bluuebunny/crossref_metadata_2025 huggingface dataset:
Impact of Thermal Pore Pressure on the Caprock Integrity during the SAGD Operation
Authors: Yang B. , Xu B. , Yuan Y.
Published: June 2013

Thermal stimulations of reservoirs cause significant amount of thermal energy stored subsurface and pore pressure altered from its original in-situ state. Such thermal and hydraulic disturbances inevitably stress and deform the rock formations including the reservoir and its overlying caprock, making the caprock integrity an important issue. This paper discusses the importance of thermally induced pore pressure for caprock integrity during a SAGD process. Relevant laboratory and field observations are presented to demonstrate its real existence, and then, numerical simulations are used to illustrate the major influencing material parameters and their evolving importance in space and time with respect to the steam chamber development. Finally, discussions are given about importance of the thermal pore pressure on the caprock integrity.
Enhance Heavy Oil Production of Horizontal Well by Distributed Downhole Electrical Heating
Authors: Zhong L. , Lin H. , Wang Y. , Lu F. , Chen Y. , Lin J. , Zhang Y. , Fan Hongyan , Jiang Cheng
Published: June 2013

Horizontal wells are widely drilled to produce heavy oil for its large reservoir contact, and the length of horizontal well usually ranges from 100m to longer than 1000m. Up to now, limited attention are attached to flow in the wellbore and vicinity of horizontal well and its influence on production performance. In fact, the influence of flow resistance in wellbore and vicinity of horizontal well on heavy oil production should not be ignored for cold production, and even thermal processes such as CSS.

In order to investigate the flow in wellbore and vicinity of horizontal well, rheological characteristic of heavy oil and water mixture are measured at different temperature and water cut, and flow in the wellbore and vicinity of horizontal well and according oil production improvement by distributed electrical heating are investigated primarily based on experimental simulation and reservoir numerical simulation. The rheological measurement results show that more than 50% - 90% reduction in viscosity of heavy oil and water mixture could be obtained as temperature increasing from inflection point temperature (80 - 90℃) to 120℃. Up to 2 - 7 times of fluid production index could be obtained by distributed electrical heating in pipe flow experiment. Both sand paced model experiment and numerical simulation indicate that oil production by distributed electrical heating is 1.5 - 4 times than that of cold production, and oil production by combination of CSS and electrical heating in production period is 1.2 - 2.0 times than CSS. In order to improve heavy oil production in cyclic steam stimulation process, a 1400m long, distributed electrical heater packed in coiled tubing is developed using stainless steel jacked mineral insulation cables. It is successfully installed and soundly operated in a horizontal well in Liaohe Oilfield. As result, about 30% - 50% increase in average oil production rate is obtained by distributed electrical heating, the production period is evidently extended, and approximately 10℃- 20℃increase in wellhead temperature obtained.

It is potential to improve heavy or waxy oil production in horizontal well by distributed electrical heating both in cold production and thermal production such as CCS. Furthermore, such coiled tubing packed heater could be used to heat the injected steam to increased the steam quality and temperature, or serves as igniter for in-situ combustion. Additionally, it offers a new way to develop downhole steam generator.
Understanding the Steam Hammer Mechanism in Steam-Assisted Gravity Drainage (SAGD) Wells
Authors: Irani Mazda , Zeleke Patou
Published: June 2013

Steam-assisted gravity drainage (SAGD) is one of the successful thermal recovery techniques applied in Albertan oil sands reservoirs. When considering in situ production from bitumen reservoirs, viscosity reduction is necessary to mobilize bitumen thereby flowing toward production well. Steam injection is currently the most effective thermal recovery method. While steam flooding is commercially viable, condensation-induced water hammer (CIWH) resulting from rapid steam pocket condensation can be a challenging operational problem. In steam flooding, steam is injected through a well down to the reservoir, warming it to temperatures of 150ºC to 270ºC (302ºF to 518ºF) in order to liquefy the bitumen inside the reservoir (Garnier et al., 2008; Xie and Zahacy, 2011). The liquified bitumen then drains to a lower well through which it is produced to the surface. In this process, steam pockets can become entrapped in subcooled condensate inside either the injection or production tubing causing a rapid collapse of the steam pocket. This type of rapid condesation is commonly referred to as "steam hammer".

In this study three different scenarios are explored to better understand steam hammer situations in SAGD wells. These scenarios are: (1) at injectors or producers during the start-up phase (or circulation phase), (2) in the injection tubing during the injection phase, and (3) in the production tubing during the injection phase. Modelling each of these scenarios indicates that steam hammer occurrence is likely in two of the three scenarios but that its incidence can be mitigated. The likely scenarios for steam hammer occurrence are in either the injection or production tubing during the start-up phase, and the injection tubing during the injection phase. Steam hammer occurrences during the circulation period can be controlled by lowering the injection pressure and controlling water drainage into the reservoir. Flow shocks that occur as a result of Counter-Current Flow Limiting (CCFL) are very likely to take place in the injection tubing during the injection phase but can be controlled by injecting at a higher steam quality. The least likely scenario for steam hammer occurrence is in the production tubing during the injection phase. This is because the produced (or breakthrough) steam temperature would need to be more than 20ºC higher than the produced liquid temperature to initiate a water hammer condition.
Modelling Fluid Flow in Grosmont C Carbonates Using Fractals - A Concept
Authors: Yuan Jian-Yang , Russel-Houston Jen , Nugent Daniel
Published: June 2013

Bitumen saturated carbonates of the Grosmont C member of the Grosmont Formation in the Saleski area are intensely fractured. The fractures connect the vuggy porosity and are the reason for in situ permeabilities that exceed 10 D. These carbonate rocks are more hydrophobic with high bitumen saturations. Most existing pilot data suggest the reservoir is in general "leaky" in comparison with siliclastics, such as the McMurray or Clearwater Formations. Furthermore, it is also observed that during CSS operations, especially in the earlier cycles, oil cuts are initially high and decrease with time. This character differs from CSS in siliclastics where initial oil cuts are low and increase with time. To fully understand these observed phenomena, we believe that common knowledge gained in studying siliclastics may not be enough. Geological studies have indicated that the Grosmont carbonate fracture system may not be a well-defined dual scale fracture-matrix system. It may be better defined with a multiple scale system. Geological models using the concept of fractals having self- similarity and fractional dimension have been proposed by Wagner et al.. In this presentation, we further postulate that the fractal nature of the Grosmont carbonates offers explanations to the above-mentioned observations. Using the published data of pilot tests in Grosmont, we demonstrate that it is possible to attribute "the loss of pressure" to very large total contact areas between fractures/vugs and the rock matrix in a fractal system, although the matrix permeability can be very low. The high oil cuts were interpreted as the result of considering high permeability channels with significant volume. Numerical simulations confirmed these assertions. This fractal point of view sheds some lights on our journey of eventually understanding and mastering the fluid flow behaviours in Grosmont carbonates.
Effective Dehydration of Canadian Heavy Crude Oil and DilBit
Authors: Sellman Erik , Murtagh Terry , Manuel Ben
Published: June 2013

Heavy crude oils and diluted Bitumen (DilBit) continue to be a challenge to dehydrate for the Oil & Gas Industry. These challenges include reduced crude oil / formation water density difference, higher crude oil viscosity and often smaller water droplets due the production techniques used for heavy crude oil production.

Other challenges include higher crude oil conductivity and increased crude oil emulsion viscosity formed by higher water cuts and increased solids content in the crude oil. Typically crude oil dehydration vessels use heat, retention time and AC type electrostatic dehydration technology. The AC technology produces limited voltage gradients and is not efficient for treating conductive crude oils, leading to the use of very large vessels and power units.

The traditional remedy to the above challenges often leads to high operating temperatures, high dosage of demulsifier chemicals, equipment fouling, production upsets and use of very large treaters. This leads to both higher operating expenditure (OPEX) as well as higher capital expenditure (CAPEX).

The use of combined AC / DC electrostatic technologies provides high bulk water removal efficiency in the weaker AC field combined with higher removal efficiency of small water droplets in the stronger DC field. Further improvements include amplitude modulated electrostatic fields, high frequency AC fields, improved electrode configurations as well as improved fluid distribution inside the electrostatic treaters.

More efficient dehydration and desalting processes provide potential for operating the treaters and desalters at lower operating temperatures and reduced dosage of demulsifier chemicals, in addition to the potential for using smaller treaters.

This paper describes improved crude oil dehydration using advanced electrostatic dehydration technologies and an efficient test method for optimized use of production chemicals, including case studies.
A New Solvent to Extract Bitumen from Oil Sands
Authors: Wang Guanqun , Nasr-El-Din Hisham A. , Petcavich Robert , Estrada Roy T.
Published: June 2013

A new environmentally friendly aqueous solution was developed to enhance recovery of bitumen from oil sands. The new solvent is water-based fluid with surfactants as the main component. The solvent can reduce the interfacial tension and change the wettability of the rock surface, which improves the efficiency and production of heavy oil recovery.

Extraction tests were conducted to evaluate the performance of the solution by soaking the oil sands with the solvent at different temperatures and times. Meanwhile, the composition of the new solvent was continuously adjusted to enhance recovery. Then, coreflood tests were conducted to evaluate the new solvent on recovery of heavy crude oil from Canada. Berea sandstone cores, with an initial permeability of 60 md, were used to conduct the coreflood tests. The cores were 6-inch length and 1.5-inch diameter. When the cores were fully saturated with heavy oil, the whole setup was placed in the oven at the designated temperature and heated for 24 hours to reach equilibrium. Then the cores were flushed with various fluids at a flow rate of 5 cm3/min. Core effluent samples were collected and the amount of crude oil was determined through the extraction method.

For the bitumen extraction tests, the first generation of the new solvent can only extract about 80% of the total bitumen at 70°C after 5 minutes soaking. About 90% of recovery was achieved at 90°C with the same solvent. The final generation of the solvent could extract 99% of the total bitumen at 70°C. For the coreflood tests, the new solvent recovered almost 90% of the heavy oil at 90°C and nearly 95% at 170°C. Meanwhile, the recovery factor was only 75% by flushing with 5 wt% KCl at 90°C.

This paper will summarize the results obtained and address the methodology of using the new solvent in the field.
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

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

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

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

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

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

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

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

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

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

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

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.
Integrating Reservoir Simulator and Model Predictive Control Software for Automating SAGD Well Pair Operations
Authors: Patel Kalpesh , Aske Elvira Marie , Fredriksen Morten
Published: June 2013

Model predictive control (MPC) technology has been successfully used in many midstream and downstream processes to control and optimize processes, production and overcome operating challenges. In spite of this, there are no documented applications of MPC on upstream heavy oil extraction processes, such as steam-assisted gravity drainage (SAGD). MPC can be used in SAGD process to stabilize well pair operating variables and thus help optimize production.

As a first step in the initiative of implementing MPC technology to control SAGD process, we investigate the feasibility of controlling the SAGD process with MPC by integrating the process control software with a reservoir simulator consisting of a single SAGD well pair. For this purpose we ran a computer-based model using commercial reservoir simulator software coupled with proprietary MPC software. This allowed us to run different control configurations along with different reservoir models to investigate the effectiveness of MPC technology.

The paper discusses the simulation setup and results of a typical simulation run indicating that MPC technology can be used to stabilize important SAGD process variables, such as subcool and steam chamber pressure. In addition, this method can help optimize production by enabling maintenance of these process variables at their optimum.

The success of this investigation also demonstrates the ability to connect commercial reservoir simulator software with other computer programs opening up the possibility to test a wide range of algorithms for SAGD process control and optimization.
The Effect of Solvents on the Viscosity of an Alberta Bitumen at In Situ Thermal Process Conditions
Authors: Motahhari H. , Schoeggl F. F. , Satyro M. A. , Yarranton H. W.
Published: June 2013

The design and optimization of solvent assisted thermal recovery processes for heavy oil and bitumen require accurate predictions of viscosity as a function of temperature, pressure, and composition. In this case study, the performance of the Expanded Fluid (EF) viscosity model is tested on viscosity data for an Alberta bitumen diluted with carbon dioxide (5.2 wt%), ethane (5.1 wt%), propane (7.6 and 16 wt%), n-butane (14.5 wt%), n-pentane (15 and 30 wt%) and n-heptane (15 and 30 wt%) at temperatures from 20 to 175°C and pressures up to 10 MPa. The main input to the EF model is the density of the fluid and densities were measured at the same conditions as the viscosity measurements.

The viscosity of the bitumen was fitted with average absolute relative deviation (AARD) of 8%. The viscosities of the diluted bitumen mixtures were predicted without tuning with an overall AARD of 17% when using measured densities as an input. The viscosity predictions were improved to an AARD of 7% using generalized viscosity binary interaction parameters. When using densities calculated with an excess volume based mixing rule, the viscosity predictions were slightly more deviated with an overall AARD of 10%.

The EF model predictions were used to evaluate the effectiveness of n-alkane solvents in reducing bitumen viscosity at in situ steam-solvent process conditions. The solubility of the solvent in bitumen was found to be the main factor controlling the mixture viscosity. The less volatile the solvent is, the greater is the viscosity reduction at a given pressure and temperature. As the process temperature increases, the greater is the viscosity reduction from a given solvent due to increased solubility at higher steam saturation pressures.
A Practical Approach to History-matching Large, Multi-well SAGD Simulation Models: A MacKay River Case Study
Authors: Liu Frank , Wang Jin , Morris Paul
Published: June 2013

History-matching is commonly used to calibrate numerical simulation models to validate geological and reservoir engineering inputs and ensure the reliability of model predictions. While history-matching can yield a powerful forecasting tool, thermal SAGD history-matching presents a host of challenges, particularly in terms of computational time and numerical tuning difficulties associated with large thermal simulation models. Typically, single well or small multi-well models are developed and calibrated to generate meaningful production forecasts. However, these predictions are only valid prior to steam chamber coalescence and the models are insufficient for life-of-well forecasting. Hence, it is necessary to build and calibrate large multi-well simulation models within a reasonable timeframe.

The oldest SAGD wells at Suncor's Mackay River (MR) property are part of the initial Phase 1 development. This phase consists of 25 well pairs that commenced steam injection in September 2002. This paper presents a calibration process for Phase 1 simulation model, generated through Suncor's geostatistical modeling process, incorporates more than 9 years of production history and contains approximately 1.4 million active cells. The process described has several components: 1) rigorous data quality control, 2) establishing appropriate boundary conditions, 3) numerical tuning, and 4) a focus on global rather than detailed local changes.

Using the process described herein, a Phase 1 history match was achieved which honours actual field rate and pressure history. The history match results are presented on well/pattern/phase basis. This process has subsequently been applied to MR Phase 2 and 3 with significant efficiency improvements.

A process is presented that addresses many of the issues that arise in validating and history-matching large, complex simulation models. It is shown that history-matching multi-wells SAGD performance with a long operation history is feasible, practical, and useful. The calibrated modeling processes gives confidence in understanding the reservoir and reduces the uncertainty of future forecasting results.
Optimization of a Vertical-Horizontal Heavy Oil Thermal Operation by using Automated Field-scale Control
Authors: Bao Yu , Wang Jingyi (Jacky) , Gates Ian D.
Published: June 2013

Given its water consumption and greenhouse gas emissions to the atmosphere, it is critical to optimize the steam injection strategy and steam conformance in steam-based oil sands recovery processes such as cyclic steam stimulation and steam- assisted gravity drainage to minimize the steam-to-oil ratio and maximize the cumulative oil volume produced. Given the heterogeneity of oil sands reservoirs, robust adaptive oil sands processes which respond to the system to continuously shift the operation towards desired operational objectives are desired. This kind of adaptive control can be achieved by proportional-integral-derivative (PID) control. PID automated control is a relatively simple method to control well operations in thermal processes by using observed data already measured in existing steam-based recovery processes. Here, a vertical-horizontal hybrid well configuration within an oil sands reservoir, with reservoir properties previously tuned by a history-match to field data, is operated under PID control to demonstrate that automated control can yield improvements of recovery process performance. Here, the well configuration consists of multiple vertical injectors and a few horizontal producers – early in the process, cyclic steam stimulation is initially done in the vertical wells to establish thermal communication within the reservoir. After sufficient communication is accomplished, the steam is injected into the vertical wells and fluids are produced through the horizontal wells in a steam-assisted gravity drainage mode. Automated control must accomplish thermal communication between the vertical and horizontal wells and thereafter the steam must be controlled to minimize the steam-to-oil ratio and maximize the oil rate. The results demonstrate that PID control can be used to improve the cSOR and volume of oil produced.
Physics-Based Proxy for Vapex Process Modeling in Heterogeneous Reservoirs
Authors: Shi Jindong , Leung Juliana Y.
Published: June 2013

Vapex (vapor extraction) is a non-thermal process that has significant potential in providing a more environmentally-friendly and energy-efficient alternative to steam injection. Vaporized solvent injected in-situ dissolves into the oil and reduces oil viscosity, allowing the oil to flow to a horizontal production well via gravitational forces. While compositional simulators are available for assessing the Vapex performance, the simulation process may become difficult when taking into account the uncertainty due to reservoir heterogeneity.

A physics-based proxy is proposed to model the process, in a way analogous to the SAGD model described by Butler, who demonstrated the similarity between two processes with a series of Hele-Shaw experiments and derived an analytical steady-state flow rate relationship that is comparable to the SAGD case. Solvent concentration and intrinsic diffusivity are introduced in this model instead of temperature and thermal diffusivity in SAGD. In this paper, analytical solutions and implementation details for the Vapex proxy is presented. The proposed approach is then applied to various reservoirs discretized with spatially varying rock porosity and permeability values; bitumen drainage rate and solvent penetration are calculated sequentially at grid blocks along the solvent-bitumen interface over incremental time steps. Results from this model are compared against experimental data available in the literature as well as detailed compositional simulation studies. Computational requirement of the proxy in comparison to numerical simulations is also emphasized.

An important contribution from this work is that process physics are built directly into this proxy, giving it an advantage over other data-driven modeling approaches (e.g. regression). It can be used as an efficient alternative to expensive detailed flow simulations. It presents an important potential for assessing the uncertainty due to multi-scale heterogeneity on effective mass transfer and the resulting recovery performance, as well as assisting decisions-making for future pilot and field development.
Analysis of Impact of Thermal and Permeability Heterogeneity on SAGD Performance Using a Semi-Analytical Approach
Authors: Hampton Travis , Kumar Dhananjay , Azom Prince , Srinivasan Sanjay
Published: June 2013

Due to the presence of heterogenic shale lenses within oil sands, engineers implementing the SAGD process are often forced to run time-consuming computer simulations before developing even a basic idea of reservoir feasibility. Therefore, there is a need for a robust analytical expression for the oil rate that can be quickly used to assess the sensitivity of the performance of a SAGD well pair to various combinations of reservoir and fluid parameters. This paper will shed some additional insights into the effect of both thermal conductivity and permeability heterogeneity on SAGD performance. Numerical simulation results for several cases of reservoir heterogeneity will be analyzed using a semi-analytical equation developed by Azom et al. that modifies the fundamental equation for SAGD performance by Butler.

Using SISIM, a geostatiscal reservoir building software, several base correlations were modeled, each correlation representing a given set of lens parameters and dimensions. The numerous realizations produced from each correlation were simulated using CMG STARS and a relationship between the heterogenic properties and adherence to Azom's model has been developed.

Our results show that naturally occurring low permeability barriers caused the steam chamber to have a shape quite different from that assumed in the literature for proxy model development and severally limited the growth of the steam chamber. As expected, variations in permeability more significantly impacted the steam chamber than corresponding thermal conductivity variations. Modifications to the semi-analytical model are required to make it a viable proxy model for fast SAGD simulations/history matching.