bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhancing the Performance of Viscoelastic Surfactant Fluids Using Nanoparticles
Authors: Gurluk Merve R. , Nasr-El-Din Hisham A. , Crews James B. 
Published: June 2013

Abstract
Viscoelastic surfactant (VES) based fluids are used in many applications in the oil industry. Their viscoelastic behavior is due to the overlap and entanglement of long wormlike micelles. The growth of these wormlike micelles depends on the charge of the head group, salt concentration, temperature, and the presence of other interacting components. The problem with these surfactants is that they are expensive and used at temperatures less than 200°F.
The viscoelasticity of nanoparticle-networked VES fluid systems were analyzed by rotational and oscillatory viscometers. Apparent fluid viscosities were measured by using 2–4 vol% amidoamine oxide surfactant in 13 to 14.2 ppg CaBr2 brines and 10.8 to 11.6 ppg CaCl2 brines at different temperatures up to 275°F and a shear rate of 10 s−1. The nanoparticles evaluated were MgO and ZnO at 6 pptg concentration. In addition, the effect of different nanoparticle concentrations (0.5 to 8 pptg) and particle size on the viscosity of VES fluid was investigated. The oscillatory shear rate sweep (100 to 1 s−1) was performed for the 4 vol% VES in 14.2 ppg CaBr2 from 100 to 250°F.
This study showed that the addition of nanoparticles improved the thermal stability of VES micellar structures in CaBr2 and CaCl2 brines up to 275°F and showed an improved viscosity yield at different shear rates. Micron and nano-size particles have potential to improve the viscosity of VES fluids. Lab tests show for VES micellar systems without nanoparticles, the dominant factor is the viscous modulus but when nanoparticles are added to the system at 275°F the elastic modulus becomes the dominant factor. These positive effects of nanoparticles on VES fluid characteristics suggest that these particles can reduce treatment cost and will extend the temperature range of the surfactants to 275°F.
History Matching Of The Norne Full Field Model Using An Iterative Ensemble Smoother
Authors: Chen Yan , Oliver Dean S. 
Published: June 2013

Abstract
Although ensemble-based data assimilation methods such as the ensemble Kalman filter and the ensemble smoother have been extensively used for history matching of synthetic models, the number of applications of ensemble-based methods for history matching of field cases is extremely limited. In most of the published field cases in which the ensemble-based methods were used, the number of wells and the types of data to be matched were relatively small. As a result, it may not be clear to practitioners how a real history matching study would be accomplished using ensemble-based methods.
In this paper, we describe the application of the iterative ensemble smoother to the history matching of the Norne field, a North Sea field, with a moderately large number of wells, a variety of data types, and a relatively long production history. Particular attention is focused on the problems of identification of important variables, generation of an initial ensemble, plausibility of results, and efficiency of minimization. We also discuss the challenges encountered in using ensemble-based method for complex field case studies that are not typically encountered in synthetic cases.
The Norne Field produces from an oil and gas reservoir discovered in 1991 offshore Norway. The full field model consists of four main fault blocks that are in partial communication and many internal faults with uncertain connectivity in each fault block. There have been 22 producers and 9 injectors in the field. Water alternating gas injection is used as the depletion strategy. Production rates of oil, gas and water of 22 producers from 1997 to 2006 and RFT pressure from 14 different wells are available for model calibration. The full field simulation model has 22 layers each with dimension 46 by 112 cells. The total number of active cell is about 45,000.
The Levenberg-Marquardt form of the iterative ensemble smoother (LM-EnRML) is used for history matching the Norne full field model using production data and RFT pressure. The model parameters that are updated include permeability, porosity and net-to-gross ratio at each gridblock, vertical transmissibility at each gridblock for six layers, transmissibility multipliers of 53 faults, end-point water and gas relative permeability of four different reservoir zones, depth of water-oil contacts and transmissibility multipliers between a few main fault blocks. The total number of model parameters is about 150,000. Distance-based localization is used to regularize the updates from LM-EnRML. LM-EnRML is able to achieve improved data match compared to the manually history matched model after three iterations. Updates from LM-EnRML do not introduce artifacts in the property fields as in the manually history matched model. The automated workflow is also much less labor intensive than manual history matching.
Fracture Mobility Control by Polymer Gel- Integrated EOR in Fractured, Oil-Wet Carbonate Rocks
Authors: Brattekås B. , Haugen Å. , Ersland G. , Eide Ø. , Graue A. , Fernø M. A. 
Published: June 2013

Abstract
This work experimentally investigates a two-step, integrated EOR technique for heavily fractured, oil-wet carbonate rocks by combining fracture mobility control and chase fluid injections for increased sweep. The combination of mobility control using a cross-linked Cr(III)-Acetate HPAM polymer gel, and three different chase fluids (water, surfactant or CO2 foam) was investigated as an integrated EOR approach. Waterflood oil recovery was low with poor sweep efficiency and oil production from the fracture volume only. Fracture conductivity was significantly reduced after polymer gel placement in the fracture, leading to increased sweep and oil recovery during chase fluid injections, with oil recoveries up to 60%OOIP.
Solvent-enhanced Spontaneous Imbibition in Fractured Reservoirs
Authors: Chahardowli Mohammad , Zholdybayeva Almagul , Farajzadeh Rouhi , Bruining Hans 
Published: June 2013

Abstract
Oil recovery in fractured reservoirs by water flooding critically depends on the wetting properties of the matrix blocks between the fractures. The recovery from oil-wet reservoirs is small. In incompletely oil-wet systems, the presence of initial water may change the wettability characteristics so that imbibition and some oil recovery can occur. The hypothesis in this work is that water-soluble solvent (diethyl ether) improve the ultimate recovery and the imbibition rate in partially and completely water-wet cores. The main recovery mechanisms are the wettability change of the partially water-wet cores and oil swelling and the oil viscosity reduction in both partially and completely water-wet cores.
This paper reports an experimental study concerning the recovery enhancement by water-soluble solvent (diethyl ether). We used an Amott imbibition cell studying oil saturated samples of various wettabilities, permeabilities using oils of different viscosities and two different diethyl ether (solvent) concentrations in the aqueous phase. In the first stage of the experiment, the completely water-wet core was exposed to brine without solvent. In a second stage, the core was put in a new Amott cell that was filled with solvent/ brine mixture. The extra recovery by solvent/brine mixture strongly depends on the residual oil saturation after brine imbibition and it is relatively insensitive to the permeability of the core or the oil viscosity. Therefore, larger residual oil saturation resulted in a higher extra recovery.
For the partially water-wet samples, we also started with exposing the core to pure brine without solvent. Contrary to the completely water-wet samples, there was a significant increase in recovery rate when the sample is transferred to another Amott cell where it is exposed to a mixture of solvent and brine. In view of large values of the inverse Bond number in both partially and completely water-wet cores, the transfer between matrix and fracture capillary driven.
Integrating Price Path Uncertainty Into Optimal Extraction Path Analysis of Unconventional Liquids Rich Reservoirs
Authors: Ozkan Sarp , Ozkan Erdal 
Published: June 2013

Abstract
The acquisition of unconventional assets has become viable under current technical and economical conditions. While producing the conventional resources, utilizing the reserve replacement potential offered by the unconventional reservoirs has brought up optimal extraction path considerations. Optimal extraction path analyses mainly focus on the timing of incorporating unconventional production within a company’s portfolio. This paper establishes a decision making framework that takes into account that different price scenarios can unfold with differing probabilities of occurrence and that switching from conventional to unconventional production comes at a cost. The model is based on an integrated discounted cash flow and optimization formulation to find the differing parameters necessary to populate a decision tree framework. A series of differing price paths are considered for a company with exogenously assigned probabilities of occurrence and an optimal path analysis is conducted under different assumptions regarding its risk propensity. A sensitivity analysis is also conducted on the probabilities of different price scenarios to better understand the risk the company faces in making production decisions. Using the framework introduced in this paper, a company should be able to make a more informed decision that considers price path uncertainty and risk preferences in the timing of the switch from conventional to unconventional production.
Investigating the Viability of Steam Flooding to Improve Oil Recovery in A Heterogeneous Light Oil Reservoir with Infinite Active Aquifer: A Comparative Simulation Case Study
Authors: Al-Mudhafer Wathiq 
Published: June 2013

Abstract
Thermal oil recovery m ethods could be an effective s olution to many crucial problems not only in hea vy/light oil reservoirs, but also in light oil reservoir. Steam flooding has proved it’s efficiency to change the reservoir and fluid properties in light oil reservoirs leading to higher oil displacement and sweep efficiency. The reservoir under study is the main pay/upper sandstone member in South Rumaila oil field located in Iraq. It is a mature oil field with around 58 years of production with 40 producing wells. The reservoir has an infinite acting aquifer located at the east and west flanks. The strength of this aquifer from the west flank is much larger than it’s in the east flank because the formation permeability at the eastern flank is less th an as at th e western one; therefore, 20 injection wells have been drilled at the east flank to maintain the aquifer water approaching to the reservoir. The formation depth is 10350 ft. sub-sea with a maximum vertical oil column of 350 ft. The average bubble point pressure of 2660 psi and the ave rage reservoir temperature is 210°F while oil density is 34°API. In this study, A comparative simulation study (Black oil and thermodynamic) has been done to investigate steam flooding feasibility improve oil recovery in comparison to two base cases of with and without water injection.
Two reservoir simulators, black oil (CMG-IMEX) & thermodynamic (CMG-STARS) have been applied to demonstrate the impact of steam flooding as heating agent to enhance the sweep efficiency through this heterogeneous reservoir. The steam injection has been done considering the current twenty injection wells with 10,000 stb/day per well. The results showed the co-impact of steam injection with simultaneously enhanced water drive from the aquifer to sweep the oil towards the reservoir crest. The cumulative oil production for steam flooding scenario has been compared with the outcome of the two base cases with and without water injection and demonstrated a significant incremental of oil recovery. The cumulative oil production for the two base cases at the final time step of 1 Feb. 2022 is equal to it's amount by steam flooding on 1 Oct. 2015.
Effect of Diluents on Interfacial Properties and SAGD Emulsion Stability: II. Differential Scanning Calorimetry and Light Scattering Methods
Authors: Balsamo Vittoria , Phan Jenny , Nguyen Duy 
Published: June 2013

Abstract
During the Steam Assisted Gravity Drainage (SAGD) production process, complex water-in-oil-in-water (W/O/W) emulsions are generated, which need to be treated to promote water-phase separation and recovery of the oil. Due to the similar density of heavy oil and water, dilution is frequently required to improve the separation process, but also to reduce the viscosity of the extracted bitumen to facilitate flow. Although significant research has been carried out to understand the stabilizing and destabilizing factors of both water-in-oil and oil-in-water emulsions, studies related to the characterization of complex W/O/W emulsions containing diluents are still limited. When carrying out this type of analysis, the complex relationship among different variables should be considered, such as the chemistry and concentration of stabilizing agents, water-to-oil ratio and droplet charge. Temperature and shearing methods are process conditions that must be also considered.
In this study we combined several techniques to characterize production fluids and synthetic emulsions, using diluents with different composition. Differential Scanning Calorimetry (DSC) was explored as a tool for analyzing the emulsions. Since the oil present in these fluids did not exhibit any thermal transition between -80°C and 30°C, the DSC could be used to quantify the amount of free and emulsified water in one measurement, for either synthetic or produced emulsions. Results demonstrated that this technique has a high potential to characterize emulsified systems with precision, requiring only small amounts of sample and without applying any pre-treatment. The technique can also be used to screen demulsifiers after performing a specific thermal treatment within the equipment.
Bottle tests are commonly used in the industry to monitor emulsion behavior. They are easy to perform, but are subject to the judgment of the experimenter, who measures the partitioning of the phases and in some cases their relative opacity. To perform a more quantitative analysis, demulsification was monitored in real-time, using a multiple light scattering device. Phase separation rates were highly influenced by the nature and amount of diluent used and they were correlated with droplet size, interfacial tension and surface pressure measurements. Results were rationalized based on the differences in the asphaltene-resins interfacial film, which will determine the emulsion behavior upon separation in the field when using demulsifiers.
SAGD Well Pair Spacing Evaluation with Consideration of Central Processing Facility Constraints
Authors: Cheung Kathy (Lai 
Published: June 2013

Abstract
When developing properties using the steam assisted gravity drainage (SAGD) process, the lateral spacing between horizontal well pair spacing is extensively evaluated during well pad design to optimize resource recovery and economics. However, constraints associated with central processing facilities (CPF) are often not incorporated into the evaluation. With constrained steam supply and fluid processing capacity, the accelerated production that should accompany a reduced well pair spacing scenario may not be realized. In this paper, the economics of developing a SAGD property using 50m, 85m, 100m and 125m well pair spacing are compared within Suncor's MacKay River property. A production development planning tool is used to tie the individual well production profiles to a constrained CPF. While higher oil production rates, a cumulative steam-oil ratio (CSOR) reduction, and slight increase in oil recovery are observed at the well pad level in the 50m well pair spacing scenario, no accelerated oil production is achieved at the CPF level as steam supply and fluid processing capacities are constrained. With larger well pair spacing, the addition of more new pads on an accelerated schedule serves to maximize the CPF capacity utilization and oil production. Hence, the overall oil production at the CPF level is practically the same regardless of well pair spacing. With the areas evaluated in this study, the economics of the 85m, 100m and 125m cases are very close, with the optimum achieved at 100m well pair spacing. The 50m well pair spacing scenario produces the worst economic result as the tighter spacing case requires incremental capital for additional wells to achieve the same resource recovery. Without the accelerated production at the CPF level due to facility constraints or appreciable incremental oil recovery and CSOR reduction overall, there is no increased revenue to offset the increased capital outlay.
Flammability Limits of Diesel and air Mixture for use in Underbalanced Drilling
Authors: Liu Yi , Mehta S. A. , Moore R. G. , Ursenbach M. G. 
Published: June 2013

Abstract
In an underbalanced drilling process, using diesel as an oleic additive to drilling mud increases the chance of explosion if the drilling fluids mix with natural gas or injected air and reach the flammable limits. Although some investigations about flammability limits of drilling fluids have been conducted on the basis of diesel components, further laboratory experimental study needs to be done. Initially, the properties of the two diesel samples, including heating value, molecular weight, densities and simulated distillation characteristics are measured and compared. Then, an experimental study is conducted to investigate the flammability limits of two diesel fuel samples (diesel A and B) at varied conditions of elevated temperature and pressure using a specially designed apparatus.
Based on the experimental results, generally, diesel B exhibits wider flammability range than diesel A. However, diesel A is easier to ignite than diesel B. In addition, the effect of pressure on the flammability limit of diesel B is more profound compared to diesel A.
This research can help diesel selection for specific conditions in the field. Moreover, it is suggested that, to maintain a low probability of ignition or explosion, the minimum diesel concentration of drilling fluid is 4.29% for both diesels under certain conditions.
On Hydrogen Sulfide Evolution and Scavenging within SAGD Steam Chambers
Authors: Kapadia Punitkumar R. , Wang Jacky , Gates Ian D. 
Published: June 2013

Abstract
In the Steam-Assisted Gravity Drainage (SAGD) thermal recovery process, high pressure and high temperature saturated-steam is injected into a bitumen-bearing oil sands formation. For most operations, the steam temperature ranges from about 200 to 260°C and thus under these conditions, the bitumen, in the presence of high temperature steam condensate, undergoes hydrous pyrolysis, i.e. aquathermolysis, yielding acid gases such as hydrogen sulfide and carbon dioxide. Current SAGD thermal reservoir simulation models in the literature often take into account complex spatial heterogeneity of the geology and oil composition and the physics of heat transfer, multiphase flow, gas solubility effects, and viscosity variations with temperature, however, few have taken the chemistry of SAGD into account. Here, we have added aquathermolysis reactions to thermal reservoir simulation model to understand reactive zones in the SAGD process and how the process generates acid gases via aquathermolysis. Given the requirement to constrain or handle sulfur emissions from thermal recovery processes, it is necessary to understand both the physical and chemical sides of the processes. Here, we have explored the possibility of triggering the Claus process underground for in situ scavenging of hydrogen sulfide during SAGD. The application of the research results is specifically to SAGD although the results could be extended to Cyclic Steam Stimulation as well. The results demonstrate that SAGD is not only a physical process that operates largely under gravity drainage but that it is also a chemically reactive process which generates hydrogen sulfide and carbon dioxide. The results also demonstrate that hydrogen sulfide generation reactions occur where there is sufficient heat, water, and oil and thus, the reactive zones are mainly at the edges of the steam chamber and in the liquid pool that sits above the production well. Injecting very small amount of sulfur dixode along with steam could result in initiation of Claus reaction underground resulting into conversion of hydrogen sulfide into liquid sulfur. The results of this study are significant given regulated emission limits of hydrogen sulfide from SAGD operations in Alberta, Canada, and moreover, the ability to potentially reduce emissions by altering the operating strategy or through in situ hydrogen sulfide scavengers offers an elegant way to meet these regulations.
Quantitative Laboratory Assessment Of Aquathermolysis Chemistry During Steam-assisted Recovery Of Heavy Oils And Bitumen, With A Focus On Sulfur
Authors: Montgomery Wren , Sephton Mark A. , Court Richard W. , Watson Jonathan S. , Zeng Huang , Rees Andrew 
Published: June 2013

Abstract
The production of gaseous sulfur-containing species during the steam-assisted recovery of heavy oil and bitumen presents problems owing to their toxicity, corrosion properties and odor. In order to quantitatively study aquathermolysis sulfur chemistry during the thermal (steam-assisted) recovery of heavy oils we have subjected a well-characterized and sulfur-rich bitumen core sample to 150 - 325°C and 70 - 1740 psia (0.48 - 12 MPa) conditions in the continued presence of liquid water for 24 hours. The reaction products include gases, oil flotate, oil sinkate, water-soluble products, and water- insoluble residues. All have been studied with a variety of analytical techniques, including FTIR spectroscopy, chromatographic fractionation (SARA analysis), GC-FPD and GC-MS. Moreover, these techniques have been extended to analysis of the asphaltene fractions. Results suggest that some in-situ upgrading of the oil occurs under these conditions; additionally, gaseous hydrogen sulfide is released at temperatures at and above 250 °C. Variations in the relative abundances of solubility classes and chemical fractions imply that the source of sulfur is via the thermal degradation of resins and/or asphaltenes. The experimental methods, results and quantification approach discussed herein will be useful to support the development of models for engineering design of facilities for the steam-assisted recovery of heavy oils and bitumen.