bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Characterization and Monitoring of Cold and Thermal Heavy Oil Production Using Multi-Transient EM
Authors: Engelmark Folke 
Published: October 2008

Abstract
Heavy oil reservoirs are typically not possible to characterize or monitor using seismic methods, since the key acoustic properties of heavy oil namely density and bulk modulus are too similar to those of water. Multi-transient EM (MTEM) is a time-domain dipole – dipole galvanic resistivity mapping technology ideally suited to estimate in situ reserves of heavy oil as well as monitoring of cold and thermal production of heavy oil. All aspects of MTEM data acquisition have been optimized to achieve a sufficiently dense surface sampling in relation to the target depth, and to reach the necessary signal to noise (S/N) at target depth in the shortest time possible with a given source strength. The spatial resolution is sufficient to characterize the total recoverable reserves within a planned Steam Assisted Gravity Drainage (SAGD) project, or within a volume affected by Cyclic Steam Stimulation (CSS), also known as "huff and puff' production. Repeatability of EM data is excellent facilitating monitoring of subtle resistivity changes with good spatial resolution.
Several factors affect the resistivity during the monitoring phase. The increased temperature will lower the resistivity by up to 85 % and the changes in resistivity due to changes in water saturation are described by the Archie equation (Archie, 1942). The salinity of the pore water will be diluted when steam condenses to water resulting in a resistivity increase. In addition to these factors, the reservoir also suffers dissolution of grain cement and loss of some of the original mineral volume. At the same time the reservoir expands due to the increased fluid pressure and concomitant reduction in vertical effective stress. This leads to further increases in porosity and permeability, hence also to decreased resistivity and weakening of the bulk and shear moduli affecting the seismic response.
Ideally a feasibility study for EM monitoring should be performed based on the results generated by a reservoir simulator, where the dynamic changes in the key parameters: temperature, salinity and the saturations of water, oil, hydrocarbon gas and live steam are tracked for every grid cell over time. This information can then be transformed into resistivity for each grid cell and the EM response from the steam chamber can be modeled at different time steps throughout the planned lifespan of the project. Currently, reservoir simulators cannot incorporate dynamic changes in porosity and permeability that are observed as permanent reductions of the elastic moduli and also reduced resistivity. It is necessary to better understand this so called formation damage to fully describe the evolution of the steam chamber.
Case Study in Venezuela: Performance of Multiphase Meter in Extra Heavy Oil
Authors: Marin Ana , Bornia Onerazan , Pinguet Bruno 
Published: October 2008

Abstract
The objective is to present accurately the performance of the combination of a venturi and multi energy gamma ray in a case study in Venezuela. The focus will be on practical information, knowledge sharing to overcome all classical problems due to fluid behavior met by multiphase metering device in extra heavy oil including classical separator.
Heavy and Extra-Heavy Oil represents more than 50% of the worldwide oil reserves, and large efforts have been spent to overcome difficulties related to this kind of oil production. Venezuela has pone of the largest reserve of HO and EHO with more than currently 1.5 trillion of oil in place. Different set of technologies and methodologies have been used to overcome the technical production and monitoring challenges in these lifted or pumped wells.
Petroleos de Venezuela (PDVSA) at the opposite of Canada companies is currently producing most of the Heavy Oil from cold and therefore non thermal production methods due to historical reasons. Recently, Orocual field in Monagas Northern (Venezuela) was put in production a cluster with extra heavy oil reaching gravity from 8.6 to 11 API and with a viscosity range from 6 Pa.s to more than 20 Pa.s at line conditions. As per fact, this new production cluster did not have any data, and PDVSA could only use conventional storage tanks to try to estimate the liquid flow rate with no possibility to be able to get the gas production because no separator were able to work in these conditions.
However, it was essential to PDVSA in this early phase of the development to review the performance of the field and get access to the oil, water and gas flow rates. In these challenging conditions, and after trying other multiphase meters said to work in Extra Heavy Oil, PDVSA found that the only solution was Venturi - multi energy gamma ray combination.
This multiphase technology broke the extra heavy oil paradigm related to multiphase technology to measure flow rates accurately and a comparative test were capable to demonstrate when it was possible from a reference point of view that the overall uncertainty of the entire system (Venturi-Tank) was better than 2%. This extended the new multiphase technology operating envelope for PDVSA from Gas to Extra Heavy Oil and provided a unique solution and the capability to monitor and optimize in real-time the production in this field.
Numerical Simulation in Steam Injection Process by a Mechanistic Approach
Authors: de Souza J. C. , Campos W. , Lopes D. , Moura L. S. S. 
Published: October 2008

Abstract
This work describes the development of a hydrodynamic and heat transfer mechanistic model for steam flow in a steam injection process. The problem of two-phase steam flow in pipelines and wellbores has been solved recently by using available empirical correlations from the petroleum and nuclear industry by Lopes (1986) and Moura (1991). Despite the good performance achieved by the empirical approach, mechanistic models developed by Ansari (1994), Hasan (1995), Gomez (2000) and Kaya (2001) supports the importance of using the mechanistic approach for the steam flow problem in injection systems. In this study, the methodology to solve the problem consists in the application of a numerical method to the governing equations of steam flow. A marching algorithm is used to determine the distribution of pressure and temperature along the pipelines and wellbores. A computer code has been formulated to get numerical results. These results are compared to results of the main models found in the literature. Finally, when compared to available field data, the mechanistic model for steam flow gives better results than empirical correlations.
Increasing Oil Recovery from Heavy Oil Waterfloods
Authors: Brice Bradley W. , Renouf G. 
Published: October 2008

Abstract
A statistical study of 166 western Canadian waterfloods recovering heavy and medium gravity oils revealed new findings about best operating practices for heavy oil waterflooding. In classical light oil waterflooding, operators are advised to start waterflooding early and maintain the voidage replacement ratio (VRR) at 1. The study, however, produced surprising results for 2 parameters − among the 120 reservoir and operating parameters investigated − that ran counter to the recommended practices of classical light waterflooding. Delaying the start of waterflooding until a certain fraction of the original oil in place was recovered was found to be beneficial. Secondly, varying the VRR was shown to correlate with increased ultimate recovery — periods of underinjection are needed, although a cumulative VRR of 1 should be maintained.
Ultimate recovery was correlated with the primary recovery factor at the start of the waterflood. No trends appeared when the full set of 166 waterfloods was inspected. However, when the dataset is analyzed by ranges of API, a "sweet spot" of improved ultimate recovery was observed in a very narrow window of oil recovery factor prior to the start of waterflooding. Graphs of each category showed this "sweet spot" window where improved recovery occurred. These categories were API ranges; as well as ranges of permeability*height/viscosity (kh/μ); and pattern development.
Also increases in ultimate recovery were observable when we examined graphs of ultimate recovery versus the fraction of injection volume that was underinjected — but again, only when the data was analyzed by the ranges. A certain period of injection when the VRR was less than 0.95 resulted in increased ultimate recoveries. However, it is important that this period of VRR &lt; 0.95 be offset with periods of increased VRR so that the cumulative VRR cycles around 1.0. Again, each range manifested a narrow "sweet spot" for where this increase in ultimate recovery occurred.
Ultra High-Temperature Solids-Free Insulating Packer Fluid for Oil and Gas Production, Steam Injection and Geothermal Wells
Authors: Ezell Ryan G. , Harrison Douglas J. 
Published: October 2008

Abstract
High-temperature production well design and equipment installation, particularly for deep petroleum reservoirs, geothermal wells, and steam injection applications, present a multitude of challenges for operators due to the elevated thermal environments that impart high temperatures to the produced fluid (e.g., steam, oil, gas, etc.). One of the foremost problems is the uncontrolled heat transfer to outer annuli and heat loss from the production tubing. This can be detrimental to the integrity of outer annuli, may reduce the well productivity and could contribute to the formation of gas hydrates. In order to efficiently produce, inject or flow these fluids through production conduits to other facilities, it is necessary to keep them thermally isolated to prevent severe reductions in flow rate and dramatic changes in pressure that lead to tubular failure. To avoid these problems, high-viscosity insulating packer fluids (IPFs) are employed to insulate production tubing from the exterior pipe and to provide the required hydrostatic force. Effective fluids have a low thermal conductivity and also remain viscosified to eliminate convective heat transfer. Until recently, the packer fluid options fell short of meeting these objectives at elevated temperatures [i.e., ≥ 250°F (121°C)] for extended durations.
Through the extensive investigation of multidisciplinary technologies, a superior-performing solids-free aqueous-based IPF was developed for applications in deep high-temperature environments. The novel system covers a broad density range and exhibits heat transfer between 0.12 – 0.16 BTU/hr ft°F. Ultra high-temperature static aging tests have shown superior gel integrity with no thermal thinning after exposure to temperatures in excess of 500°F (260°C). The utilization of nanotechnology and a system of intermolecular associating synthetic macromolecules allow for the formation of the superior gel structure. In addition to the ultra-high thermal stability, the fluids possess thixotropic flow properties, are hydrate inhibitive and are environmentally friendly by Gulf of Mexico (GOM) standards. This paper presents and discusses the laboratory data generated under simulated high-temperature well conditions.
A New Analytical Model for Conduction Heating during the SAGD Circulation Phase
Authors: Duong Anh N. , Tomberlin Timothy A. , Cyrot Martin 
Published: October 2008

AbstractThe initial steam chamber that developed during the circulation phase of a Steam Assisted Gravity Drainage (SAGD) process impacts the efficiency of bitumen recovery tremendously. The circulation phase, during which both horizontal injector and producer in a SAGD well pair are put under circulation, is designed to establish inter-well communication and create an initial steam chamber. It is desirable to know the mid-point temperatures between and along the horizontal well pair so that any development of the steam chamber can be predicted.This paper proposes a new analytical model to predict the temperature fronts and heating efficiency between and along the horizontal well pair during the SAGD circulation phase. By using the exponential integral solution for radial heating in a long cylinder and superposition in space for multi-heating sources, the proposed model can be used to predict these temperature profiles, provided that the steam temperatures or pressures are known during the circulation period.Knowing temperature profiles between and along the horizontal wells is of great importance when deciding how to design the circulation parameters, where to modify the process, and when to switch to the SAGD production phase in a timely manner. The results can be optimized under various operational conditions, wellbore profiles, tubing sizes, and convection flow effects.The proposed model is easy to use, provides quick results, and ideal for updating during operations. This model is also advantageous compared to numerical simulation because it reduces computational time if many well pairs are involved in the study, and models accurately any variation in distance between the wellbores. Generic data is used in this paper to illustrate the model application.
Considerations When Ranking Stochastically Modeled Oil Sands Resource Models for Mining Applications
Authors: Etris Edward L. (Ned) , Idris Yonnus , Hunter A. C. (Chris) 
Published: October 2008

Abstract
Traditional oil sands mining operations have used deterministic techniques to create a single resource model for mine planning. Stochastic modeling, commonly used for in situ oil sands evaluation, provides more realistic geology and allows for multiple realizations, which mining operations can use to assess the variability of recoverable bitumen volume estimates and develop mine plans accordingly. The existence of multiple realizations makes it possible to measure uncertainty, but eventually detailed mine planning will proceed based on a single realization. This paper discusses the processes of stochastic modeling and of determining the appropriate single realization for mine planning as applied to an oil sands mine currently in the planning stage (Fort Hills).
Geological models for mining operations have less uncertainty than models for in situ operations due to the much closer drill hole spacing and the better understood recovery process for mining, but the level of uncertainty is not zero. The same techniques that are currently being used to assess uncertainty for in situ oil sands leases can be applied to mining leases to quantify uncertainty for mine planning. In the case of Fort Hills, 100 realizations of ore grade were created using conditional simulation. Ranking solely by total bitumen in place was insufficient, so a new measure of heterogeneity related to vertical ore-waste changes was developed and is discussed in this paper. These two measures were combined to rank the realizations and to select mid, high, and low cases. The combined ranking resulted in ordering the realizations in a way that correlated with other measures of recoverable resource volumes, and lends support to the choice of the "mid" model (centrally located in the ranking) for use in detailed mine planning.
The conditional simulation for Fort Hills marks the first time that stochastic modeling has been applied to full field modeling and then used for mine planning in an oil sands mine. The ranking method, including the methodology for assessing mining heterogeneity, is new and heretofore unpublished, and is the ultimate topic for discussion in this paper.
An Approach for Characterization and Lumping of Plus Fractions of Heavy Oil
Authors: Rodríguez I. , Hamouda A. A. 
Published: October 2008

Abstract
Heavy Oil fluids contain large concentrations of high molecular weight components, hence large content of the plus fractions, such as C7+.
Different approaches have been developed to characterize the petroleum plus fractions to improve prediction of the pseudo-components properties by equations of state (EOS).
A method is developed, in this work, to split the plus fraction into single carbon numbers (SCN); generating the mole fraction and the respective molecular weight. The developed method is based on the relationships between three parameter gamma distribution (TPG), experimental mole fraction, molecular weight and single carbon number data obtained from literature and industrial contacts. TPG is used to fit the trend of the compositional analysis. The characterized mole distribution as function of single carbon number is generated by integrating the TPG between the limiting molecular weights (LMω). The limiting molecular weights are determined simultaneously during the integration process by fitting the characterized and experimental mole fractions.
The developed method is easy to use. In addition the approach is not dependent on fixed molecular weights assumption that only normal carbon numbers exist in the composition.
There are several correlations generated to predict physico-chemical properties as a function of SCN. Those correlations have been originally developed to work with light oil. The developed approach together along with some of the correlations is tested for heavy oil samples to identify the ranges where they can be applied. Two lumping schemes are used to group the single carbon numbers into pseudo-components. The properties for each pseudo-component, in this work, are used to predict PVT data, constant volume depletion, using Peng-Robinson equation of state, PVTP commercial simulator.
Electro-Thermal Dynamic Stripping ProcessIntegrating Environmentalism with Bitumen Production
Authors: McGee Bruce C. W. , McDonald Craig W. , Little Les 
Published: October 2008

Abstract
The Electro-Thermal Dynamic Stripping Process(ET-DSP™) was commercialized as an environmental remediation technology to remove volatile soil contaminants. After nearly ten years of use, it has been adapted for the thermal stimulation and recovery of bitumen from oil sand reservoirs. A proof of concept field pilot [McGee, 2008] in the McMurray formation was conducted in 2007 and was deemed to be successful. Using a tight well spacing, the pilot demonstrated the effective recovery of approximately 75% of the original bitumen in place. Sand production was minimal and the produced bitumen was emulsion free. An expanded field test is currently underway to establish commercial viability of the ET-DSP™ process as an in-situ recovery process. Validation and calibration of the computer simulation model from the initial pilot test is presented along with details of the expanded field test.
The Athabasca Oil Sands are well known to the public as open-pit mining or SAGD in-situ projects. Approximately two-thirds of the Athabasca Oil Sands resource base occurs at depths that are defined as either too deep to surface mine or too shallow for currently available in-situ techniques and concerns regarding environmental issues that arise from these methods have the potential to slow their development. The ET-DSP™ process represents an alternative in-situ recovery technology that delivers significant environmental advantages in addition to its ability to access bitumen reserves that otherwise would be not recoverable. With growing public expectations for reduced greenhouse gas emissions, reduced fresh water usage and improved management of waste water, as well as the accelerated reclamation of disturbed land and boreal forest, there are many drivers to support the commercial development of the ET-DSP™ technology.
Electromagnetic Heating Method To Improve Steam Assisted Gravity Drainage
Authors: Koolman M. , Huber N. , Diehl D. , Wacker B. 
Published: October 2008

Abstract
The paper describes an opportunity for improvement of the widely applied Steam Assisted Gravity Drainage (SAGD) process for in-situ production of bitumen from oil sands deposits. The technical concept aims at Electro Magnetic (EM-SAGD) heating methods assisting the process. Preliminary investigations were carried out to confirm the feasibility of various solutions and evaluate aspects of energy efficiency and environmental impact. This solution targets energy efficiency as well as reduced environmental impact.
Different electromagnetic methods have been studied. For sites with overburdens of more than 30m, the inductive method has been found to be the most reasonable in terms of technical and economical feasibility. To evaluate the lifetime efficiency, a reservoir simulator has been coupled to a finite element program, in order to implement the effects of alternating current losses. Different standard cases of thick, shallow and thin reservoir conditions have been simulated in an integrated way of investigation to compare standard SAGD and EM-SAGD. The higher effort of additional electrical heating for EM-SAGD can be justified by lower cost of steam, less amount of water usage and treatment but basically by a higher return from increased bitumen production. In most cases, an earlier production start and a higher recovery rate can be obtained.
The proposed solution may contribute a significant enhanced oil recovery at specifically less energy consumption, leading to less impact to the environment in terms of green house emissions and water usage.
Passive Seismic Data Management and Processing to Monitor Heavy Oil Steaming Operations
Authors: Bailey J. R. , Smith R. J. , Keith C. M. , Searles K. H. , Wang L. 
Published: October 2008

Abstract
Cyclic Steam Stimulation (CSS) is a cost-effective means to produce heavy oil at the Cold Lake field in Alberta, Canada. The high viscosity of bitumen is the main obstacle to economic production, but the bitumen viscosity decreases significantly with temperature. Steam is injected at fracturing conditions, resulting in complex interactions of reservoir expansion (dilation) and contraction (recompaction) that propagate stress and strain fields in the overburden.
The mechanical loads on wells resulting from this production process are an important design consideration. To enhance operational integrity, a dedicated passive seismic monitoring well is installed on new development pads to provide early detection of casing failures and possible fracturing of the formation overburden. There is now an installed base of almost 90 such acoustic monitoring wells in the operator's field. With data acquisition of 15 to 30 geophones per system, recording continuously at 2000 or 3000 samples per second, the data management issues for this monitoring network are challenging.
Several classes of acoustic events have been identified, including those due to casing failure, formation heave, near-wellbore cement cracking, and production rod pump background noise, in addition to "Continuous Microseismic Radiation" (CMR) that resembles harmonic tremors. Most casing failures are detected by observation of singular events. The detection of fracturing of the overburden, which may include the presence of bitumen and/or produced water that has migrated out of zone, is a more complex process that requires distinguishing shear events and CMR events from normal formation heave and other environmental noise.
The operator has stewarded the development of a cost-effective system that includes local pad data acquisition, uploading of selected data to a server with data archiving facilities, and downloading data to dedicated analysts. This paper will present a summary of the data management and processing technologies developed to address the challenge of managing this data-intensive problem.
Fig. 1 CSS is a three-step process consisting of injection at fracturing conditions, soak, and production.