Heavy oil recovery by VAPEX appears to be a promising IOR technique as it uses less energy than SAGD and, if CO2 is injected, can also provide a means of disposing of excess CO2 in the subsurface. Nonetheless field application of this process has been limited due to concerns that favourable laboratory recoveries may not scale up to the field. In particular previous laboratory studies of VAPEX in porous media have obtained significantly higher production rates than predicted either by analytic models derived from Hele-Shaw experiments or numerical simulations. The discrepancy between experiment and models has been explained by assuming greater mixing between vapour and oil than would be expected from molecular diffusion. Justifications for this increase include convective dispersion, an increased surface area due to the formation of oil
films on sand grains, imbibition of oil into those films and a greater dependence on drainage height. Convective dispersion seems to be the most plausible mechanism.
This paper investigates the role of convective dispersion on oil recovery by VAPEX using a combination of well characterized laboratory experiments and numerical simulation. A first contact miscible fluid system was used so that all mechanisms contributing to increased-mixing apart from convective dispersion were eliminated. Longitudinal and transverse dispersion coefficients were measured experimentally as a function of flow-rate and viscosity ratio. Vapex drainage experiments were then performed over a range of injection rates.
The laboratory measurements of oil drainage rate were compared with those predicted by the Butler-Mokrys analytical model and numerical simulation using either molecular diffusion or convective dispersion. Using measured convective dispersion improved prediction of oil drainage rate by 50%.
The numerical model was then used to investigate the impact of rate (through viscous to gravity ratio and Peclet number), well separation and reservoir geometry on recovery.
Given the enormous capital costs, operating expenses, flue gas emissions, water consumption and handling conducted in thermal in situ bitumen recovery processes, improving overall efficiency by lowering energy requirements and environmental impact of these production techniques is a priority. Steam Assisted Gravity Drainage (SAGD) is a common thermal technique used in Athabasca reservoirs. Although SAGD is effective at producing bitumen, its energy efficiency can be poor due to enormous heat losses on the surface and in the wellbore. Given current attention to carbon dioxide emissions and water handling, there is a need to design and implement Reduced Emissions to Atmosphere Recovery (REAR) processes for heavy oil and bitumen extraction. One alternative is to generate steam in situ by in situ combustion (ISC) by injecting air or oxygen into the formation thus reducing or even avoiding transfer heat losses. In ISC, an energy generating oxidation zone propagates within the formation and generates heat which enables in situ steam generation from formation and injected water within the reservoir. In this research, design and optimization of hybrid in situ steam generation recovery processes are examined by using advanced three-dimensional reactive thermal reservoir simulation. Hybrid techniques combine the advantages of both ex situ steam and in situ steam generation processes in that it raises overall energy efficiency, lowers natural gas consumption as fuel, reduces overall gas emissions as well as water usage to generate steam, all on a per unit oil basis. The research here identifies steam-air based hybrid processes that use roughly 70% of the energy of conventional SAGD to recover the same amount of oil with substantial reduction of flue gas emissions and water use as viable REAR processes worthy of scaled physical model and potentially field testing.
Electrical heating for heavy-oil recovery is not a new idea but commercialization and wider application of this technique require detailed analyses for determination of optimal application conditions. In this study, applicability of electrical heating for heavy-oil recovery from two heavy-oil fields in Turkey (Bati Raman and Camurlu) was tested experimentally and numerically. The physical and chemical properties of the oil samples for the two fields were compiled and measured. Then, core samples were exposed to electrical heating and oil recovery performances by the retort technique were determined for different conditions. Experiments with and without using iron powder were analyzed and in-situ viscosity reduction during the heating process was determined through a history matching process using the simulation of the laboratory experiments. Experimentally obtained oil recovery and temperature distributions were used in this history matching exercise. Iron powder addition to oil samples causes a decrease in the polar components of oil and the viscosity of oil can strongly be influenced by the magnetic fields created by iron powders. Therefore, three different iron powder types at three different doses were tested to observe their impact on oil recovery. Experimental observations showed that viscosity reductions were accomplished as 88% and 63% for Bati Raman and Camurlu crude oils, respectively, after 0.5% Fe addition, which was determined as the optimum type and dose for both crude oil samples. Different parameters (thermal diffusion coefficients, oil viscosity, and relative permeabilities) that are needed in numerical modeling as data were determined through experimentally validated numerical modeling study. Furthermore, field scale recovery was tested numerically using the parameters obtained from laboratory scale experimental and numerical modeling results. The power of the system, operation period and the number of heaters were optimized. Economic evaluation done using the field scale numerical modeling study showed that the production of one barrel petroleum costs about 5 USD and at the end of 70 days, 320 barrels petroleum can be produced. When 0.5% Fe is added, oil production increased to 440 barrels for the same operational time period.
As the world's traditional oil and gas reserves decline, the industry is challenged to produce from unconventional sources. Heavy oil is found in different parts of the world and could be an answer to the demand for energy. However, heavy oil is highly viscous and traditional methods are not sufficient to produce these wells.
One option is to inject fluid such as steam to decrease the viscosity, making it feasible to produce the heavy-oil reserves. However, the steam heats the casing and the cement sheath in addition to the reservoir of heavy oil. The increase in temperature is high and imposes considerable thermal stress on the casing and the cement sheath. In many wells, the upperhole section is unconsolidated, posing higher risk to the cement sheath when subjected to stresses.
If the cement sheath is unable to withstand the stresses, it could be damaged and fail to provide zonal isolation. The cracks and microannulus in the cement sheath can act as a pathway for the steam to escape. This could considerably reduce the recovery of heavy oil while posing health, safety, and environmental challenges.
The design procedures necessary for evaluating the properties needed in the cement sheath to help withstand thermal stresses are discussed in this paper. Procedures to improve cement slurry placement are also presented. Additionally, methods to reduce heat losses in the upperhole section as well as reduce temperature stresses while optimizing the overall well-construction for heavy-oil recovery are also discussed.
This work should aid in the construction of wells that will contain injected fluids such as steam in the recovery of heavy oil. The cementing procedures discussed in this paper should help improve heavy-oil recovery as well as health, safety, and the environment.
Caplan, Mark (Athabasca Oil Sands Corp) | Heron, Caroline Andrea (Athabasca Oil Sands Corp) | Sullivan, Laura (Athabasca Oil Sands Corp) | Herle, Emeline (Athabasca Oil Sands Corp) | Keith, Jesse (Athabasca Oil Sands Corp) | Bernal, Andrea (Athabasca Oil Sands Corp) | Atkinson, Ian Kenneth (Dogtooth Investments Ltd)
The depositional setting of the McMurray Formation within the main Athabasca fairway has been extensively studied by industry and is well documented in the literature. Much crown land in this easternmost part of the Athabasca Oil Sands Area (AOSA) is currently being drilled and geologically characterised with the aim of in-situ thermal extraction methods, such as SAGD. Reservoirs in this region consist of tidally-influenced channel sands and open estuarine tidal sand bars. There are, however, new plays being discovered in the northwestern part of the AOSA that represent strikingly different depositional environments. Athabasca Oil Sands Corp. (AOSC) holds extensive oil sands assets in this western region of AOSA, and has discovered thick, good quality bitumen pay within the McMurray Formation.
Depositional environments of the McMurray Formation in this region contrast significantly to those reservoirs located within the main fairway to the east. This paper will describe the depositional environment, the building of a numerical simulation model to represent this reservoir, and the results of simulation studies predicting the performance of SAGD behaviour in this particular depositional setting.
A number of vertically-oriented heavy oil depletion experiments have been conducted in recent years in an attempt to investigate the impact of gravitational forces on gas evolution during solution gas drive. Although some experimental result indirectly suggest the occurrence of gas migration during these tests (especially at slow depletion rates), a major limitation of such an interpretation is the difficulty in visualising the process in reservoir rock samples. In contrast, experimental observations using transparent glass models have proved invaluable in this context and provide a sound physical basis for modelling gravitational gas migration in gas-oil systems. The experimental observations often exhibit somewhat contradictory trends however - some studies showing dispersed gas migration, whilst others describe fingered, channelised flow - and, to date, there appears to have been little systematic effort towards modelling the wide range of behaviours seen in or inferred from laboratory tests.
To this end, we present a new pore network simulator that is capable of modelling the time-dependent migration of growing gas structures. Multiple pore filling events are modelled dynamically with interface tracking allowing the full range of migratory behaviours to be reproduced, including braided migration and discontinuous dispersed flow. Simulation results are compared with experiments and are found to be in excellent agreement. Moreover, simulation results clearly show that a number of network and fluid parameters interact in a rather complex manner and as a consequence, the competition between capillarity and buoyancy produce different gas evolution patterns during pressure depletion. The implications of evolution regime on recovery from heavy oil systems undergoing depressurisation are extensively discussed.
Metering of bitumen produced by Steam-Assisted Gravity Drainage (SAGD) induces many issues arising from high operating temperatures (150-200 C), steam presence in the gas phase, foaming, emulsion and small density differences between bitumen and produced water. Nucleonic technology could be well-suited for this environment especially if the temperature issue can be properly handled. A multiphase meter (MFM) utilizing a multi-energy gamma ray (nuclear fraction) meter associated with a Venturi can potentially handle these operating constraints and replace separation devices for permanent or periodic well testing, providing accurate monitoring and optimization of oil, water, gas and steam production.
Following a 2008 field trial planned at a Canadian SAGD site, this paper will present specific strengths of the MFM with emphasis on its ability to meter correctly the liquid/gas phases depending of the calibration method and operating measurement range. Indeed, the overall methodology is a key element of the utilization of the MFM to ensure consistency with metering figures from well tests performed with a test separator equipped with accurate liquid and gas measurements and this field trial explores variations in process conditions to identify strengths and weaknesses of this MFM technology versus the operating envelope in standard operation (Non SAGD).
An entire study of the main parameters which could influence the measurement associated with this technology will be provided based on practical and simulated data and the impact of changes in each parameter will be evaluated. This paper will be a guideline for future users in the oil industry of this technology by providing an understanding of how to apply it to bitumen metering.
Multiphase flow meters (MFM) are more and more selected in Oil and Gas developments not only in production but also in periodic well testing, replacing test separators technology. The Heavy Oil business has been left more or less without large focus on research and development for MFM technology. This leads today, on the market, to few multiphase flow meters capable to handle this viscous fluid in cold production and high temperature fluids in thermal production. This statement was well documented previous SPE paper (Ref ).
Cold production of oil leads to degassing of the light species and the formation of a bubbly phase, sometimes called the "foamy oil?? effect. This bubbly phase is particularly observed with heavy oils, combining high viscosity and asphaltenes.
Presence and behavior of a foamy-oil effect appears to be critical to the cold production process. This process is not a well-understood production mechanism because a wide range of different petrophysical parameters and experimental factors interact in a rather complex way. Over the past few years, a number of efforts have been made in many institutions, in order to understand and model the solution gas drive mechanism in primary heavy oil recovery. Conventional simulations are not reliable for prediction forecast purposes. The reason is often that conventional modeling requires relative permeabilities tables that are not universal, but depend at least on the depletion rate and possibly on other parameters.
In this paper we keep the conventional Darcy scale point of view and the Darcy law with relative permeabilities. The key difference however is that relative permeabilities are not fit to experiments but obtained through physically-motivated explicit formulas. These expressions or formulas are based on the analysis of the mechanism of gas phase flow based on the geometry of the bubbles and its consequences on their motion. The theory involves a prediction of the aspect ratio of the bubbles and their velocities. The aspect ratio of the bubbles depends on the characteristics of the porous media in terms of pore size distribution and is obtained based on the Invasion Percolation in Gradient theory.
The resulting model is analyzed and solved in two different ways. First we describe a new type of approximate solution assuming extremely slow degassing. A simple partial differential equation similar to a kinematic wave equation results. This approach is more powerful than the asymptotic expansion described in previous wirk of the authirs, as it allows for the stauration to exhibit gradients and even shocks. Second, we solve the full set of Darcy-scale equations by way of a numerical solution, based on a version of the IMPES method based on previous similar numerical approaches. We show comparisons between the two solutions. We discuss how the formation of strong gradients of the gas phase saturation depends on gravity and viscosity.
Meher, Rajendra Kumar (Oil & Natural Gas Corp. Ltd.) | Suyan, Kalyan Mal (Oil & Natural Gas Corp. Ltd.) | Dasgupta, Debasish (Oil & Natural Gas Corp. Ltd.) | Deodhar, S. (Oil & Natural Gas Corp. Ltd.) | Sharma, Vinod (Oil & Natural Gas Corp. Ltd.) | Jain, Vinay Kumar (Oil & Natural Gas Corp. Ltd.)
Cementation of In-situ combustion (ISC) wells is a challenging affair as wells are often associated with weak and unconsolidated formation, nevertheless cement rise upto surface is desired to prevent casing failure. Furthermore the cement sheath is also required to withstand extreme stresses due to high temperature cycling experienced during in-situ combustion process.
In heavy oil fields of western India, due to the problem of inadequate placement time and flash setting when in contact with portland cement, the portland cement-silica blends were used for cementation of ISC wells instead of alumina cement blends. But this resulted in insufficient cement rise due to losses during cementation and the set cement failed to contain the strength and permeability in course of ISC process causing charging of sub-surface shallower layers.
For mitigating these problems, non-alumina based thermally stable lightweight lead slurry and a ductile high temperature resistance tail slurry have been developed and implemented for cementation of ISC wells, the details of which alongwith successful case histories are presented in this paper.
In the formulated thermally stable slurries there was neither reduction in strength nor increase in permeability even after thermal cycling upto 6500C. The lightweight slurry composition (S.G.1.60) reduced the hydrostatic head to effect cement rise upto surface. Since these formulations are devoid of alumina cement, all the associated field problems were totally eliminated. Superior cement bondage in comparison to earlier results confirmed the successful field validation.
This approach and the development is a unique solution of the problems in cementation of ISC wells, making it suitable for use as an effective alternative to earlier practices. Field implementation of this development has successfully arrested charging of shallower zones which was endangering the ISC process in fields of western India.
A comparative risk assessment was conducted to evaluate the risk associated with a Steam Assisted Gravity Drainage (SAGD) well blowout. The main comparison was between an isolated (double barrier) completion and an open (single barrier) completion used in conjunction with an effective blowout response plan. The target application was a SAGD pilot project in the Orinoco Belt in Venezuela.
The overall approach for the risk assessment included the investigation of the blowout flowing potential of the SAGD wells pair through reservoir modelling, the estimation of the probability of a blowout using fault-tree analysis, and the evaluation of the possible consequences (life safety, environmental and economic) of such blowout using various quantitative consequence models. Details of this approach are discussed in this paper, along with the results specific to the target application.
Results of this work can provide guidance for similar operations where decisions regarding completion options and blowout response plans are required. One key result was that, for this specific SAGD pilot project, a blowout response plan must be able to reduce the blowout duration substantially (from 3 days to 1 day for environmental risk, and from 3 days to 2 hours for economic risk) for the environmental and economical risks associated with a open completion to be comparable to those of an isolated completion.