bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Technology Using Surfactant to Improve Tailings Dewatering
Authors: Wu Yongfu , Mahmoudkhani Amir , Fenderson Tom , Watson Philip , Stewart Krystle , Sanders Laura , Nair Mohan 
Published: June 2013

Abstract
There are three challenges facing scientists and engineers in mature fine tailings (MFT) treatment: fast solids/water separation, maximum water recovery, and consolidation of the final sediment. To date, polymeric flocculants have been widely used in the oil sands industry, alone or in combination with electrolyte coagulants, to the described challenges.
As a mixture of solids and liquid, tailings naturally stratify during settling according to Stokes' Law, with coarse particles concentrated at the bottom of a sediment bed and fines at the top. According to Stokes' Law, MFT viscosity is one of several factors affecting the particle settling velocity. In this paper, a new method using surfactant to reduce MFT viscosity, therefore, to accelerate tailings settling velocity and to improve tailings dewatering, will be presented. Experimental results indicate that with addition of a solid surfactant at 4,000 ppm and moderate shaking for 30 minutes, tailings viscosity was reduced from 6,300 cPs to 2,200 cPs at shear rate of 2.2 sec-1. The treated MFT sample was centrifuged at 1,000 G-force for 5 minutes. After that, the top layer can be easily poured out of the centrifuge tube. The solid content in the top layer is only 6.9%, but is as high as 80.2% in the bottom layer. In this way, the MFT was readily separated without addition of extra water.
Offshore Heavy Oil Polymer Flooding Test in JZW Area
Authors: Xiaodong Kang , Jian Zhang 
Published: June 2013

Abstract
JZW oilfield, which was considered as one of the best candidates for polymer flooding with low water salinity and temperature, is one of offshore heavy oilfields in Bohai bay. Based on a lot of the laboratory and numerical simulation studies, the polymer flooding test was initialed in 2007 while the area comprehensive water cut was 80%. By 2008, all injection wells in the area were transferred to polymer injection wells. For the effect of polymer flooding test, lots of measure adjustment was taken to optimize the injection and production structure, control the produced polymer concentration.
At present, the obvious response to increasing oil and decreasing water cut is seen in the test area, 0.18PV polymer solution has been injected in the area, and the response was seen in almost all 21 producers. The average daily oil production rate of 10 typical producers increased from 190 bbl to 310 bbl, and the average water cut decreases from 85.2% to 63.1%. It can be observed from the production history of the target block of the similar rule as the typical well which the water cut increased after polymer flooding and reached the maximum value of 80%. With the polymer injected, the water cut decreased by a maximum of about 10% to 70% while oil production rate increased by about 30%.
Now, the performance of the oilfield is basically in agreement with the results predicted by numerical simulation, expecting that the polymer flooding oil recover can be 6.2%(OOIP) higher than the water flooding. For the higher recovery, the surfactant-polymer flooding test has been run in one of the well groups of the area since last year.
Real Time Surveillance and Optimization of a Heavy Oil Field
Authors: Cramer R. , Babbar S. , Brouwer R. , Schotanus D. 
Published: June 2013

Abstract
Data driven well models were constructed for a steam injected field producing 800 m3/d of API 8 bitumen from 100+ beam pumped wells. The modelling technique is known as Production Universe(PU) which gives real time estimates of oil and water flows for each of the wells during steady state and transient operations. PU tracks rates when wells are starting-up, closing-in and for transient flow oscillations, resulting in automatic daily reports of total production and deferment (low and off) for each well.
The deferments reports drive an exception-based surveillance (EBS) process by flagging the engineers of the largest production gain opportunities. EBS analysis and associated well remedial actions have resulted in an 8% production gain. Continuous estimation of well bitumen and water flows has allowed real time optimization of the entire field. This is achieved by continuously maximizing production within the plant water handling and economic constraints. The system knows how much oil and water the wells are producing and recommends rates for each of the wells to maximize production within the water handling capability.
The EBS process has been successfully running for more than a year. The RTO process has just been introduced, hence it is too early to estimate the incremental gain.
This paper will detail the surveillance and optimization techniques, learnings and associated work processes.
A New Method for Predicting Friction Losses and Solids Deposition during the Water-Assisted Pipeline Transport of Heavy Oils and Co-Produced Sand
Authors: McKibben Melissa , Gillies Randall , Sanders Sean 
Published: June 2013

Abstract
In this paper, the results of a multi-year research project to develop reliable engineering scale-up models of water-assisted pipeline transport of heavy oils and bitumen are described. Empirical correlations currently in use do not properly account for the effects of flow rate and pipe diameter on friction losses. They account not at all for effects of water cut, temperature, oil viscosity or sand concentration. Additionally, sand accumulation in operating pipelines is a concern because no accurate method of predicting the conditions under which sand can be transported is available.
In water-assisted pipeline transport, water present in the production fluid can form a layer that separates the oil-rich core from the pipe wall, thereby drastically reducing the energy required to transport the mixture. Alternately, small amounts of water can be added to provide the lubricating effect.
A multi-year project to explore water-assisted flow regimes was sponsored by Husky Energy, Nexen Inc., Shell Canada Energy and four other heavy oil and/or oil sands producers. An extensive experimental test program was carried out in SRC's 50, 100 and 260 mm (diameter) pipeline flow loops, using oil/water/sand mixtures containing heavy oil, bitumen or a viscous lube oil. Measurements collected during the tests included the frictional pressure drop, thickness of the oil wall fouling layer and solids concentration distribution. The friction loss model developed as part of this project assumes that the flow is only partially lubricated by the water layer so that oil-oil contact at the pipe wall becomes more important as the water cut, superficial mixture velocity and/or ratio of oil-to-water viscosity decreases. The sand transport criterion developed here compares the particle terminal settling velocity to the friction velocity of the turbulent water layer.
The models developed here provide accurate predictions for the scale-up, design and operation of water-assisted pipeline flow technology, which has significant potential to reduce the costs and environmental impact associated with heavy oil pro- duction and transportation.
Achieving Production Optimization Using Progressive Cavity Pumps, Artificial Neural Networks, and System-Based Monitoring
Authors: Eggers Juan , Gomez Angel E. , Hurtado Yomalys , Claib Amin , Silva Tayruma , Nunez Gustavo J. , Borjas Jesus , Duarte Luis , Valbuena Sinaira 
Published: June 2013

Abstract
Petrocedeño is a Venezuelan joint venture (JV) between PDVSA, Total, and Statoil. Petrocedeño operates in the San Diego field of the Junín block located in the Orinoco Belt, where over 500 lifted wells currently produce over 120,000 bpd of extra- heavy oil (7-9.5 API) using progressive cavity pumps (PCPs). Petrocedeño has extensively used down-hole sensors to monitor PCP operational parameters, such as velocity, torque, vibration, intake and discharge pressure, and temperature. Timely and proper usage of this data, incorporated with other well information and operational data, improves production optimization using proactive surveillance and diagnostics of underperforming wells. In spite of having process data in hand, it was noticed that additional optimization can be obtained by integrating the data available with articulated workflows.
Initially, a pilot was conducted to evaluate technology aimed at optimizing the production of 50 wells through timely identification of underperformance occurrences. This was achieved using:
Automated data gathering and integration Automated daily production rate estimation using operational data and artificial neural networks (ANNs) Customized surveillance and diagnostic workflows
The technology applied was developed by integrating data and estimating well production rates on an hourly basis. This involved using trained ANNs and a leading production technology platform. In addition, continuous surveillance workflows of operational parameters as well as estimated rates and other production information were implemented on engineers’ computers through customized well and reservoir analysis software created during the pilot.
After the pilot project, Petrocedeño engineers were able to reduce the time to identify underperforming wells in 20%. The positive results achieved in the mentioned pilot, encouraged the company to implement the system in the whole San Diego field, as well as introducing additional production surveillance and optimization workflows and visualization tools. This paper presents some of the main workflows implemented and the results obtained.
Differential Evolution for Assisted History Matching Process: SAGD Case Study
Authors: Mirzabozorg Arash , Nghiem Long , Chen Zhangxing , Yang Chaodong 
Published: June 2013

Abstract
SAGD (Steam Assisted Gravity Drainage) is an efficient and proven technology to recover vast reserves of Alberta's oil sands. Because of its thermal and compositional effects, numerical simulation of the SAGD process requires extensive computational run time, especially in a history matching framework. Therefore, it is beneficial to use an optimization technique that yields faster convergence and better match-quality solutions.
This paper presents a new population-based optimization technique, called differential evolution, in the assisted history matching process. Differential evolution belongs to the class of evolutionary algorithms in the continuous parameter space that has been used successfully in a large range of engineering optimization problems outside the oil industry. Differential evolution converges faster than many other global optimization methods. It requires fewer control variables, is robust and easy to use, and lends itself very well to parallel computing.
We applied the differential evolution technique to a SAGD case study to history match saturation and temperature profiles as well as cumulative oil and water production and cumulative SOR. The results show that it is an excellent optimization technique for obtaining multiple good history matched models, which allow the assessment of uncertainty for the forecast stage. The match-quality of the history matched models obtained with differential evolution has been compared to the results of the particle swarm optimization method that is widely used in history matching. The comparison shows that differential evolution offers much better match-quality solutions with much lower number of simulation runs.
Modeling the Effect of Permeability Anisotropy on the Steam-Assisted Gravity Drainage (SAGD) Process in Multi-Layered Reservoirs
Authors: Azom Prince N. , Srinivasan Sanjay 
Published: June 2013

Abstract
The performance of the SAGD process is significantly impacted by permeability anisotropy both during the initial rise of the steam chamber as well as during the lateral spreading of the steam chamber. Previous models for SAGD performance take into account the effective permeability of the medium but don't explicitly account for the anisotropy. We extend our earlier development of a semi-analytical model that accounts for permeability anisotropy during the SAGD process to multi-layered reservoirs. We explicitly account for permeability anisotropy by resolving the resultant oil drainage and resultant gravity head vectors on to the principal axes of the reservoir's permeability ellipsoid. The extension to multi-layered systems recognizes that the entire reservoir may not be characterized by a single anisotropy ratio and in fact the ratio may vary from one reservoir layer to the next. We model oil recovery in such situations taking into account the unique quasi-steady state flow characteristics of the SAGD process.
Our method involves using the quasi-steady assumption to derive the appropriate SAGD slope drainage equations for both the resultant gravity head (RGH) and the resultant oil discharge (ROD) vector orientations. These vectors are later mapped to the principal anisotropy axes of the permeability field. The entire modeling is done in dimensionless space making the model suitable for use as predictive type-curves.
Our results show that just like for the single layer case, both the RGH and ROD models give different results especially at low equivalent anisotropy ratios. We also show that there is a limitanisotropy ratio beyond which the anisotropy ceases to affect the production characteristics. Moreover, our results show that static averaging techniques like arithmetic, harmonic averaging that yield effective permeability used in traditional models for the SAGD process fail to capture the effect of anisotropy on SAGD flow rates for multi-layered reservoirs. The resulting production expression can be used as a fast proxy to model the SAGD process in more complex reservoirs for the purposes of history matching and/or in a predictive modeling framework.
Modeling of Interaction Between CO2 and Rock in Core Flooding Experiments
Authors: Vilela Oliveira de Souza Alexandre , Fjelde Ingebret 
Published: June 2013

Abstract
Understanding CO2 (aq), mineral and water reactions is one of the key elements to long term CO2-storage in reservoirs. When CO2 is injected to reservoirs with water, CO2 will be dissolved in the water phase. Liege outcrop chalk and Berea outcrop sandstone have been used as analogous to chalk reservoir and sandstone reservoir rocks to study interactions between CO2 and rocks. Core flooding experiments have been conducted in these rocks at 340 bar 130°C with injection of formation water and carbonated water (CO2-saturated formation water). The flow regime used was first injection of formation water follow by injection of carbonated water and a second injection of formation water. The sampling of the produced water phase was made at two different points after the core, high pressure and temperature (340 Bar and 130°C) and low pressure and temperature (2 Bar and room temperature). The samples were analysed for elements by Inductive Coupled Plasma (ICP). After the experiments, the numerical simulations were performed at the same conditions with two different geochemical softwares PHREEQC and TOUGHREACTS, to reproduce the experimental results. Using kinetic rates of the minerals, the numerical simulations were capable to show the dissolution and precipitation of carbonates minerals and formation of secondary minerals. The simulation results give a detailed understanding of the experimental geochemical system. It is concluded that the experimental and simulation methods can be used in combination to evaluate the potential for interactions between the rock and carbonated water. The compositions of effluent samples taken at high pressure have been found to be more representative than effluent samples taken at low pressure. The accuracy in the preparation of high pressure effluent samples should be improved.
A New and Practical Workflow for Large Multi-pad SAGD Simulation - A Corner Oil Sands Case Study
Authors: Card C. C. , Kumar A. , Close J. C. , Kjosavik A. , Agustsson H. , Picone M. M. 
Published: June 2013

Abstract
Every simulation engineer wishes to simulate large full field models, but historically reservoir simulation of the SAGD process has been constrained to single well models up to a single pad. Models of these sizes provide valuable information and have helped to assess the development potential of reservoirs. These models may be used for reservoir management and to support the decision making process for the design of the initial completion, operating strategy, multi-pad wind down evaluations and also qualitatively assess the uncertainty in the SAGD forecast under different geological settings.
However, in many cases we are left with the question of how multi-well and multi-pad communications ultimately affect performance at the well pair scale. Due to technological constraints with computer hardware and simulation technology, running extremely large multi-pad models has been until recently largely impractical, especially when trying to run multiple scenarios to better understand the impact of geological and operational uncertainty.
In this paper, we present a new and practical workflow that makes running extremely large multi-pad, multi-million grid cell SAGD models a reality. The three major steps of the workflow are 1) Generating simulation friendly geomodels, 2) Use of experimental design and 3D sub-models based on SAGD Performance Index (SPI) for numerical tuning, and 3) Use of 2D cross-sections and SPI to develop dynamic grid refinement parameter values for the full 3D model. All of these steps are aimed at improving the numerical stability and run time of multi-pad SAGD simulation models.
A 24 SAGD well pair model with 2.52 million gridblocks was simulated for 10 years of forecast. The reservoir is geologically complex and highly heterogeneous. We discuss some of the important aspects that need to be accounted for when simulating large scale SAGD models. Using this new workflow, the simulation run time was reduced from 42 days to 7 days on 8 CPUs - a 6 times speedup. The resulting run time is short enough to facilitate multi-realization simultaneous runs using 8 CPUs hence maximizing the throughput and minimizing the simulation cycle time. This new workflow can be easily replicated and, more importantly, automated to reduce engineering time requirements.
Efficiency of Solvent Retrieval during Steam-Over-Solvent Injection in Fractured Reservoirs (SOS-FR) Method: Core Scale Experimentation
Authors: Mohammed M. Almojtaba , Babadagli Tayfun 
Published: June 2013

Abstract
Sole injection of steam or solvent into heterogeneous reservoirs usually yields an inefficient recovery performance. The SOS- FR (Steam-Over-Solvent Injection in Fractured Reservoirs) method was suggested as a solution to improve the efficiency of heavy-oil/bitumen recovery from fractured carbonates and oil sands reservoirs after cold production (Al-Bahlani and Babadagli 2008). The method consists of three phases: Phase (1): Steam is injected at low temperatures to heat the matrix and condition the oil for subsequent solvent injection; Phase (2): solvent injection to dilute matrix oil by diffusion and enhance gravity drainage recovery rate, and; Phase (3): low temperature (around the boiling point of solvent) steam injection to retrieve the solvent diffused into matrix.
Previously, we focused on the effectiveness of Phases (1) and (2) of the method (Al-Bahlani and Babadagli 2009a-b) and observed very positive responses at the field scale (Al-Bahlani and Babadagli 2010) with high ultimate recoveries. The efficiency of this process, however, is purely determined by the amount of solvent retrieved at the end of the process. This paper, therefore, focuses on Phase (3), which is done mainly for solvent retrieval.
About twelve static core experiments were performed on water and oil-wet sandstones. After saturating the rock samples with different heavy-oils, they were immersed into different liquid solvents—hexane, heptane, decane, and diluent oil. Once the ultimate recovery was achieved by diffusion and gravity drainage [Phase (2)], the samples were exposed to different temperature hot-water [Phase (3)] and the amount of solvent retrieved was measured through volumetric and weight measurements, as well as refractometer readings. The retrieval of solvent diffused into matrix was mainly due to two reasons: (1) Evaporation of solvent at elevated temperature, and (2) imbibition of hot-water into rock (if oil-wet samples become more water-wet during Phase (2).
The amount of solvent retrieved through these processes were determined and the efficiencies were analyzed for different parameters including rock wettability, solvent type, solvent-soaking period, different combinations of steam-solvent cycle, and temperature applied.
Bitumen Recovery by the SOS-FR (Steam-Over-Solvent Injection in Fractured Reservoirs) Method: An Experimental Study on Grosmont Carbonates
Authors: Naderi Khosrow , Babadagli Tayfun , Coskuner Gökhan 
Published: June 2013

Abstract
The recovery of 1,600,000 cp bitumen from very heterogeneous carbonate reservoirs in the Grosmont unit in Albert is a great challenge. Steam injection alone may not be efficient due to the heterogeneous nature of the reservoir caused by natural fractures at different scales. Recent cold solvent studies showed limited recovery because of low diffusion coefficient and by-passing matrix oil. The hybrid use of steam and solvent could be an option to overcome some of these challenges. We adapted the previously introduced SOS-FR (Steam-Over-Solvent Injection in Fractured Reservoirs) method and conducted twelve experiments using preserved core samples from the Grosmont formation. The temperature used can be qualified as hot water injection thereby reducing the cost of heating the reservoir.
The method applied in this study is based on soaking rather than continuous injection. The samples were immersed in hot water (90 °C) first to mimic low temperature pre-steaming to condition the reservoir for solvent injection. This was followed by a solvent soaking period under varying conditions (duration, solvent type, etc.). Heptane and the distillate obtained from a heavy oil upgrading facility were used as solvents. Finally, the core samples were soaked in hot water again. Oil recoveries varied between 40% and 90% OOIP with a mean value of 68%. Asphaltene precipitation as a percentage of OOIP was measured between 6.5wt% and 33wt%. The oil recovery and asphaltene precipitation depended on the solvent type, the solvent exposure duration, the position of matrix rock (horizontal or vertical), and the duration and number of solvent/hot water cycles. Most importantly, the last phase (hot water immersion) yielded substantial recovery of solvent diffused into matrix oil by applying a temperature value close to the boiling point of the solvent. The solvent retrieval was extremely fast and varied between 62% and 82% of the solvent diffused into the core during solvent exposure.
Experimental observations look promising for further applications as indicated by the high recovery values. The important aspects are that the solvent from readily available distillates used for transportation of heavy oil are very responsive and the temperature requirement for final hot water injection applied to retrieve solvent was less than 100 °C. Solvent retrieval was extremely quick and reasonably high which is more likely to make the process economic.