bluuebunny/crossref_metadata_2025_split huggingface dataset:
Predicting SAGD ESP Intake Temperature
Authors: Fedenczuk Leon , Graham John , Pehlke Trent , Cherniwchan Nicholas 
Published: May 2016

Abstract
This paper introduces a formula for predicting the intake temperatures of an ESP during SAGD operations, the "Lagged PVT Ratio Formula". This formula is intended to be used to automate the ESP's operation, with the goal of maintaining select well temperature and subcool targets. Target intake temperatures are determined and are currently monitored manually. If downhole temperatures reach a critical, typically water saturation temperatures, vapors can form at or in the ESP. This can cause the pump to trip or fail, leading to a costly workover being required.
To develop the Lagged PVT Ratio Formula data from eight well pads, approximately 80 SAGD well-pairs, was used. It is based on lagged non-dimensional ratios derived from select well parameters known to effect ESP intake temperatures. Formula inputs are based on the previous five readings of select variables in 10 minute intervals. Frequent readings of appropriate parameters allow for fast and accurate temperature predictions during sensitive well operating periods, and periods of stable production. Accurate temperature predictions are specifically important during the initial start-up period of the well. Verification tests showed that a single equation can be used to predict the ESP's intake temperature for SAGD well-pairs at different stages of the wells life. This formula has proven to be consistently robust and does not change when applied to similar existing well-pairs, well-pairs with different geology, and new well-pairs.
With an increasing number of producing SAGD well-pairs on site, being able to predict ESP temperatures, leading to well-pair automation, will be an economical benefit for operators. It will allow for additional SAGD well-pairs to be drilled without requiring additional production engineers to monitor and operate the wells on a daily basis.
Understanding Impacts of Lean Zones on Thermal Recovery in View of Mobile Water
Authors: Xu Jinze , Pan Yi , Chen Zhangxin 
Published: May 2016

Abstract
Lean zones have been reported in Nexen's Long Lake project and Suncor's Firebag project in Canada. With high steam-oil ratio and low oil recovery caused by lean zones, developing a heterogeneous oil sand reservoir is a considerable challenge. To study the mechanism of how lean zones affect thermal recovery performance, the role of the huge volume of mobile water cannot be neglected. In this paper, we propose a new mass transfer model for the thermal recovery process in oil sands with mobile water. Further discussions based on the model showed the following conclusions: (1) Reservoir regions during thermal recovery are divided into four regions based on initial water saturation. An increase in the initial water saturation may cause the oil bank to disappear. (2) The initial mobile water saturation significantly reduces the width of the two-phase flow region once it is larger than the frontal water saturation of this region. (3) High water saturation leads to a long breakthrough time in a hot driving region and low oil recovery. (4) Large connate water saturation and porosity and small heated oil viscosity benefit the oil recovery before the breakthrough of the steam chamber.
A Proxy Model for Predicting SAGD Production from Reservoirs Containing Shale Barriers
Authors: Zheng Jingwen , Leung Juliana Y. , Sawatzky Ronald P. , Alvarez Jose M. 
Published: May 2016

Abstract
An approach based on artificial intelligence (AI) tools is being used to explore the influence of shale heterogeneities on SAGD production. In this project, the production data is derived from a set of synthetic SAGD reservoir simulations based on petrophysical properties and operational constraints representative of Athabasca oil sands reservoirs.
The underlying reservoir simulation model is homogeneous, and two-dimensional. Its petrophysical properties, such as the porosity, permeability, initial oil saturation and net pay thickness, have been taken from average values for several pads in Suncor's Firebag project. Superimposed on this homogeneous reservoir model are sets of idealized shale barrier configurations. The permeability of each shale barrier is several orders of magnitude smaller than the permeability of the oil sand in the simulation model. The individual shale barriers are categorized by their location relative to the SAGD well pair (vertical and lateral), and by their geometry (thickness and lateral extent).
SAGD production was simulated with the reservoir model for a training set of shale barrier configurations. The training set was chosen to try to span the space of possible shale barrier configurations in the reservoir model; the elements of the set were identified by means of experimental design. A network model based on AI tools was constructed to match the output of the reservoir simulation model for this training set of shale barrier configurations, with a focus on the production rate and the steam-oil ratio (SOR). Then the trained AI proxy model was used to predict SAGD production profiles for scenarios where the shale barriers were distributed stochastically. The results of these predictions were compared with the results of the SAGD simulation model with the same shale barrier configurations. The match to production rate and SOR was good, better than expected.
The results of this work demonstrate the capability and flexibility of the AI-based network model, and of the parameterization technique for representing the characteristics of the shale barriers, in capturing the effects of complex heterogeneities on SAGD production. The approach could be extended to study the effects of other heterogeneous features such as lean zones on SAGD production. It offers the significant potential of providing an indirect method for inferring the presence and distribution of heterogeneous reservoir features from the profiles of SAGD field production data.
In-Situ Combustion Experience in Heavy Oil Carbonate
Authors: Ismail Norasyikin B. , Klock Kristina A. , Hascakir Berna 
Published: May 2016

Abstract
In-situ Combustion (ISC) has the potential to be the most effective enhanced oil recovery (EOR) method for heavy oil recovery. However, it is considered a high risk failure rate process since it is hard to predict the combustion reactions between complex crude oil and heterogeneous rock matrices. If the reservoir rock is reactive, like carbonates, the risk factor of ISC increases. This research studies the ISC performance for different rock matrices found in Alberta, Canada.
The reaction kinetics analyses were carried out by Thermogravimetric Analysis/Differential Scanning Calorimetry (TGA/DSC) on bulk oil, and its Saturates, Aromatics, Resins, and Asphaltenes (SARA) fractions at a constant heating rate (20°C/min). To better understand the combustion behavior of bulk oil, pseudo blends of SARA fractions were prepared and systematic TGA/DSC tests were run on these blends. Furthermore, the impact of reactive porous media on fuel formation mechanism was investigated by using clays and carbonates. The reaction kinetic analyses on bulk oil and SARA fractions suggest that asphaltenes, resins, and aromatics fractions go into endothermic reactions at elevated temperatures, still the asphaltenes fraction generates the greatest amount of heat. The two-component interaction of asphaltenes with other fractions produces less heat than the combustion of asphaltenes alone. The three- component pseudo blend prepared by mixing asphaltenes-resins-aromatics produced the highest amount of heat and we believe that in bulk oil combustion saturates by acting as an ignitor provides the necessary heat to initiate the reactions among aromatics, resins, and asphaltenes fractions. Moreover, the effect of reactive porous media on reaction kinetics of bulk oil were investigated at a constant heating rate (20°C/min). Carbonates and clays were used. Since the clays act like a catalyst, heat generation was observed lower with clays than carbonates and carbonates required more heat for successful combustion.
While the heating rates during in-situ combustion are generated naturally, in TGA/DSC tests, a constant heating rate is applied. In this study, we used 20°C/min as the heating rate. If the same heating rate during ISC cannot be reached, then, the heat generation cannot be as high as reported in this manuscript. Thus, it is important to extend the systematic TGA/DSC analyses presented in this paper. Tests should be conducted at varying heating rates on different oil samples and on their SARA fractions.
Produced Gas Reinjection Based Cyclic Solvent Processes for Foamy Oil Reservoirs in the Eastern Orinoco Belt, Venezuela
Authors: Li Xingmin , Yin Yin , Yang Zhaopeng , Shen Yang , Liu Zhangcong 
Published: May 2016

Abstract
Solution gas drive from heavy oil reservoirs in the eastern Orinoco Belt, Venezuela presents foamy oil behavior and has shown a primary recovery factor of 8-12%. However, the cold production performance will get worse continuously during such a pressure depletion process, and steam injection sometimes is not an economically attractive follow-up candidate for improving the oil recovery further especially at the low oil price condition. Therefore, produced gas re-injection based processes in huff and puff mode, i.e., hydrocarbon-based cyclic solvent processes (CSP and ECSP) have been tested to evaluate their applicability to such reservoirs.
In this study, the oil sample used in the test is taken from Block M, Eastern Orinoco Belt. The viscosity and the API gravity of the stock tank oil of Block M are 14,488cp (at 54 °C) and 7.8 respectively. The produced reservoir gas is mainly a mixture of methane and CO2 (87:13 in molar ratio). Firstly, the heavy oil swelling test and unconventional PVT test are conducted. And then the behavior of primary depletion process and produced gas huff and puff (CSP) is investigated by conducting a series of sandpack tests. In addition, to further improve the performance of the produced gas CSP, three different enhanced cyclic solvent processes (ECSP), including produced gas and propane, produced gas and foaming agent, and produced gas plus oil viscosity reducer ECSP are tested.
The 3-cycle produced gas CSP test result shows that it can improve the oil recovery by 8.7% compared to primary depletion when the first CSP cycle is initiated at a certain pressure between the bubble point pressure and the pseudo bubble point pressure. The CSP process illustrates obvious restoration of the foamy oil drive mechanism which provides primary production, or so called secondary foamy oil drive mechanism. Above three different ECSP processes all improve the CSP performance with different degrees. The produced gas and propane ECSP (70% produced gas +30% propane), with produced gas slug injected before propane slug during each injection process, improves the oil recovery by 23.6% through three cycles compared to cold production due to viscosity reduction and solvent-gas-drive mechanisms. For 3-cycle produced gas and foaming agent ECSP, and produced gas plus oil viscosity reducer ECSP, the increased oil recovery are 15.5% and 11.2% separately.
Compositional Mechanisms in SAGD and ES-SAGD With Consideration of Water Solubility in Oil
Authors: Venkatramani Arun Venkat , Okuno Ryosuke 
Published: May 2016

Abstract
Experimental data have shown that the solubility of water in the oleic (L) phase (xwL) can be significant at elevated temperatures. However, xwL was not properly considered in prior studies of SAGD and ES-SAGD. The main objective of this research is to present a detailed study of compositional mechanisms in SAGD and ES-SAGD simulation by considering xwL. The importance of properly considering xwL is shown in economic evaluation of these bitumen-recovery processes.
The phase-behavior models used in this research are carefully created on the basis of experimental studies presented in the literature. Mechanistic simulation studies are then conducted for SAGD and ES-SAGD. Co-injectants used in ES-SAGD simulations range from propane through n-decane.
Results show that xwL enhances bitumen production in both SAGD and ES-SAGD mainly because xwL results in reduction of L-phase viscosity. The enhancement is more significant when the chamber-edge temperature is higher, because xwL increases with temperature. The enhancement of bitumen production observed in the case studies is 7.66% for SAGD, 4.08% for C6-SAGD, and 4.85% for C8-SAGD for a fixed period of operation at 35 bars. It is important to consider xwL in SAGD and ES-SAGD simulations, because the relative performance of ES-SAGD to SAGD tends to be overestimated without considering xwL.
On the basis of a sensitivity analysis for economic performance of ES-SAGD, a guideline is presented to leverage xwL to improve bitumen production in ES-SAGD. As discussed in our prior research, solvent becomes effective in diluting bitumen and reducing steam requirement, only when it sufficiently accumulates near the chamber edge. New results show that water can act as a diluting agent until solvent sufficiently accumulates near the chamber edge.
Steam-Air Injection Process
Authors: Chang Jeannine , Ivory John 
Published: May 2016

Abstract
This paper summarizes the results of reservoir simulations performed to investigate steam-air injection and its potential as a thermal recovery process. The steam-air injection process is considered to be any process that involves both steam and air injection whether they are injected together or at different times. The objective of the simulations was to develop steam-air injection based on its ability to divert steam from more to less oil depleted regions thereby improving reservoir contact (conformance) and increasing oil production. This diversion is caused by the deposition of coke and/or asphaltene in depleted regions or high permeability channels or thief zones. It primarily results from low temperature oxidation (LTO) of the oil. Air injection is most effective when used to divert injected steam when significant channeling/over-riding is occurring prior to air injection.
Air should be injected at a relatively low rate and temperature in order that coke/asphaltene deposition occurs and facilitates steam diversion. Simulations showed that in a field application of the steam-air injection process, it is important to stop injecting air with/without steam once diversion has been obtained. Otherwise, oil will unnecessarily be consumed or degraded by LTO reactions and steam diversion may be reduced due to consumption of deposited coke/asphaltenes by high temperature oxidation (HTO) reactions. Continued injection of air could even increase channeling as it removes the coke and any residual oil by oxidation reactions thereby reducing the flow resistance in channels/thief zones. Air injection in a steam process is complex and it is not simply a case of injecting air with steam without careful consideration of the process.
In-Situ Reflux: An Improved In-Situ Recovery Method for Oil Sands
Authors: Harding Thomas G. , Zanon Stefan , Imran Muhammad , Kerr Richard K. 
Published: May 2016

Abstract
The steam-assisted gravity drainage (SAGD) process is the only commercially proven in-situ recovery method for Athabasca oil sands but it is challenged by high capital and operating costs and project economics are very sensitive to oil price fluctuations. The SAGD process also uses large quantities of water and produces significant greenhouse gas emissions during steam generation. It has become important to develop lower cost and more environmentally sustainable in-situ recovery technology for Athabasca oil sands.
In-situ reflux (ISR) is a new and lower cost alternative to SAGD that uses long electrical resistance heaters in horizontal wells to vaporize connate water to produce a rising steam chamber above the heater well. In ISR a relatively small amount of water or solvent may be injected to enhance heat transfer into the formation and assist in reducing bitumen viscosity. Steam condensate formed by the cooling of steam migrates downward along with heated bitumen but as these fluids approach the heater well and production conduit, the water is re-vaporized or refluxed while the oil continues its downward travel and is produced. SAGD-like horizontal well pairs are contemplated for ISR although it may be possible to operate single wells. Capital costs for ISR are much reduced compared to SAGD since there are no steam generators, only a small water treatment plant is needed and the required capacity of the production separation train is significantly reduced. Operating costs for ISR are also reduced compared to SAGD through elimination of surface and wellbore heat losses during energy transmission to the producing formation. Greater energy efficiency in ISR leads to lower carbon dioxide production and water requirements compared to SAGD. This paper presents a description of the ISR process, a comparison of the SAGD and ISR processes and the steps taken to assess the viability of ISR. The many possible applications of the ISR recovery process are also discussed.
An Experimental Investigation of the Effect of pH and Salinity on Sand Control Performance for Heavy Oil Thermal Production
Authors: Mahmoudi Mahdi , Fattahpour Vahidoddin , Nouri Alireza , Leitch Michael 
Published: May 2016

Abstract
In this paper, we present the results of an experimental investigation on the effect of pH and salinity on slotted liner performance in terms of sanding and retained permeability for heavy oil thermal production. This work is an advancement of the existing knowledge in the literature which indicates that pH and salinity could highly affect the mobilization, flocculation and deflocculating of clays (mainly Illite and Kaolinite) in oil sands formations.
Water with different pH, in the range of 6.8 to 8.8, and salinities, in the range of 0 to 1.4 % was injected into sand pack samples supported with multi-slot coupon in a Sand Retention Testing (SRT) facility. Measurements included pressure drops along the sand pack and across the slotted liner coupon as well as the produced sand/fines for different flow rates. These measurements were used to assess the effect of the pH and salinity on fines migration within the sand pack, capability of the slotted liner to produce the fines, pore and slot plugging, sand production and the retained permeability.
We observed that the pressure drops, fines production and the retained permeability are highly dependent on the pH and salinity of the injected fluid. In low pH and high salinity environment, clay is not mobilized resulting in low pressure drops and high retained permeabilities. On the other hand, an increase in pH value or a decrease in salinity leads to significant clay mobilization and a remarkable reduction in retained permeability.
This paper provides a thorough experimental investigation of the pH and salinity effect on slotted liner performance. The effect of the pH and salinity is usually ignored in screen control testing while it could highly control the clay mobilization and retained permeability. Results of this study could trigger wide reconsideration in sand control approaches particularly by altering the pH in the near wellbore zone.
Optimum Time of ACP Injection for Heavy Oil Recovery
Authors: Aitkulov Almas , Lu Jun , Pope Gary , Mohanty Kishore K. 
Published: May 2016

Abstract
Alkaline-cosolvent-polymer (ACP) flooding of a heavy acidic oil (320 cp) was studied in a two-dimensional (2D) sand pack. An ACP formulation was developed by studying the phase behavior of the oil with several alkaline-cosolvent formulations. The effectiveness of the ACP formulation was validated in a 1D sand pack by conducting a waterflood followed by a stable ACP flood. Sand was then packed into a 2D square steel cell equivalent to a quarter five-spot pattern. Several ACP floods were then conducted in this 2D cell to study both the displacement and sweep efficiency of ACP floods. First, the polymer concentration in the ACP formulation was varied to find an optimum ACP slug viscosity where the oil recovery and pressure gradients are acceptable. When the ACP slug viscosity was about 1/4 of the oil viscosity, oil recovery was 76% OOIP; we adopted this viscosity as the optimum viscosity. Then, using this ACP slug viscosity, the waterflood extent, after which the ACP flood was initiated, was varied (0-1 pore volume). The oil recovery, oil cut, effluent concentration and pressure drop were monitored during the floods. The timing of the tertiary flood did not change the tertiary oil recovery very much. However, shorter the waterflood, faster was the oil recovery under the constant injection rate constraint. Sweep efficiency during secondary ACP flood was lower than that in the tertiary ACP injection. Gravity effect on sweep was significant under ultralow IFT.
Unconventional Production Forecast Needs Integration of Field Hydraulic Stimulation Data Through Fracture Model Calibration and Optimized Numerical Scheme
Authors: Delorme M.. , Bossie-Codreanu D.. , Ben-Gharbia I.. , Khebzegga O.. , Khebzegga N.. , Ricois O. M. 
Published: May 2016

Abstract

Objectives/Scope
Hydraulic fracturing is today a standard when developing unconventional reservoir plays. This is studied through different models, based on a great deal of characterization data gathering and analysis. Unfortunately, numerical limitations impose drastic simplifications (number of fractures, some data being ignored…) leading to simple fracture geometries, lacking observed complexity. This limits any design optimization expectation. Our objective is to show that calibration data used for simpler models, along microseismic measurements, can lead to more realistic hydraulic fracturing geometries. Results can be linked to a reservoir platform, forecasting production. The presented computationally efficient method, within which sensitivity is performed, highlights key parameters governing the stimulation process. This study shows that the tool used is tailored for practical scenario design and evaluation.

Methods, Procedures, Process
The method used to generate realistic fracture geometries implies information at all scales (seismic, log, cores…) as well as numerical tools able to handle geomechanics and fluid flow, over a great number of fractures (as required by the characterization). Thus all data is input into one 3D Representative Deformable Discrete Fracture Network (DDFN), simulating the hydraulic stimulation. Characterization is based on geostatistical concepts applied to both natural and hydraulically induced fractures, driven by geological and geomechanical data. The process is simulated using a one phase hydrodynamic model within the DDFN (specific discretization) under far stress conditions. Fractures behavior is governed by geomechanical laws, reversible and non-reversible, with an approximate proppant model. Various scenarios are tested according to either geomechanical uncertain parameters, or characterization ones. Observed in-situ Bottom Hole Pressure (BHP) and microseismic characteristics (shape, frequency…) are then history-matched.

Results, Observations, Conclusions
For each simulated scenario, quality of the history match is shown and discussed, stressing the representativity of the data involved.
The method has shown to be computationally efficient and robust enough to support hundred thousands of fractures while at the same time being able to simulate simpler cases. Also, within the studied framework, ties with already existing reservoir platform are shown. Advantages of such an approach are highlighted including current limitations of classical reservoir models.

Novel/Additive Information
This work undergone at different scales demonstrate the new possibilities of computational robust algorithms, within an approach considering both geological settings and geomechanical properties. The model offers the possibility to integrate several scales to an adaptive discretization scheme.