bluuebunny/crossref_metadata_2025_split huggingface dataset:
Urucu Field Integrated Production Modeling
Authors: Campos Sthener R. , Teixeira Alex F. , Vieira Leonardo F. , Sunjerga Snjezana 
Published: July 2010

Abstract
The main objective of this paper is to present a model based integration platform to perform 60+ oil wells optimization in PETROBRAS Urucu field (Solimões Basin, Amazon Rain Forest), while honoring operational constraints on wells, production separators, pipelines, and total field gas processing capacity.
The solution was built based on current technologies of modeling gas and water coning in the high-permeability reservoirs of Urucu, including detailed 3D finite-difference well models automatically history matched to production data, and empirical models based on fundamental flow theory. The well models have been integrated into a prototype solution to simultaneously solve for all 60+ optimal well rate controls. The optimization scheme should determine the optimum setting of well control (e.g. liquid rate) of all the wells in the field and advise on production management of each individual well. The developed concept is presented in the paper.
Another important development presented is a virtual metering modeling that estimates production rate of each well, based on real time data of pressure and temperature measurements on wellhead.
The Urucu field optimization strategy relies intensively on the engineering work related to process and technology. An international and multidisciplinary group including academic collaboration was established to compose the various knowledge needed to embrace the challenge.
Experimental Investigation of Caustic Steam Injection for Heavy Oils
Authors: Madhavan R. , Mamora Daulat 
Published: July 2010

Abstract
An experimental study has been conducted to compare the effect of steam injection and caustic steam injection in improving the recovery of San Ardo and Duri heavy oils. A 67 cm long × 7.4 cm O.D (outer diameter), steel injection cell is used in the study. Six thermocouples are placed at specific distances in the injection cell to record temperature profiles and thus the steam front velocity. The injection cell is filled with a mixture of oil, water and sand. Steam is injected at superheated conditions of 238°C with the cell outlet pressure set at 200 psig. The pressure in the separators is kept at 50 psig. The separator liquid is sampled at regular intervals. The liquid is centrifuged to determine the oil and water volumes, and oil viscosity, density and recovery. Acid number measurements are made by the titration method using a pH meter and measuring the EMF values. The interfacial tensions of the oil for different concentrations of NaOH are also measured using a tensionometer.
Experimental results showed that for Duri oil, the addition of caustic results in an increase in recovery of oil from 52% oil initially-in-place (OIIP) (steam injection) to 59 % OIIP (caustic steam injection). However, caustic has little effect on San Ardo oil where oil recovery is 75% OIIP (steam injection) and 76 % OIIP (caustic steam injection). Oil production acceleration is seen with steam-caustic injection. With steam caustic injection there is also a decrease in the produced oil viscosity and density for both oils. Sodium hydroxide concentration of 1 wt % is observed to give the lowest oil-caustic interfacial tension. The acid numbers for San Ardo and Duri oil are measured as 6.2 and 3.57 mg KOH per gram oil respectively.
EOR Geomechanical Screening- Identification of Risks to Mitigate and Opportunities to Pursue
Authors: Qobi Latifa , Alexander Dave , Strauss Jonathan , Kindy Fahad 
Published: July 2010

Abstract
Geomechanics plays a significant role in the decision making process associated with many parts of the E & P business, spanning exploration, appraisal and production activities and supporting field (re-) development, abandonment and well execution phases. Petroleum Development Oman (PDO) has many mature fields that are subject to either secondary or tertiary recovery mechanisms. Geomechanics has been demonstrated to have a significant impact on the productivity, safety and environment. This is most prevalent in EOR projects and the associated waste disposal systems.
The aim of this paper is to demonstrate: ▪The range of potential threats and opportunities related to steam and polymer flood in EOR developments▪Fit for purpose procedures that can be utilized for early screening of potential risks▪How an early risk and opportunity register related to the geomechanics behavior of the reservoir due to these developments can be established and classified in a scale of likelihood of occurrence versus impact▪Define fit for purpose data gathering, well and reservoir surveillance plans for mitigation
Such work is needed for a comprehensive identification of field measurements, laboratory tests and well and reservoir monitoring opportunities early in the project development process. Results from a clastic reservoir will be used as an example to illustrate the above.
EOR Development Screening of a Heterogeneous Heavy Oil Field - Challenges and Solutions
Authors: Strauss J. P. , Alexander D. M. , Al-Azri N. , Al-Habsi M. , Al-Musallami T. , Koning M. , Eriavbe F. , Al-Jarwani R. , Landman A. J. 
Published: July 2010

Abstract
This paper covers EOR development concept screening from a sub-surface perspective. The field in question is a medium sized heavy oil field with complex geology that is located in South Oman. The two front running concepts considered are steam and polymer flood, both of which present their own challenges. Common to both concepts are the difficulty in obtaining adequate conformance in a field that is characterised by high and highly variable permeabilities in a channelised environment and that includes lateral extensive shales that break the system up into vertically distinct sand units. Additional challenges are presented by a permeable regional scale aquifer, an erosive top surface that reduces the equivalent oil column (EOC) in the core of the field leaving thicker columns laterally close to the edge aquifer and the friable nature of the sand that makes sand control necessary. Challenges specific to steam are the relatively high initial pressure, inferred connection to a regional-scale strong aquifer, and relatively high CAPEX associated with the development. Polymer on the other hand represents a relatively untested option for oil with viscosities of greater than 400cP as are present in this field.
Modelling work used to identify risks and the subsequent development potential of these two options is presented. Potential development and maturation solutions for the various options are discussed and concepts are compared.
Alkaline-Surfactant-Polymer Flood: From the Laboratory to the Field
Authors: Stoll W. M. , al Shureqi H. , Finol J. , Al-Harthy S. A. , Oyemade S. , de Kruijf A. , van Wunnik J. , Arkesteijn F. , Bouwmeester R. , Faber M. J. 
Published: July 2010

Abstract
After two decades of relative calm, chemical EOR technologies are currently revitalized globally. Techniques such as alkaline surfactant-polymer flooding, originally developed by Shell, have the potential to recover significant fractions of remaining oil at a CO2 footprint that is low compared to, for example, thermal enhanced oil recovery, and they do not depend on a valuable miscible agent such as hydrocarbon gas. On the other hand, chemical EOR technologies typically require large quantities of chemical products such as surfactants and polymers, which must be transported to, and handled safely in, the field.
Despite rising industry interest in chemical EOR, until today only polymer flooding has been applied on a significant scale whereas applications of surfactant-polymer (SP) or alkaline surfactant-polymer (ASP) flooding were limited to multi-well pilots or to small field scale. Next to the oil price fluctuations of the past two decades, technical reasons that discouraged the application of chemical EOR are excessive formation of carbonate or silica scale and of strong emulsions in the production facilities.
Having identified significant target oil volumes for ASP flooding, Petroleum Development Oman (PDO), supported by Shell Technology Oman, carried out a sequence of single-well pilots in three fields, sandstone and carbonate, to assess the flooding potential of tailor-made chemical formulations under real subsurface conditions, and to quantify the benefits of full- field ASP developments.
The paper discusses the extensive design process that was followed. Starting from a description of the optimisation of chemical phase behaviour in test tubes as well as core-flood experiments, we elaborate how the key chemical and flow properties of an ASP flood are captured to calibrate a comprehensive reservoir simulation model. Using this model we evaluate PDO's single-well pilots and demonstrate how these results are used to design a pattern-flood pilot.
Experimental Investigation into the Influence of Convective Dispersion and Model Height on Oil Drainage Rates during VAPEX
Authors: Alkindi Abdullah , Muggeridge Ann , Al-Wahaibi Yahya 
Published: July 2010

Abstract
Vapour extraction (VAPEX) has received considerable attention as an enhanced heavy oil recovery process. Like SAGD it relies on significantly reducing the oil viscosity but has the advantage over SAGD that it will be effective in thin or deep reservoirs where thermal methods are impractical due excessive heat losses. Nonetheless field applications of VAPEX have been limited partly due to difficulties in predicting the high oil rates observed in laboratory experiments and thus in upscaling the results to field scale.
In this paper, we present a laboratory investigation of the VAPEX process using analogue fluids in a well characterized glass bead pack. The experiments were focused specifically on determining the role of convective dispersion and reservoir thickness on drainage rates. Longitudinal and transverse dispersion coefficients were measured with and without gravity in order to quantify the impact of interstitial velocities and contrasts in the fluids' viscosity and density on the rate of mixing as encountered in VAPEX.
The experimental measurements of oil drainage rates were higher than predicted by the standard Butler-Mokrys analytical model assuming diffusion-controlled mass transfer. The use of measured dispersion coefficients however significantly improved the model predictions. In addition, the results found drainage rates to have a higher than square root dependency on model height. The combined effects of the roles of convective dispersion and model height on drainage rates were incorporated into a predictive model that satisfactorily matched measured rates in the laboratory.
A Novel Ultra-low Interfacial Tension Foam Flooding Agent to Enhance Heavy Oil Recovery
Authors: Kang Wanli , Liu Shuren , Meng Lingwei , Cao Dongqing , Fan Haiming 
Published: July 2010

Abstract
Foam as a mobility control agent in enhanced oil recovery is becoming more and more attractive. Recently, ASP foam flooding method was proposed, which was based on the mechanism of both lowering interfacial tension to an ultra-low value (10−3mN/m grade) and improving sweep efficiency of displacing fluid. However, the alkali (NaOH or Na2CO3) in the ASP system will bring about scaling in the reservoir and pipelines if the formation water contains a large number of divalent cations such as Ca2+ and Mg2+. Therefore, it is necessary to develop a non-alkali foam flooding system to improve oil recovery.
A novel ultra-low interfacial tension foam agent is developed by the combination of surfactant and additives to lower oil-water interfacial tension and the addition of polymer to improve foam stability. Firstly, the concentration of surfactant and non-alkali additives used as the foam agent was determined by interfacial tension contour diagram. Then, the molecular weight and concentration of HPAM to enhance foam stability in the reservoir was screened. The foamability of the formula was measured using airflow method. Furthermore, the effects of temperature, salinity and shearing on the interfacial property and foamability were investigated to know the adaptability of this method to different oilfields. The heavy oil displacement experiments showed that the final oil recovery could be improved approximately 23% initial-oil-in place over waterflood recovery for the heterogenous core model of which permeability variation coefficient is 0.65, more than that of alkaline-surfactant-polymer flooding.
Well Bore Heat Loss - Options & Challenges for Steam Injector of Thermal EOR Project in Oman
Authors: Wang Jianshe (James) , Macfadyen Ross , Zhang Eamon , Mukhaizna Occidental 
Published: July 2010

Abstract
Wellbore heat loss is an important factor in steam flooding. It influences the magnitude and form that heat energy is injected into the reservoir, which impacts final recovery and project economics as well as flooding conformance in the context of viscous fingering of the liquid phase. Sufficient down hole steam quality is critical for the success of steam flooding projects. Heat loss can be measured by steam quality change from wellhead to bottom hole. Many factors affect down hole steam quality, such as completion design and injection rate. It is a reservoir management and production surveillance challenge to obtain quantifiable down hole steam quality values. Unfortunately, reliable down hole steam quality measurement is still effectively unavailable.
This paper introduces a study and practice for steam injection wellbore heat loss modeling for Mukhaizna steam flood project in Oman. A state-of-the-art numerical thermal well model is used, supported by some empirical data calibration. Important influencing factors are discussed in the paper including completion design, injection rate, reservoir pressure, etc. The findings of this study strengthen and enhance the knowledge and understanding of steam injector behavior. Some useful practical guidelines for injection well design and field operation are recommended.
Designing Alcohol-Free Surfactant Chemical Flood for Oil Recovery
Authors: Shiau B. J. , Harwell Jeffrey H. , Dinh Anh V. , Roberts Bruce L. , Hsu Tzu-Ping , Anwuri Ovinuchi I. 
Published: July 2010

Abstract
This work shows a unique method for determining the composition of an aqueous solution for chemical EOR using surfactants, salts, and polymer without the addition of a co-solvent. Phase behavior studies composed of reservoir brine, alkali, surfactants, salts, polymer and reservoir crude oil are evaluated as a function of time for onset of phase equilibrium and middle phase formation at ambient temperature and pressure. The optimal surfactant formulation was confirmed by a fast coalescence rate of formation of middle-phase microemulsion and ultra-low interfacial tension. Optimum formulations from phase behavior studies are further evaluated in 1-D sand-pack using crushed sandstone, reservoir oil, and brine at reservoir temperature. One half of a pore volume (PV) of the selected surfactant/polymer (SP) or alkali/surfactant/polymer (ASP) solution is used to flood the column and is followed with reservoir brine until no more oil is produced. The optimum SP and ASP compositions for oil mobilization from the sand pack studies are then investigated in a core flood apparatus. Residual oil saturation was first established in a Berea core at the targeted reservoir temperature and pressure. The core is then flooded with 0.5 PV of the optimum SP or ASP formulation, followed by reservoir brine until no more oil is produced. A unique aspect of this work is that the packed column studies predict core flood results. Packed bed studies are much faster, the apparatus is much less complex and much less expensive, relative to a core flood apparatus. The level of surfactant loading is 0.51% to 0.55% with 2.1% salt. The alcohol-free surfactant loading is lower that previously reported levels. Core floods show oil recoveries ranging from 55% to 64% of the residual oil after waterflooding.
Quantifying Geochemical Interactions When Injecting into a Sour Oil or Gas Field
Authors: van Putten Sascha , Gupta Arjit , Oraimi Mahmood , Abri Ali 
Published: July 2010

Abstract
In this paper the study results for gas and/or water injection into sour fields located in the South Oman Salt Basin (SOSB) is presented. The hydrocarbons in the fields are contained in carbonate “stringer” reservoirs, which are slabs of carbonates floating within salt. The fields in this area are typically high pressure, high temperature sour (H2S and CO2) reservoirs.
The typical development concept for these type of fields in general follows a staged approach: (1) An appraisal phase, (2) An early production phase from primary depletion, followed by (3) a miscible gas flood (or a water flood), and ultimately (4) a gas blow down phase. The objective of this phasing is to allow for optimal learning and economies of scale.
This paper presents a part of the work done in preparation of the third development phase with a specific focus on quantifying the interaction of an injectant with the reservoir rock. In other words due to geochemical reactions of the injected gas (or water) with the host rock or formation water, mineral dissolution or precipitation can occur. As a result, the reservoir properties in the reservoir are altered that could potentially result in well injectivity and/or productivity issues (either through pore plugging or fine migration).
The development of reactive flow simulation tools that are capable of modeling the relevant process (e.g. fluid flow, geochemistry, rock behavior) is currently an active research topic in industry. In this paper we will present a modeling workflow to improve our fundamental understanding taking into account some of the current limitations of the modeling tools. The workflow will be described through presenting several modeling examples using different simulation tools (e.g. geochemical modeling tools, PVT modeling tools).
Effect of Clay, Brine and Chemical Treatment in the Wettability Alteration of Berea Rock
Authors: Wu Stanley , Firoozabadi Abbas 
Published: July 2010

Summary
Alteration of wettability from liquid wetting to intermediate gas wetting has great potential in improving gas well productivity from water-blocking and condensate blocking in gas reservoir. Presence of some salt ions such as Na+ even in small quantities in the initial water in the rock has detrimental effect on the alteration of wettability. Berea cores are usually used in laboratory flow studies including in the alteration of wettability. In this work, we present a comprehensive study on the use of Berea, both unfired and fired, in single and two-phase flow with a focus on salt effect on wettability alteration. Three fluoro-chemicals are used in the treatment. We find that one of the three, a nonionic polymeric surfactant is very effective in the alteration of wettability in fired Berea with and without initial salt presence in the rock. The treatment efficiency of ionic surfactants is reduced at the presence of initial salt.
Integrated Evaluation of Surfactant-Polymer Floods
Authors: Gao P. , Towler B. , Li Y. , Zhang X. 
Published: July 2010

Abstract
This paper proffers some guidelines for using a surfactant-polymer (SP) flooding operation so that the feasibility and profit can be optimized. Many successful projects have shown that surfactant-polymer flooding is an effective means to improve oil recovery after or during water-flooding. Here, the guidelines for evaluating whether a surfactant-polymer flood is suitable for a given field are developed and the procedure for a full implementation is summarized. These guidelines cover primary screening, laboratory measurements, reservoir simulation, economic analysis, pilot testing, and field application. Detailed methods also are presented for the optimization of chemicals (including compatibility tests between chemicals and reservoir fluids and rock), well pattern and spacing preparation, and slug and injection process design. The correlations between the above phases of operation are also emphasized. The work offers reservoir engineers a reference for decision-making in SP flooding.
A Drilling Rate Model for Roller Cone Bits and Its Application
Authors: Hareland G. , Wu A. , Rashidi B. 
Published: July 2010

Abstract
Modeling bit performance is a scientific approach to optimizing drilling performance. Drilling rate or rate of penetration (ROP) is one of bit performance indexes. Several ROP models for roller cone bits have been developed over the years. However, there exist errors to some extent between these models and the field. This is because of the technical complexity of the bit-rock interaction. This paper introduces a new ROP model based on the interaction mechanism between drill bit and rock. The ROP model takes into account bit structure, especially cutting structure, and drilling parameters, such as WOB, RPM, and bit wear. The paper then focuses on applications of the ROP model in predicting drilling rate and rock compressive strength with drilling well data from Western Canada.
Simulations were carried out using the ROP model for roller cone bits with two sets of offset well drilling data. The predicted ROP and rock strength when the model is used in an inverted mode were compared with field data or results from log rock strength data respectively. The comparison shows the ROP model can predict drilling operational ROP and rock compressive strength well.
The ROP model is different from others in that it takes into account the bit cutting structure in more detail. The model can reflect the effects of different number of inserts and insert shape on ROP.
The model is especially useful when selecting a roller cone bit with same IADC code but with different insert features and designs, and can be used in optimizing the drilling parameters in a planning mode and predicting the unconfined compressive strength in an inverted mode.
CO2 Based VAPEX for Heavy Oil Recovery in Naturally Fractured Carbonate Reservoirs
Authors: Gul Ali , Trivedi Japan J 
Published: July 2010

Abstract
With the increasing demand for energy production and environmental concerns, the focus has been shifting towards new green recovery techniques for heavy oil complex reservoirs such as naturally fractured carbonate reservoirs (NFCRs). After the success of VAPEX as an alternate to SAGD for heavy oil recovery, it has been studied for fractured reservoirs in recent years. Moreover, CO2 has been a successful EOR agent in fractured light-medium oil reservoirs and thus can be used as a higher soluble, low cost, and environment friendly alternate to solvent. Our aim is to show that CO2 with VAPEX could be a feasible choice for NFCRs. This work is focused on investigating the applicability and optimization of CO2 based solvent extraction process for heavy oil recovery and greenhouse gas sequestration from NFCRs.
A series of numerical experiments were performed to study the role of a) solvent type, b) operating condition, c) oil and gas diffusion, and d) extraction process; in various single/multiple fracture configurations while injecting CO2 - solvent in different ratios. The optimal injection rate and CO2 - solvent concentration ratio were obtained considering maximum oil recovery and CO2 storage. A parametric study was also performed to analyze the influence of various operational and reservoir parameters such as fracture properties, fracture configurations, oil viscosity, solvent type, and injection/production constrains. The results suggested that CO2 or conventional VAPEX alone may not be able to achieve higher recovery in high pressure NFCRs, but CO2 based VAPEX can provide efficient technique to recover heavy oil with emphasis on sequestration.