigate fully the burning characteristics of a Canadian bitumen (8.6 °API, 54,000 cP at 25 °C). Our ultimate goal is to estimate the variations in the chemical reactions occurring during in- situ combustion (ISC) within a reservoir which has heterogeneously distributed fluid saturations. Thus, six combustion tube experiments are conducted at varying initial water (Swi=0%, 16%, and 34%) and oil (Soi=34%, 54%, and 84%) saturations. The best performances are achieved for high initial oil and water saturation cases. The dominance of the low temperature oxidation (LTO) reactions is observed in the experiment with the intermediate water saturation (16%). The combustion front for the experiments without water (Swi=0%) could not sustain. The combustion tube results are further investigated with the reaction kinetics experiments. Hence, ISC experiments are simulated by TGA/DSC at constant (5, 10, and 15 °C /min) and varying (observed during combustion tube experiments) heating rates. The combustion tube tests suggest that water is a critical component which maintains the sustainability of the combustion process. The reaction kinetics experiments reveal that at the latent heat, interaction of steam with bitumen enhances the burning characteristics of bitumen. If the combustion front temperature (~ 400 °C) is reached with low heating rates (5 °C /min), the LTO reactions lead the formation of several different types of fuel which cannot generate sufficient heat to maintain the sustainability of combustion. Hence, LTO products adversely affect the performance of ISC for the cases which had insufficient heat generation or no initial water. However, higher heating rates (10-20 °C /min) lead the formation of more effective fuel which can generate more heat upon cracking at higher temperature ranges and maintains the sustainability of the combustion front. Because at lower initial oil and at no water saturation cases lower heating rates are observed during ISC experiments, ISC could not sustain. And, since at higher initial oil saturation with the existence of initial water saturation cases higher heating rates are witnessed during ISC experiments, the combustion process could maintain sustainability. Therefore, we recommend the injection of water to the zones with lower initial water saturations prior to field application of ISC to increase the heating rate of ISC zones.
UNISIM-II-D: Benchmark Case Proposal Based on a Carbonate Reservoir
Authors: Correia M. , Hohendorff J. , Gaspar A. T. , Schiozer D. 
Published: November 2015

Abstract
Brazilian pre-salt reservoirs are mainly carbonate formations and they represent a great opportunity for research development. There is an increasing need of synthetic simulation models that reproduce these Pre-salt flow features for research development in reservoir simulation. This work presents a simulation benchmark model available as public domain data that represents Brazilian pre-salt trends and add a great opportunity to test new methodologies for reservoir development and management using numerical simulation.
The work structure is divided in three steps: development of a reference model with known properties, development of a simulation model under uncertainties considering a specific date that represents the field development phase, and, elaboration of a benchmark proposal for studies related to the oil field development and production strategy selection. The reference model, treated as the real field, is a fine grid model in order to guarantee a high level of geologic details. The simulation model under uncertainties is a large scale model, a result of a development project considering an initial stage of field management.
The benchmark model is based in a combination of Pre-salt characteristics and Ghawar field information given its diagenetic events and flow features close to Pre-salt. Based on the available information, several uncertainty attributes were considered in structural framework, facies, petrophysical properties, discrete fracture network. Economic and technical uncertainties were also considered. There is an increasing need of synthetic simulation models that reproduce these Pre-salt flow features for research development in reservoir simulation. This work presents a simulation benchmark model available as public domain data that represents Brazilian pre-salt trends and add a great opportunity to test new methodologies for reservoir development and management using numerical simulation. The main result of this project is achieved: the construction of a reference model and the construction of a simulation model under uncertainties assuming the well log information from three wells. This work provides a great contribution for further research development in reservoirs with geologic and dynamic pre-salt trends.
Dynamic Drill-rate Test Approach Appplied to a Pre-salt Case Study
Authors: Nascimento A. , Elmgerbi A. , Roohi A. , Prohaska M. , Thonhauser G. , Mathias M. H. 
Published: November 2015

Abstract
Pre-salt basins and its exploration have become more and more frequently mentioned over the years, not just for their potential reserves, but for the implicit challenges in terms of general operations (downstream and upstream) to be faced in order to make these fields effectively commercially viable. Several research efforts aimed at to addressing these related barriers, but still in the drilling optimization and efficiency discipline, as a known challenge, a considerably low drillability is experienced when drilling throughout the pre-salt carbonates itself.
A lot of already known rate of penetration (ROP) modeling and Specific Energy (SE) studies have been developed and improved during the past 50 years, helping in post- and pre-operations analysis, allowing simulations and tendency estimations, enabling a better understanding of possible parameters and design combinations for operations optimization and efficiency enhancement.
Pre-run tests may be a very important tool together with consequent interpretation and re-usage of the results to help in boosting optimization in operations. Thus, the main focus of this paper is to address a reverse engineering by evaluating specific well data and information, identifying gaps to boost rate of penetration for a pre-salt well case study, based on a drilling mechanics analysis proposing a new analysis methodology, by playing-back through a reverse engineering procedure the drill-rate test curves, exemplifying its impact in analysis with a more dynamic and real-time focus.
Predicting and Managing Inorganic Scale Associated With Produced Water from EOR Projects
Authors: Jordan M. , Mackay E. 
Published: November 2015

Abstract
Inorganic scale associated with conventional hydrocarbon extraction has been well studied over the past 50 years and the mechanisms of formation, inhibition and removal are now well understood within the industry. For enhanced oil recovery (EOR) significant changes occur within the reservoir as a result of injected chemical or changes in fluid type that are used to increase the oil recovery. Two such EOR processes, CO2 and alkali surfactant polymer (ASP) flooding, are the subject of this paper.
CO2 is miscible with oil when injected at high enough pressure, but is also very soluble in water. The resulting low pH carbonic acid typically increases the geochemical reactivity of the system, and thus it is no longer sufficient to consider the scale risk associated with the formation and injection brines, but the impact of mineral dissolution deep within the reservoir may also be a factor when analysing the scale risk as the brines are produced. The requirement for such calculations, which are not typically conducted during conventional hydrocarbon recovery processes, is discussed. Consideration is given to the value of developing models that will predict the concentration of scaling ions, and hence the scaling risk, at the production wells based on in situ reactivity.
In the case of ASP flooding, the current industry understanding of scale prediction models for such systems is discussed, along with the current inhibitor screening tests to qualify scale inhibitors for squeeze application. The design of the different squeeze treatments applications for treatment of formation water and injection water production are presented. Along with the scale challenges within the production well, the scale issues associated with processing the produced ASP fluids will be reviewed in terms of additional scale risk not associated with conventional hydrocarbon production.
The objective of this paper is to highlight the challenges, current understanding and gaps in the industry knowledge and processes when it comes to scale management for EOR projects.
Simplified Near Wellbore Reservoir Simulation To Predict the Performance of Viscous Oil Horizontal Well With Water Coning From an Active Aquifer
Authors: Jurus W. J. , Stanko M. , Parra A. , Golan Michael 
Published: November 2015

Abstract
This paper describes the development of a comprehensive 2D near wellbore reservoir model to history match and predict the not yet fully understood production performance and deliverability of horizontal wells producing a heavy viscous oil (~300 cp). This in the presence of water conning from an active aquifer. The target application is heavy oil reservoirs (e.g. Rubiales field, Colombia) with rapidly increasing or high producing water cut (~90%), constant reservoir pressure maintained by an active aquifer, and high horizontal pay zone permeability (~15 D).
The methodology employs a simplified 2D horizontal wellbore reservoir model with enough flexibility (i.e. tuning parameters) to match the measured wells production profile (i.e. water production and producing water cut). One well with full production record was analyzed.
The following modeling strategies were tried out: providing an adequate pressure support from the aquifer, increasing artificially the oil mobility in the porous media as the water saturation increases and hindering the vertical water migration from the aquifer towards the well. These modeling strategies added additional tuning variables besides the conventional formation parameters.
Model parameters were varied automatically using an optimization engine minimizing the difference between the simulated and the measured data.
Several modeling approaches were tried out in the simulator: standalone variation of the oil viscosity, oil viscosity variation with water saturation, oil-water emulsion behavior using inversion point and Richardson model, Fetkovich type numerical aquifer, water injector with constant bottom-hole pressure and tunable injectivity index, initial water saturation variation with depth within oil zone.
Almost all the modeling approaches yielded an acceptable history match (&lt;6%) for water production profiles. The match of the bottomhole pressure is more challenging, as satisfactory residuals are only obtained in certain production periods. It was not possible to reproduce the bottomhole pressure trend considering simple aquifer volumetric expansion and emulsion behavior throughout the entire reservoir domain.
The present paper proposes the utilization of a simplified 2D near wellbore reservoir model to successfully represent the performance of viscous oil high water cut producing wells with complex physics. The results show that it is possible to overlook the complexity of such reservoirs by "wrapping them up" in a few macro parameters and still keeping physical consistency.
A Novel Method to Calculate Asphaltene Solubility Parameter
Authors: Souza M. M. , de Melo S. A. , Costa G. M. 
Published: November 2015

Abstract
Asphaltene precipitation is a challenging and complex problem in all sections of the oil industry including oil production, transportation and processing. Asphaltenes can plug pumps, valves, tubing and flow lines, cause fouling in surface handling facilities and even act as coke precursors and catalyst poisons. For these reasons, the occurrence of asphaltene deposits may result in productivity losses and sometimes even production shutdowns. For many years, much effort has been done on modelling asphaltene precipitation because experimental investigation is a hard task. Thermodynamic models based on Flory-Huggins theory have been used by several oil companies to predict the asphaltene onset conditions due to the depletion or gas injection. However, the main requirement to accomplish a successful calculation of asphaltene precipitation is an accurate solubility parameter. A variety of models to calculate asphaltene precipitation based on the solubility parameter is available in literature but most of them are complex due to inherent assumptions that are built-in. In this work, a new simple and accurate method to calculate the asphaltene solubility parameter is proposed, which requires only SARA (saturate, aromatic, resin, and asphaltene) analysis, the oil composition and the reservoir temperature. Once it is sufficient to know up to C7+ fraction, a much detailed analysis of the oil composition is unnecessary. Soave-Redlich-Kwong (SRK) (Prausnitz et al. 1999) equation of state (EOS) and Pedersen's characterization method (Pedersen et al. 1984) were used to calculate the liquid phase molar volume and SARA analysis was employed to determine the number of fractions that correspond to the amount of asphaltene in the oil. Five oils were selected from literature and calculation of their asphaltene solubility parameter was performed without needing their composition in details. Just one fraction was sufficient to include the amount of asphaltene indicated in SARA analysis for all oils tested. Each oil was considered as a mixture of 26 components. The values of asphaltene solubility parameters calculated by a simple method based on SRK EOS were comparable to those given by perturbed-chain statistical associating fluid theory (PC SAFT) EOS available in literature (Punnapala and Vargas 2013), which requires an extremely detailed characterization of the oil. Therefore, the proposed simple method is preferred because it is much more useful to the oil industry.
Mature Oil Field Reservoir Characterization Integrating Well Logs and Wireline Pressure Transient Diagnostics Data
Authors: Gelvez C. , Torres C. , Lozano E. , Avila R. 
Published: November 2015

Abstract
A mature oil field reservoir is characterized by gathering the geological and petrophysical data with the dynamic data. The product allows the defining of vertical reservoir units and their continuity along the field. Reservoir properties, seals and barriers are determined by pressure data and compared with the petrophysical interpretation.
This document presents a profound study on pressure data interpretation and how to integrate this information with a petrophysical-geological model obtained by well log data analysis. The sands correlation, reservoir properties, faults location and vertical seals, are interpreted at first with the well log data (GR-SP-RES-DN-PE) and seismic data. Then the pressure data points are analyzed taking into account the previous interpretation to confirm the sands vertical connectivity, fluid gradients and the fluid contacts. Additionally, the mini PBU transients are diagnosed by means of computer-aided type curves to evaluate flow regimes in the near wellbore region and to calculate the permeability. Finally, a fully integrated static petrophysical model is built based on the previous study.
The geological cross section is compared before and after the pressure data integration. Ten recently drilled wells from three different reservoir areas with pressure data available are analyzed and presented in this paper. The pressure data evaluation allows identifying the 4 different formation units and its water oil contact (WOC), according to the pressure gradients. The pressure behavior along the horizontal section permits to estimate the sands continuity and the connectivity between three areas. The static reservoir pressure analysis serves to validate and improve the basic well log interpretation and should be a part of the formation evaluation workflow. In addition, a near wellbore model is a strong tool to support and improve the type curve diagnose and interpretation of dynamic data.
This paper provides a great insight on reservoir characterization and the benefits of the pressure logging tool for gathering static and dynamic information into geological models. In many cases formation testing data interpretation is based solely on the spherical flow analytical model. This straightforward approach might bias some features of the near wellbore region, which can only be assessed by pressure transient diagnosis (e.g. pressure derivative). Modeling of formation pressure testing as an interpretation tool strongly improves the near wellbore region dynamic description.
Recognition of Oil-Water Contact Architecture in Water Drive Reservoirs by Rock Typing Implementation, Sacha Field of Ecuador
Authors: Rodriguez L. , Leal J. , Sanchez H. , Hinojosa G. 
Published: November 2015

Abstract
This paper discusses the successful, fully integrated petrophysical and geological modeling of the Hollin formation in the Sacha field of Ecuador. The goal of the modeling project was to unravel aquifer heterogeneities and hydrodynamic effects; it focuses on suitable petrophysical rock typing, supporting the establishment of a tilted water/oil contact (WOC) that follows a particular architecture across the field.
Documenting WOC changes is extremely important during reservoir modeling. Changes in fluid levels can be related to, among other things, structural complexities, rock heterogeneities, and hydraulic movement effects. However, when dealing with a mature field characterization that has undergone an accelerated production, flow capacity differences and remaining reserves become critical points to delineate aquifer heterogeneities. The identification of aquifer heterogeneities and possible hydrodynamic flow were considered separately to address this problem, using available core data, a log-derived water saturation (Sw) model, and dynamic performance integrated with a rock typing approach.
Such factors were considered when studying the Cretaceous Lower Hollin formation in the Sacha field. The Sacha field is a mature field in Oriente basin, Ecuador, and the reservoir is characterized by a sequence of amalgamated sandstones deposited primarily by a braided stream system. A strong aquifer underlies this sequence of amalgamated sandstones and maintains a stable pressure. As a result, various WOCs are displayed at different levels in the wells with a variation of up to 70 ft across the field. Aquifer heterogeneities were identified as facies changes, faults, and capillarity effects that perhaps triggered these WOC irregularities. Although these anomalies do not prevent vertical fluid communication within the reservoir, they represent an important step for proper electrical rock property interpretation; thus, providing a more realistic reservoir Sw model. The construction of rock-fluid surfaces helps to identify the aquifer heterogeneities related to steady state WOC depths. The textural features of the rock in conjunction with an identified water recharge point created an WOC surface that vary the inclination rates from 2 ft/km northward, 13 ft/km eastward, and southward across the field, creating a predictable WOC architecture that affected water production.
This improved understanding of key petrophysical aspects and methods arising from work undertaken to solve various problems related to the tilted WOC have revealed new opportunities to the field edges. These opportunities have been tested with newly drilled wells with excellent results. The results obtained from these tests are having a significant effect on future drilling programs.
The Catalytic Effect of Clay on In-Situ Combustion Performance
Authors: Kozlowski M. L. , Punase A. , Nasr-El-Din H. A. , Hascakir B. 
Published: November 2015

Abstract
The in-situ combustion (ISC) is highly effective thermal enhanced oil recovery process in which high displacement efficiencies can be accomplished. While several physical and chemical factors affect the ISC performance, there is a little knowledge about how each parameter changes the ISC fate. In this study, we investigate the catalytic effect of clay on different crude oil types.
Six one-dimensional combustion tube experiments were conducted on three different crude oil samples; one from Mexico and two from Alberta, Canada. The combustion behavior of each crude oil sample was tested with two combustion runs; by preparing reservoir rock with only sand (E1, E3, and E5) and by preparing reservoir rock with 3 wt% clay and 97 wt% sand mixture (E2, E4, E6). The combustion characteristics were monitored with temperature profiles, produced gas compositions, and produced liquid yields. The level of in-situ oil upgrading were determined by comparing the viscosities of produced oil samples with the original ones.
The results showed that the catalytic effect of the clay controls the combustion front propagation, the fuel formation, and the produced oil quality. Clays visualized on postmortem samples in the shape of lumps indicate that clay alteration occured at elevated temperature due to interaction of clay with crude oil and due to thermal decomposition of clay. It was observed that the lump formation was associated with mainly saturates and asphaltene contents of initial oil and asphaltene-clay interaction during fuel formation.
Our results support that the clay presence in reservoir rock had an impact on ISC performance. However, this impact did not have a linear trend and the response of the catalytic effect of clays were different from one crude oil to another; while one crude oil favored combustion more with the presence of clay, the other did not and led to lower oil production by producing more gas.
New Opportunities Identification Workflow, Pañacocha Field, Oriente Basin, Ecuador
Authors: Guerrero J. Rodas , Vega J. , Alvarez I. , Lafournère J. , Henson R. , Fonseca C. , Bravo L. , Minchala J. , Morales O. 
Published: November 2015

Abstract
Over the years, simulation models have been helping oil companies and stakeholders to make investment decisions. However, these models are not always available to help with the field development planning. A fast and efficient workflow performed for the identification of new opportunities in the Pañacocha field is presented.
To start the workflow, a conceptual geological model was identified for each reservoir, based on the available data and nearby analog fields. Quality control, updating and reinterpretation of well top data, petrophysical parameters maps (net pay, porosity, and water saturation), and original oil in place estimations were carried out to identify untouched areas. A total of 45 locations that may still contain oil were identified.
For the next step, a decline curve analysis was carried out, and well type curves were generated to determine the estimated ultimate reserves (EUR), drainage area, and recovery factor by well. The range of recoverable oil associated with each location was estimated by varying all the parameters involved in the volumetric formula.
Finally, the locations were ranked based on their production potential. The selection of drilling targets included the associated geological and operational risk. A base case, based on the contract minimum commitments, is presented. However, this study shows that a more aggressive drilling campaign is possible.
In conclusion, this workflow allowed us to have a better understanding of the field potential. Oil in place volumes and recovery factors were updated. Analysis of produced fluids helped to assess reservoir performance. The economic analysis following this study will help in selecting the best option to develop the field.